JP2013509300A - Cryogenic system for removing acid gases from hydrocarbon gas streams by removing hydrogen sulfide - Google Patents

Abstract

  A system for removing acid gas from a raw gas stream, including an acid gas removal system (AGRS) and a sulfur component removal system (SCRS). An acid gas removal system receives the sour gas stream and separates it into an overhead gas stream composed primarily of methane and a bottom acid gas stream composed primarily of carbon dioxide. The sulfur component removal system is installed either upstream or downstream of the acid gas removal system. The SCRS receives the gas stream and generally separates the gas stream into a first fluid stream that includes hydrogen sulfide and a second fluid stream that includes carbon dioxide. If SCRS is upstream of AGRS, the second fluid stream also contains mainly methane. When SCRS is downstream of AGRS, the second fluid stream is primarily carbon dioxide. Various types of sulfur component removal systems can be utilized.

Description

CROSS REFERENCE TO RELATED APPLICATIONS This application is filed on Nov. 2, 2009, and is incorporated by reference herein in its entirety to remove acid gases from a hydrocarbon gas stream by removal of hydrogen sulfide. Claims to US Provisional Patent Application No. 61 / 257,277, entitled "Cryogenic System".

This section is intended to introduce various aspects of the present technology that may be related to exemplary embodiments of the present disclosure. This discussion is believed to help provide a framework to facilitate a better understanding of certain aspects of the present disclosure. Accordingly, it should be understood that this section should be read from this perspective and not necessarily as prior art approval.
The present invention relates to the field of fluid separation. More specifically, the present invention relates to separating both hydrogen sulfide and other acid gases from a hydrocarbon fluid stream.

Production of hydrocarbons from the reservoir is often accompanied by accidental production of non-hydrocarbon gases. Such gases include pollutants such as hydrogen sulfide (H ₂ S) and carbon dioxide (CO ₂ ). When H ₂ S and CO ₂ are produced as part of a hydrocarbon gas stream (such as methane or ethane), this gas stream is often referred to as “sour gas”.
Sour gas is typically processed to remove CO ₂ , H ₂ S, and other contaminants before being sent downstream for further processing or sale. Removal of the acid gas produces a “sweetened” hydrocarbon gas stream. This sweetened stream can be used as an environmentally acceptable fuel or as a feed to a facility that produces liquids from chemicals or gases. By chilling the sweetened gas stream, liquefied natural gas, or LNG, can be formed.

This gas separation process causes problems with respect to the disposal of separated contaminants. In some cases, a rich acidic gas (consisting primarily of H ₂ S and CO ₂ ) is sent to a sulfur recovery unit (“SRU”). This SRU converts H ₂ S into benign elemental sulfur. However, in some regions (such as the Caspian Sea region), the market is limited, so the production of additional elemental sulfur is not desired. Millions of tons of sulfur are therefore stored in large, ground blocks in some parts of the world (most notably Canada and Kazakhstan).
While sulfur is stored on the ground, carbon dioxide associated with acid gases is often released to the atmosphere. However, the implementation of CO ₂ release may not be longing for. One proposal for minimizing CO ₂ emissions is a process called acid gas injection (“AGI”). AGI means that undesired sour gas is reinjected into the underground structure under pressure and sequestered for possible use at a later date. Alternatively, carbon dioxide is used to create artificial reservoir pressure to enhance oil recovery operations.

In order to promote AGI, it is desirable to have a gas treatment facility that effectively separates acidic gas components from hydrocarbon gases. However, economically separating pollutants from the desired hydrocarbons for “very sour” streams that are production streams containing approximately 15% or more than 20% CO ₂ and / or H ₂ S It can be particularly difficult to design, construct and operate facilities capable of Many natural gas reservoirs contain a relatively low percentage of hydrocarbons (eg less than 40%) and a high percentage of acid gases, mainly carbon dioxide, but hydrogen sulfide, carbonyl sulfide, carbon disulfide and various Also contains mercaptans. In these cases, it may be advantageous to employ cryogenic gas treatment.

  Cryogenic gas treatment is a distillation process often used for gas separation. Cryogenic gas separation produces a cooled overhead gas stream at moderate pressure (eg, 350-550 pounds per square inch gauge (psig)). In addition, liquefied acidic gas is produced as a “bottom” product. Because the liquefied acid gas is relatively dense, a hydrostatic head can be advantageously used in the AGI well to assist the injection process. This means that the energy required to pump the liquefied acidic gas into the structure is lower than the energy required to compress the low pressure acidic gas to the reservoir pressure. Fewer compressor and pump stages are required.

There are challenges associated with the cryogenic distillation of sour gas. If CO ₂ is present in the gas to be processed at a concentration of greater than approximately 5 mole percent at a total pressure of less than approximately 700 psig, this will freeze as a solid in a standard cryogenic distillation unit. When CO ₂ forms as a solid, it destroys the cryogenic distillation process. To circumvent this problem, the assignee has previously designed a variety of “Controlled Freeze Zone ™” (CFZ ™) processes. The CFZ (TM) process makes it possible to form a frozen CO ₂ particles in the opening portion of the distillation column, and then by capturing particles on melting tray well a tendency of carbon dioxide to form solid particles use. As a result, a clean methane stream (with any nitrogen or helium present in the raw gas) is produced at the top of the column, while a cold liquid CO ₂ / H ₂ S stream is produced at the bottom of the tower. The “Bulk preparative” distillation can be performed at pressures above about 700 psig without worrying about freezing of CO ₂ . However, the methane produced in the overhead will have at least a few percent of CO ₂ in it.

Certain embodiments of the CFZ ™ process and related equipment are described in US Pat. No. 4,533,372, US Pat. No. 4,923,493, US Pat. No. 5,062,270, US Pat. No. 5,120. , 338 and US Pat. No. 6,053,007.
As generally described in the above-mentioned US patents, the distillation column or column used for cryogenic gas treatment includes a lower distillation zone and an intermediate controlled freezing zone. Preferably an upper distillation zone is also included. By providing a portion of the column that is below the freezing point of carbon dioxide but at that pressure and above the boiling point of methane, the column operates to produce solid CO ₂ particles. Freezing range controlled, while to form frozen in CO ₂ (the solid) particles, it is preferable to operate at a temperature and pressure such as to allow vaporization of methane and other light hydrocarbon gases.

As the gas feed stream moves up the column, the frozen CO ₂ particles exit the feed stream and descend by gravity from the controlled freezing zone to the melting tray. The particles are liquefied in this melting tray. The carbon dioxide rich liquid stream then flows down from the melting tray to the lower distillation zone at the bottom of the column. The lower distillation zone does not substantially form any carbon dioxide solids, but is maintained at temperature and pressure so that dissolved methane is boiled off. In one aspect, the bottom acid gas stream is generated at 30 ° to 40 ° F.
In one embodiment, some or all of the frozen CO ₂ particles can be collected on a tray at the bottom of the freezing zone. The particles are then removed from the distillation column for further processing.
The controlled freezing zone includes a cryogenic liquid spray. This spray is a methane-rich liquid stream, known as “reflux”. As the gas stream of light hydrocarbon gas and entrained sour gas travels up through the column, the gas stream encounters a liquid spray. The cryogenic liquid spray assists the solid CO ₂ particles escape while evaporating the methane gas and flowing upwards through the column.

In the upper distillation zone, methane (or overhead gas) is captured and derived from a tube and sold or made available as fuel. In one aspect, the overhead methane stream is released at approximately -130 ° F. The overhead gas is partially liquefied by additional cooling, and this liquid can also return to the column as reflux. The liquid reflux usually flows through the tray or packing of the rectification section of the column and then is injected as a cryogenic spray into the spray section of the controlled freezing zone.
Methane produced in the upper distillation zone meets most standards for pipeline delivery. For example, methane produces less than 2 mole percent of CO _{2 in} the pipeline and H ₂ S if sufficient reflux is produced and / or there is a sufficient separation stage from the packing or tray in the upper distillation zone, and H ₂ S The standard 4 ppm can be satisfied. However, if the original raw gas stream contains hydrogen sulfide (or other sulfur-containing compound), these will end up with a liquid column bottom stream of carbon dioxide and hydrogen sulfide.

Hydrogen sulfide is a toxic gas heavier than air. This corrodes wells and surface equipment. When hydrogen sulfide contacts metal conduits and valves in the presence of water, iron sulfide corrosion can occur. Therefore, it is desirable to remove hydrogen sulfide and other sulfur components from the raw gas stream before it enters the cryogenic distillation column. This allows for a “sweeter” gas stream to be fed to the column. The CO ₂ produced by the cryogenic process is thus substantially free of H ₂ S and can be used, for example, for enhanced oil recovery.

A system is needed that reduces the content of H ₂ S and mercaptans from the natural raw gas stream prior to cryogenic distillation for sour gas removal. Alternatively, an additional process of extracting hydrogen sulfide from the cryogenic gas separation system and downstream of the acidic gas bottom stream from the CFZ column is required.

A system is provided for removing acid gases from a sour gas stream. In one embodiment, the system includes an acid gas removal system. The acid gas removal system utilizes a cryogenic distillation column that separates the sour gas stream into an overhead gas stream composed primarily of methane and a liquefied bottom acid gas stream composed primarily of carbon dioxide. Yes. The system also includes a sulfur component removal system. This sulfur component removal system is installed upstream of the acid gas removal system. The sulfur component removal system receives a raw gas stream and generally separates the raw gas stream into a fluid stream having hydrogen sulfide and a sour gas stream.
The sour gas stream preferably contains between about 4 ppm and 100 ppm sulfur components. Such components may be hydrogen sulfide, carbonyl sulfide, and various mercaptans.
The cryogenic acid gas removal system preferably includes a refrigeration system for cooling the sour gas stream prior to entering the distillation column. The cryogenic acid gas removal system is preferably a “CFZ” system in which the distillation column has a lower distillation zone and a controlled freezing zone in the middle. An intermediate controlled freezing zone, or “spray section”, receives a cryogenic liquid spray composed primarily of methane. This cold spray is a liquid reflux produced from the overhead loop downstream of the distillation column. Refrigeration equipment is provided downstream of the cryogenic distillation column to cool the overhead methane stream and return a portion of the overhead methane stream as cryogenic liquid reflux to the cryogenic distillation column.

It should be understood that other acid gas removal systems other than cryogenic distillation systems can be employed. For example, the acid gas removal system may be a physical solvent system that tends to reject H ₂ S as well as CO ₂ . This acid gas removal system may employ bulk fractionation.

Various types of sulfur component removal systems can be utilized. These include systems that employ physical solvents to separate sulfur-containing components from sour gas streams. These may also include the use of redox processes and so-called scavengers. They may also include a so-called “CrystaSulf” process.
In one aspect, the sulfur component removal system includes at least one solid adsorbent bed. At least one solid adsorbent bed adsorbs at least a portion of hydrogen sulfide while allowing methane gas and carbon dioxide to pass through as a sour gas stream. This solid adsorbent bed may, for example, (1) be made from a zeolitic material or (ii) contain at least one molecular sieve. The solid adsorbent bed may adsorb at least some water accidentally.
The at least one solid adsorption bed may be an adsorption dynamic separation bed. Alternatively, the at least one solid adsorbent bed can include at least three solid adsorbent beds, (i) the first of the at least three solid adsorbent beds is used to adsorb sulfur components; (Ii) a second of the at least three solid adsorbent beds is regenerated, and (iii) a third of the at least three solid adsorbent beds is of at least three solid adsorbent beds. Set aside for the first floor. The regeneration may be part of a thermal swing adsorption process, part of a pressure swing adsorption process, or a combination thereof.

In another embodiment, the sulfur component removal system employs a chemical solvent such as a selective amine. In this example, the sulfur component removal system preferably utilizes a plurality of co-current contact devices.
Other types of sulfur component removal systems may be utilized instead of or in addition to physical or chemical solvent systems. Such a system may include a redox system, the use of at least one solid adsorption bed, or the use of at least one absorption dynamic separation bed.
A separation system for removing acid gases from the sour gas stream is also provided herein. In this system, hydrogen sulfide and other sulfur-containing compounds are substantially removed downstream of the acid gas removal system. This system is designed to handle acid gas streams. The acid gas stream is obtained from a raw gas stream initially containing between about 4 ppm and 100 ppm sulfur components.

  In one embodiment, the system includes an acid gas removal system. The acid gas removal system receives a raw gas stream and separates the raw gas stream into an overhead gas stream composed primarily of methane and a bottom liquid acid gas stream composed primarily of carbon dioxide. Hydrogen sulfide will also be present in the bottom acid gas stream. The system also includes a sulfur component removal system. The sulfur component removal system is installed downstream of the acid gas removal system. The sulfur component removal system receives a bottom acid gas stream and generally separates the bottom acid gas stream into a carbon dioxide stream and another stream having primarily sulfur-containing compounds.

  The acid gas removal system is preferably a cryogenic acid gas removal system. The cryogenic acid gas removal system includes a distillation column for receiving a raw gas stream and a refrigeration system for cooling the raw gas stream prior to entering the distillation column. The cryogenic acid gas removal system is preferably a “CFZ” system in which the distillation column has a lower distillation zone and a controlled freezing zone in the middle. An intermediate controlled freezing zone, or “spray section”, receives a cryogenic liquid spray composed primarily of methane. This cold spray is a liquid reflux produced from the overhead loop downstream of the distillation column. Refrigeration equipment is provided downstream of the cryogenic distillation column to cool the overhead methane stream and return a portion of the overhead methane stream as a liquid reflux to the cryogenic distillation column.

Various types of sulfur component removal systems can be utilized. In one aspect, the sulfur component removal system includes at least one solid adsorbent bed. The at least one solid adsorbent bed adsorbs at least some sulfur-containing components from the bottom acidic gas stream and substantially passes carbon dioxide gas. The solid adsorption bed can use, for example, adsorption dynamic separation (AKS). This AKS bed may adsorb at least some carbon dioxide accidentally. In this example, the AKS sulfur component removal system also preferably includes a separator, such as a gravity separator. This gravity separator separates liquid heavy hydrocarbon components and hydrogen sulfide from, for example, gaseous CO ₂ .
Alternatively, the solid adsorbent bed may be an iron sponge to react directly with H ₂ S to remove it by forming iron sulfide.

  In another aspect, the sulfur component removal system includes an extractive distillation process. This extractive distillation process employs at least two solvent recovery columns. The first column receives a bottom acid gas stream, and the bottom acid gas stream is divided into a first fluid stream mainly composed of carbon dioxide and a second fluid stream mainly composed of a solvent and a sulfur-containing compound. And to separate.

  In order that the present invention may be better understood, specific illustrations, charts and / or flowcharts are appended hereto. It should be noted, however, that these figures are only illustrative of selected embodiments of the present invention and therefore should not be considered limiting in scope. This is because the present invention is amenable to other equally effective embodiments and applications.

FIG. 3 is a side view of an exemplary CFZ distillation column in one embodiment. The cooled raw gas stream is injected into a controlled freezing zone in the middle of the tower. It is a top view of the fusion tray in one embodiment. The melting tray is in the tower below the controlled freezing zone. 2B is a cross-sectional view of the melting tray of FIG. 2A along line 2B-2B. FIG. 2B is a cross-sectional view of the melting tray of FIG. 2A along line 2C-2C. FIG. 3 is an enlarged side view of a stripping tray in the lower distillation zone of the distillation column in one embodiment. FIG. 2 is a perspective view of a jet tray that can be used in either the lower distillation section or the upper distillation section of a distillation column in one embodiment. FIG. 4B is a side view of one opening in the jet tray of FIG. 4A. 2 is a side view of a controlled freezing zone in the middle of the distillation column of FIG. In this figure, two exemplary aperture adjustment plates have been added to the controlled freezing zone in the middle. 1 is a schematic diagram illustrating a gas processing facility for removing acid gas from a gas stream according to the present invention, in one embodiment. FIG. The gas treatment facility employs a solvent process upstream of the acid gas removal system. In one embodiment, a detailed schematic diagram of the solvent system of FIG. 6 is provided. The solvent system here is a physical solvent system that operates to contact the dehydrated gas stream to remove hydrogen sulfide. In an alternative embodiment, a detailed schematic diagram of the solvent system of FIG. 6 is provided. The solvent system here is a chemical solvent system that operates to contact the dehydrated gas stream to remove hydrogen sulfide. 1 is a schematic diagram illustrating a gas processing facility for removing acid gas from a gas stream according to the present invention, in one embodiment. FIG. In this arrangement, hydrogen sulfide is removed from the gas stream upstream of the acid gas removal system using a redox process. 1 is a schematic diagram illustrating a gas processing facility for removing acid gas from a gas stream according to the present invention, in one embodiment. FIG. In this arrangement, hydrogen sulfide is removed from the gas stream upstream of the acid gas removal system using a scavenger. 1 is a schematic diagram illustrating a gas processing facility for removing acid gas from a gas stream according to the present invention, in one embodiment. FIG. In this arrangement, hydrogen sulfide is removed from the gas stream upstream of the acid gas removal system using a CrystaSulf process. 1 is a schematic diagram illustrating a gas processing facility for removing acid gas from a gas stream according to the present invention, in one embodiment. FIG. In this arrangement, hydrogen sulfide is removed from the gas stream upstream of the acid gas removal system using a thermal swing adsorption system. 1 is a schematic diagram illustrating a gas processing facility for removing acid gas from a gas stream according to the present invention, in one embodiment. FIG. In this arrangement, hydrogen sulfide is removed from the gas stream upstream of the acid gas removal system using a pressure swing adsorption system. It is the schematic which shows the gas processing facility of this invention in another embodiment. In this arrangement, hydrogen sulfide is removed from the gas stream upstream of the acid gas removal system using an adsorption bed that utilizes adsorption dynamic separation. It is the schematic which shows the gas processing facility of this invention in another embodiment. In this arrangement, hydrogen sulfide is removed from the gas stream downstream of the acid gas removal system using an adsorbent bed that utilizes adsorptive dynamic separation. It is the schematic of the gas processing facility of this invention in another embodiment. In this arrangement, hydrogen sulfide is removed from the gas stream downstream of the acid gas removal system using an extractive distillation process. FIG. 15B is a detailed schematic diagram of a gas processing facility for the extractive distillation process of FIG. 15A.

Definitions As used herein, the term “hydrocarbon” refers to an organic compound that primarily includes, but is not exclusively, elemental hydrogen and carbon. Hydrocarbons generally fall into two classes: cyclic or closed hydrocarbon rings, including aliphatic or straight chain hydrocarbons, and cyclic terpenes. Examples of hydrocarbon-containing materials include any form of natural gas, oil, coal, and bitumen that can be used as a fuel or can be improved in quality into a fuel.

As used herein, the term “hydrocarbon fluid” refers to a hydrocarbon or hydrocarbon mixture that is a gas or a liquid. For example, the hydrocarbon fluid may comprise a hydrocarbon or hydrocarbon mixture that is a gas or liquid at forming, processing or ambient conditions (15 ° C. and 1 atm atmosphere). The hydrocarbon fluid may include, for example, oil, natural gas, coal seam methane, shale oil, pyrolysis oil, pyrolysis gas, pyrolysis products of coal, and other hydrocarbons that are in a gaseous or liquid state.
The term “mass transfer device” refers to any object that receives fluids to be contacted and directs them to other objects, such as via gravity flow. One non-limiting example is a tray for stripping specific ingredients. Grid filling is another example.

As used herein, the term “fluid” refers to gases, liquids, and combinations of gas and liquid, and combinations of gas and solid and combinations of liquid and solid.
As used herein, the term “condensable hydrocarbon” means a hydrocarbon that condenses at approximately 15 ° C. and 1 absolute atmospheric pressure. Hydrocarbons that can be condensed may include hydrocarbon mixtures having, for example, a carbon number greater than four.
As used herein, the term “heavy hydrocarbon” refers to a hydrocarbon having more than one carbon atom. Major examples include ethane, propane and butane. Other examples include pentane, aromatic, or diamondoid.

As used herein, the term “closed loop refrigeration system” refers to any refrigeration system in which an external working fluid, such as propane or ethylene, is used as a coolant to cool an overhead methane stream. means. This is in contrast to an “open loop refrigeration system” that is used as a fluid on which a portion of the overhead methane stream itself acts.
As used herein, the term “cocurrent contact device” or “cocurrent contactor” refers to (i) a flow of gas and (ii) another flow of solvent within the contact device. Means a vessel that receives these streams in such a way that the gas and solvent streams are in contact with each other while flowing in the same direction. Non-limiting examples include a discharge device and coalescer, or a static mixer plus deliquesizer.
By “non-absorbing gas” is meant a gas that is not significantly absorbed by the solvent during the gas sweetening process.
As used herein, the term “natural gas” refers to a multi-component gas obtained from a crude oil well (associated gas) or an underground gas-holding structure (non-associated gas). The composition and pressure of natural gas can be significantly different. A typical natural gas stream contains methane (C ₁ ) as a significant component. The natural gas stream may also contain ethane (C ₂ ), higher molecular weight hydrocarbons, and one or more acid gases. Natural gas can also contain trace contaminants such as water, nitrogen, wax, and crude oil.

As used herein, “acid gas” means any gas that is dissolved in water to produce an acidic solution. Non-limiting examples of acid gases include hydrogen sulfide (H ₂ S) and carbon dioxide (CO ₂ ). Sulfur compounds include carbon disulfide (CS ₂ ), carbonyl sulfide (COS), mercaptans, or mixtures thereof.

The term “liquid solvent” means a substantially liquid phase fluid that preferentially absorbs acid gas, thereby removing or “scrubping” at least a portion of the acid gas component from the gas stream. The gas stream may be a hydrocarbon gas stream or other gas stream, such as a gas stream with nitrogen.
"Sweetned gas stream" refers to a substantially gas phase fluid stream that had at least a portion of the removed acid gas component.
As used herein, the terms “lean” and “rich” are relative to removing a selected gas component from a gas stream with an absorbent liquid and are relative to the content of the selected gas component. Each degree is merely meant to be less or greater. The terms “lean” and “rich” respectively indicate that the absorbent liquid either does not have the selected gas component completely or cannot absorb the selected gas component any more. Does not necessarily indicate or require. In fact, the so-called “rich” absorbent liquid produced in the first contactor in a series of two or more contactors, as will be apparent from the rest of this specification, It is preferable to retain significantly or much of the absorption capacity. Conversely, a “lean” absorbent liquid is capable of significant absorption, but it should be understood that it can also retain trace concentrations of the gas component being removed.

  The term “raw gas stream” refers to a hydrocarbon fluid stream in which the fluid is predominantly in the gas phase and has not undergone a step to remove carbon dioxide, hydrogen sulfide, or other acidic components.

The term “sour gas stream” refers to a hydrocarbon fluid stream where the fluid is predominantly in the gas phase and contains at least 3 mole percent carbon dioxide and / or greater than 4 ppm hydrogen sulfide.
As used herein, the term “subsurface” refers to a formation that occurs below the surface of the soil.

DESCRIPTION OF SPECIFIC EMBODIMENTS FIG. 1 presents a schematic diagram of a cryogenic distillation column 100 that can be used in connection with the present invention in one embodiment. This cryogenic distillation column 100 may be referred to herein interchangeably with “cryogenic distillation column”, “column”, “CFZ column”, or just “tower”.
The cryogenic distillation column 100 of FIG. 1 receives an initial fluid stream 10. This fluid stream 10 is mainly composed of production gas. In general, the fluid stream represents a dry gas stream from a well tip or a group of well tips (not shown) and contains approximately 65% to approximately 95% methane. However, the fluid stream 10 may contain a lower percentage of methane, for example, a lower percentage of methane, approximately 30% to 65%, or even 20% to 40%.

Methane may be present along with other hydrocarbon gas trace elements such as ethane. In addition, trace amounts of helium and nitrogen may be present. In this application, the fluid stream 10 will also contain certain contaminants. These contaminants include acidic gases such as CO ₂ and H ₂ S.
The initial fluid stream 10 can be subjected to a post production pressure of about 600 pounds per square inch (psi). In some cases, the pressure of the initial fluid stream 10 can be up to approximately 750 psi, or even 1,000 psi.
The fluid stream 10 is typically cooled before entering the distillation column 100. A heat exchanger 150, such as a cylindrical multi-tube heat exchanger, is provided for the initial fluid stream 10. A refrigeration unit (not shown) reduces the initial fluid stream 10 to a low temperature from approximately −30 ° to −40 ° F. by providing a cooled fluid (eg, liquid propane, etc.) to the heat exchanger 150. Let The chilled fluid stream can then travel through expansion device 152. The expansion device 152 may be, for example, a Joule-Thompson (“J-T”) valve.

The expansion device 152 serves as an expander to achieve further cooling of the fluid stream 10. Preferably, partial liquefaction of the fluid stream 10 is achieved. A Joule-Thompson (or “J-T”) valve is preferred for gas feed streams that tend to form solids. The expansion device 152 minimizes heat loss in the supply tube and minimizes the possibility of clogging by solids when some components (such as CO ₂ or benzene) are dripped below their freezing point. In addition, it is preferably incorporated close to the cryogenic distillation column 100.
As an alternative to a J-T valve, the inflator device 152 may be a turbo inflator. Turbo expanders provide more cooling and create shaftwork sources for processes such as the refrigeration units described above. The heat exchanger 150 is a part of the refrigeration unit. In this way, the operator can minimize the total energy requirements of the distillation process. However, turbo expanders cannot handle particles that are frozen as well as JT valves.

In either case, the heat exchanger 150 and the expander device 152 convert the raw gas in the initial fluid stream 10 to the cooled fluid stream 12. The temperature of the chilled fluid stream 12 is preferably about -40 ° to -70 ° F. In one aspect, the cryogenic distillation column 100 operates at a pressure of approximately 550 psi and the chilled fluid stream 12 operates at about -62 ° F. Some gas phase may inevitably be taken into the chilled fluid stream 12, but under these conditions, the chilled fluid stream 12 is substantially in the liquid phase. Presumably, no solid formation occurs in the presence of CO ₂ .

  The CFZ cryogenic distillation column 100 is divided into three main sections. These are the lower distillation zone, or “stripping section” 106, the middle controlled freezing zone, or “spray section” 108, and the upper distillation zone, or “rectification section” 110. In the tower arrangement of FIG. 1, the chilled fluid stream 12 is introduced into the distillation tower 100 in a controlled freezing zone 108. However, the cooled fluid stream 12 may instead be introduced near the top of the lower distillation zone 106.

  Note that in the arrangement of FIG. 1, the lower distillation zone 106, the middle spray section 108, the upper distillation zone 110, and related components are contained within a single vessel 100. However, for offshore applications where tower 100 height and operational considerations may have to be taken into account, or for remote areas where limited transport is a concern, tower 110 May be divided into two separate pressure vessels (not shown). For example, the lower distillation zone 106 and the controlled freezing zone 108 may be placed in one container and the upper distillation zone 108 may be placed in another vessel. The external vessel is then used to interconnect the two containers.

In either embodiment, the temperature of the lower distillation zone 106 is higher than the supply temperature of the chilled fluid stream 12. The temperature of the lower distillation zone 106 is designed to be well above the boiling point of methane in the chilled fluid stream 12 at the column 100 operating pressure. In this way, methane is preferentially removed from heavier hydrocarbons and liquid acid gas components. Of course, those skilled in the art, the liquid of the distillation column 100 is a mixture, i.e., that this is the liquid at an intermediate temperature which is between the pure methane and pure CO ₂ means "boiling" I want you to understand. Furthermore, if heavier hydrocarbons are present in the mixture (such as ethane or propane), the boiling point of the mixture will increase. These factors provide design considerations for the operating temperature within the cryogenic distillation column 100.

In the lower distillation zone 106, CO ₂ and any other liquid phase fluid drop by gravity toward the bottom of the cryogenic distillation column 100. At the same time, methane and other gas phase fluids escape and rise upward toward the top of the tower 100. This separation is mainly accomplished via the density difference between the gas phase and the liquid phase. However, this separation process may be assisted by components inside the distillation column 100. As described below, these include a melting tray 130, a plurality of advantageously designed mass transfer devices 126, and an optional heater system 25. A side reboiler (see 173) can also be added to the lower distillation zone 106 to facilitate removal of methane.

Referring again to FIG. 1, the chilled fluid stream 12 can be introduced into the column 100 near the top of the lower distillation zone 106. Alternatively, it may be desirable to introduce the feed stream 12 to the controlled freezing zone 108 on the melting tray 130. The injection point of the chilled fluid stream 12 is a design issue determined primarily by the composition of the initial fluid stream 10.
If the temperature of the chilled fluid stream 12 is high enough that no solids can be expected (eg, greater than -70 ° F.), the chilled fluid stream 12 is a two-phase flash box type in the column 100 It may be preferred to inject directly into the lower distillation zone 106 via the device (or gas distributor) 124. Use of the flash box 124 serves to at least partially separate the two-phase gas / liquid mixture in the chilled fluid stream 12. The flash box 124 may be grooved so that the two-phase fluid strikes the adjustment plate in the flash box 124.

  If solids are expected due to low inlet temperature, the chilled fluid stream 12 may need to be partially separated in the container 173 before being fed to the column 100 as described above. In this case, the cooled feed stream 12 can be separated in the two phase separators 173 to minimize the possibility of solids blocking the column 100 inlet system and internal components. The gaseous gas leaves the phase separator 173 via the vessel inlet system 11 where it enters the column 100 via the inlet distributor 121. This gas then travels upward through the column 100. Liquid / solid slurry 13 is discharged from phase separator 173. Liquid / solid slurry is directed to column 100 and melt tray 130 via gas distributor 124. The liquid / solid slurry 13 can be fed to the column 100 by gravity or by a pump 175.

In either arrangement, that is, with or without the two phase separators 173, the cooled fluid stream 12 (or 11) enters the column 100. The liquid component leaves the flash box 124 and descends to a group of stripping trays 126 in the lower distillation zone 106. The stripping tray 126 includes a series of weirs 128 and downcomers 129. These are described more fully below in connection with FIG. The stripping tray 126, coupled with the warmer temperature of the lower distillation zone 106, acts to allow methane to escape from the solution. The produced gas carries methane extracted by boiling and any incorporated carbon dioxide molecules.
The gas advances further upward through the riser tube or exhaust tube 131 (shown in FIG. 2B) of the melting tray 130 and reaches the freezing zone 108. The exhaust tube 131 acts as a gas distributor for a uniform distribution throughout the freezing zone 108. The gas then contacts the cryogenic liquid from the spray header 120 to “freeze” the CO ₂ . In other words, the CO ₂ freezes and then returns as a precipitate or “snow” on the melting tray 130. The solid CO ₂ is then melted and flows down by gravity through the melting tray 130 in liquid form, from below it flows through the lower distillation zone 106.

  As will be discussed more fully below, the spray section 108 is a freezing zone in the middle of the cryogenic distillation column 100. A portion of the separated liquid / solid slurry 13 is introduced into the tower 100 immediately above the melting tray 130 by an alternate configuration in which the cooled fluid stream 12 separates in the vessel 173 before entering the tower 100. In this way, a liquid / solid mixture of acid gas and heavier hydrocarbon components will flow out of the distributor 121, and the solids and liquid will fall onto the melting tray 130.

The melting tray 130 is designed to receive liquid and solid materials, primarily CO ₂ and H ₂ S, by gravity from the intermediate controlled freezing zone 108. The melt tray 130 serves to warm the liquid and solid materials and guides them downward in the liquid form through the lower distillation zone 106 for further purification. The melting tray 130 collects and warms the solid / liquid mixture from the controlled freezing zone 108 of the liquid pool. Melting tray 130 discharges the gas stream back to controlled freezing zone 108 and provides sufficient heat transfer to melt solid CO ₂ , lower distillation zone or lower portion of column 100 below melting tray 130. Designed to facilitate drainage of liquid / slurry to distillation zone 106.

FIG. 2A provides a top view of the melting tray 130 in one embodiment. FIG. 2B provides a cross-sectional view of the melting tray 130 along the line BB of FIG. 2A. FIG. 2C shows a cross-sectional view of the melting tray 130 along the line CC. The melting tray 130 will be described with reference to these three figures collectively.
First, the melting tray 130 includes a bottom 134. The bottom 134 may be a substantially planar body. However, in the preferred embodiment shown in FIGS. 2A, 2B and 2C, the bottom 134 employs a substantially non-planar profile. This non-planar configuration increases the surface area for contacting liquids and solids placed on the melting tray 130 from the controlled freezing zone 108. This has the effect of increasing the heat transfer from the gas routed up from the lower distillation zone 106 of the column 100 to the liquid and the solid to be thawed. In one aspect, the bottom 134 is corrugated. In another aspect, the bottom 134 is substantially sinusoidal. This form of tray design is shown in FIG. 2B. It should be understood that the heat transfer area of the melting tray 130 can be increased by using other non-planar arrangements instead.

The melting tray bottom 134 is preferably inclined. This slope is clearly shown in the side view of FIG. 2C. Although most of the solids should be melted, the slope serves to ensure that any unmelted solids in the liquid mixture flow out of the melting tray 130 and from there into the lower distillation zone 106. Fulfill.
Looking at the view of FIG. 2C, it can be seen that the sump or channel 138 is in the center of the melting tray 130. The melt tray bottom 134 delivers a solid / liquid mixture by tilting inward toward the channel 138. The bottom 134 may be inclined in any manner to facilitate liquid withdrawal by gravity.

As described in US Pat. No. 4,533,372, the melting tray was referred to as the “exhaust tray”. This was due to the presence of a single ventilator for ventilation. The exhaust stack provided an opening through which gas can move up the exhaust stack tray. However, the presence of a single exhaust stack meant that all gas traveling upward through the exhaust stack tray had to exit through a single opening. On the other hand, in the melting tray 130 of FIGS. 2A, 2B, and 2C, a plurality of exhaust pipes 131 are provided. The use of the plurality of exhaust pipes 131 improves the gas distribution. This provides better heat / mass transfer in the controlled freezing zone 108 in the middle.
The exhaust tube 131 may have an arbitrary profile. For example, the exhaust stack 131 may be circular, square, or any other shape that allows the gas melting tray 130 to pass through. The exhaust stack 131 may also be narrow and extend upward into the controlled freezing zone 108. This allows an advantageous pressure drop to distribute the gas evenly as the gas rises to the frozen zone 108 under CFZ control. The exhaust stack 131 is preferably located at the top of the corrugated bottom 134 to provide an additional heat transfer area.

  The uppermost opening of the exhaust tube 131 is preferably covered with a door opening or cap 132. This minimizes the probability that a solid falling from the controlled freezing zone 108 can be avoided from falling on the melting tray 130. In FIGS. 2A, 2B and 2C, a cap 132 is seen on each of the exhaust stacks 131.

The melting tray 130 may also be designed to be equipped with a bubble cap. This bubble cap is defined as the convex entry / exit of the bottom portion 134 rising from the bottom surface of the melting tray 130. The bubble cap provides additional heat transfer to the CO ₂ rich liquid by further increasing the surface area of the melt tray 130. Using this design, proper liquid withdrawal, such as increased tilt angle, should be provided to ensure that the liquid is directed to the lower stripping tray 126.

Referring again to FIG. 1, the melt tray 130 can also be designed with an external liquid transfer system. This transfer system serves to ensure that all liquids are substantially free of solids and sufficient heat transfer is provided. The movement system first includes an extraction nozzle 136. In one embodiment, the draw nozzle 136 is in the draw reservoir or in the channel 138 (shown in FIG. 2C). Fluid collected in channel 138 is delivered to travel line 135. The flow through the movement line 135 can be controlled by a control valve 137 and a level controller “LC” (taken in FIG. 1). The fluid returns to lower distillation zone 106 via transfer line 135. If the liquid level is too high, the control valve 137 opens. If the level is too low, the control valve 137 is closed. If the operator chooses not to adopt the lower distillation zone 106 transfer system, the control valve 137 is closed and fluid is either directed directly to the mass transfer device or via the overflow downcomer 139 for stripping. To the “stripping tray” 126 below the melting tray 130.
Regardless of whether an external transfer system is used, the solid CO ₂ is warmed on the melting tray 130 and converted to a CO ₂ rich liquid. The melting tray 130 is heated from below by the gas from the lower distillation zone 106. Auxiliary heat may be applied to the melting tray 130 or just above the melting tray bottom 134 using various means such as the heater line 25. The heater line 25 facilitates thawing of solids by utilizing the thermal energy already available from the bottom reboiler 160.

The CO ₂ rich liquid is withdrawn from the melting tray 130 under liquid level control and introduced into the lower distillation zone 106 by gravity. As described, a plurality of stripping trays 126 are provided in the lower distillation zone 106 below the melting tray 130. The stripping tray 126 is preferably in a substantially parallel relationship with one tray over the other. Each of the stripping trays 126 may be positioned with a very slight inclination with a weir so that the liquid level is maintained on the tray. The fluid flows by gravity over each weir along each tray and then flows down to the next tray via the downcomer.
The stripping tray 126 can be variously arranged. The stripping tray 126 can be arranged in a generally horizontal relationship to form a cascading liquid stream that can be moved back and forth. However, the stripping tray 126 is preferably arranged to create a cascaded liquid flow that is divided by separate stripping trays along substantially the same horizontal plane. This is illustrated in the arrangement of FIG. 3, where the liquid flow is split at least once so that the liquid flows across separate trays and falls into two opposing downcomers 129.

  FIG. 3 provides a side view of the stripping tray 126 arrangement in one embodiment. Each of the stripping trays 126 receives fluid from above and collects them. Each stripping tray 126 preferably has a weir 128 that functions as a dam, thereby allowing a small pool of fluid to be collected on each of the stripping trays 126. The accumulation may be 1/2 to 1 inch, but any height may be employed. As the fluid falls from one tray 126 to the next lower tray 126, the weir 128 creates a draining effect. In one aspect, the stripping tray 126 is not inclined, but this falling effect is created through a higher weir 128 configuration. In this “contact area” of tray 126, the fluid comes into contact with a lighter, hydrocarbon-rich ascending gas that extracts methane from the orthogonally flowing liquid. The weir 128 acts to block the downcomer 129 dynamically, thereby preventing gas from bypassing through the downcomer 129 and helping further promote escape of the hydrocarbon gas.

  As the liquid moves downward through the lower distillation zone 106, the percentage of methane in the liquid becomes increasingly smaller. The degree of distillation depends on the number of trays 126 in the lower distillation zone 106. In the upper part of the lower distillation zone 106, the liquid methane content can be as high as 25 mole percent, while at the bottom of the stripping tray, the methane content can be as low as 0.04 mole percent. The methane content is rapidly flushed along the stripping tray 126 (or other mass transfer device). The number of mass transfer devices used in the lower distillation zone 106 is a matter of design choice based on the composition of the raw gas stream 10. However, only a few levels of stripping tray 126 are typically required to remove methane, for example, in liquefied acid gas to the desired level of 1% or less.

  A variety of individual stripping tray 126 configurations that facilitate methane escape may be employed. The stripping tray 126 may simply represent a panel having a sieve hole or bubble cap. However, a so-called “jet tray” may be employed under the melting tray to provide additional heat transfer to the fluid and prevent undesired blockage due to solids. Instead of trays, random or structured packing may be employed.

  FIG. 4A provides a top view of an exemplary jet tray 426 in one embodiment. FIG. 4B provides a cross-sectional view of the jet tab 422 from the jet tray 426. As shown, each jet tray 426 has a body 424 with a plurality of jet tabs 422 formed in the body 424. Each jet tab 422 includes a tilted tab member 428 that covers the opening 425. Accordingly, the jet tray 426 has a plurality of small openings 425.

  During operation, one or more jet trays 426 can be located in the lower distillation zone 106 and / or the upper distillation zone 110 of the column 100. The tray 426 can be arranged using a plurality of passages, such as the pattern of the stripping tray 126 of FIG. However, any tray or packing arrangement that facilitates escape of methane gas can be utilized. The fluid falls like a waterfall on each jet tray 426. The fluid then flows along the body 424. Tabs 422 are optimally oriented so that fluid moves quickly and efficiently over tray 426. An adjacent downcomer (not shown) may be provided to move liquid to the subsequent tray 426. Opening 425 also allows gas gases released during the fluid transfer process in lower distillation zone 106 to travel more efficiently upward into melt tray 130 and through exhaust stack 131. .

In one aspect, the tray (eg, tray 126 or 426, etc.) can be made from an anti-adhesive material, ie, a material that prevents the accumulation of solids. The use of anti-stick materials in certain processing equipment prevents the accumulation of corrosive metal particles, polymers, salts, hydrates, catalyst fines, or other chemical solid compounds. In the case of the cryogenic distillation column 100, the adherent material can be used in the trays 126 or 426 to limit the sticking of the CO ₂ solids. For example, a Teflon ™ coating can be applied to the surface of tray 126 or 426.
Alternatively, a physical design can be provided to ensure that CO ₂ does not begin to accumulate in solid form along the inner diameter of the column 100. In this regard, the jet tab 422 is oriented so that liquid is propelled along the wall of the column 100, thereby preventing solids from accumulating along the wall of the column 100 and providing excellent gas-liquid contact. Can be ensured.

In any of the tray arrangements, material separation occurs when the downward flowing liquid reaches the stripping tray 126. Methane gas escapes from the solution and moves upward in the form of a gas. However, CO ₂ remains largely in its liquid form because the temperature is generally low enough and the concentration is high enough to move down to the bottom of the lower distillation zone 106, although some CO ₂ will definitely vaporize during the process. The liquid then exits the cryogenic distillation column 100 from the outlet line as a bottom fluid stream 22.

  Upon exiting the distillation column 100, the bottom fluid stream 22 enters the reboiler 160. In FIG. 1, a reboiler 160 is a reaction kiln type container that provides re-boiled gas to the bottom of a stripping tray. A re-boiled gas line can be seen at 27. In addition, the reboiled gas can be delivered via the heater line 25 to provide supplemental heat to the melting tray 130. This auxiliary heat is controlled via a valve 165 and a temperature controller TC. Instead, by using a heat exchanger, such as a thermosiphon heat exchanger (not shown), the initial fluid stream 10 can be cooled to efficiently utilize energy. At this point, the liquid entering the reboiler 160 remains at a relatively low temperature, eg, approximately 30 ° to 40 ° F. The integrated heat of the initial fluid stream 10 allows the operator to warm and partially boil the cold bottom fluid stream 22 from the distillation column 100 while pre-cooling the production fluid stream 10. In this case, the fluid providing supplemental heat via line 25 is the return of the gas phase from reboiler 160.

  Under some conditions, it is expected that the melt tray 130 can operate without the heater line 25. In these cases, the melting tray 130 can be designed with an internal heating function, such as an electric heater. However, it is preferred to provide a thermal system that employs thermal energy available in the bottom fluid stream 22. The warm fluid in the heater line 25 is present in one embodiment at 30 ° to 40 ° F. and thus they contain relative thermal energy. Thus, in FIG. 1, it is shown that the warm gas flow in the heater line 25 is directed to the melting tray 130 via a heating coil (not shown) on the melting tray 130. Alternatively, the warm gas stream may be connected to the movement line 135.

In operation, the majority of the reboiled gas stream is introduced to the bottom of the column via line 27 above the bottom liquid level and at or below the last stripping tray 126. . As the reboiled gas turns upward through each tray 126, residual methane is removed from the liquid. This gas gets colder as it moves up the tower. By the time the gas flow from line 27 reaches the corrugated melt tray 130, the temperature can drop from approximately −20 ° F. to 0 ° F. However, the gas flow remains fairly warm compared to the molten solid on the melt tray 130 (possibly about −50 ° F. to −70 ° F.). This gas still has sufficient enthalpy to melt the solid CO ₂ when it comes into contact with the melting tray 130.

Returning to the reboiler 160 again, fluid in the bottom stream 24 exiting the reboiler 160 in liquid form may pass through the inflator valve 162. The inflator valve 162 reduces the bottom liquid product pressure and effectively provides a refrigeration effect. Accordingly, a cooled bottom stream 26 is provided. The CO ₂ rich liquid exiting the reboiler 160 can be pumped down the hole through one or more AGI wells (schematically seen at 250 in FIG. 1). In some situations, liquid CO ₂ can be pumped into a partially recovered oil reservoir as part of an enhanced oil recovery process. Thus, CO ₂ can be a miscible injection material. As an alternative, CO ₂ can also be used as a miscible flooding agent to enhance oil recovery.

  Referring again to the lower distillation zone 106 of the tower 100, the gas travels upward through the lower distillation zone 106 through the exhaust 131 of the melting tray 130 to the controlled freezing zone 108. The controlled freezing zone 108 is defined as an open chamber having a plurality of spray nozzles 122. As the gas moves upward through the controlled freezing zone 108, the temperature of the gas becomes very low. The gas contacts liquid methane (“reflux”) exiting the spray nozzle 122. Since this liquid methane is cooled by the external refrigeration unit including the heat exchanger 170, it is much cooler than the gas moving upward. In one arrangement, liquid methane exits the spray nozzle 122 at a temperature of about -120 ° F to -130 ° F. However, as the liquid methane evaporates, it absorbs heat from its surroundings, thereby reducing the temperature of the gas moving upwards. The vaporized methane also flows upward due to its density reduction (compared to liquid methane) and the pressure gradient in the distillation column 100.

  As the methane gas travels further up the cryogenic distillation column 100, they leave the intermediate controlled freezing zone 108 and enter the upper distillation zone 110. The gas continues to move upwards with other light gases that have escaped from the original cooled fluid stream 12. The combined hydrocarbon gas exits from the top of the cryogenic distillation column 100 to form an overhead methane stream 14.

  The hydrocarbon gas in the overhead methane stream 14 moves to the external refrigeration unit 170. In one aspect, the refrigeration unit 170 uses an ethylene coolant or other coolant that can cool the overhead methane stream 14 to temperatures as low as approximately −135 ° to −145 ° F. This serves to at least partially liquefy the overhead methane stream 14. The refrigerated methane stream 14 then travels to a reflux condenser or separation chamber 172.

A separation chamber 172 is used to separate the gas 16 from the liquid, sometimes referred to as “liquid reflux” 18. Gas 16 represents the lighter hydrocarbon gas from the original raw gas stream 10, primarily methane. Nitrogen and helium may also be present. Methane gas 16 is, of course, a “product” that will eventually be sought for capture and sold commercially, along with any traces of ethane. This non-liquefied portion of the overhead methane stream 14 can also be used for on-site fuel.
A portion of the overhead methane stream 14 exiting the refrigeration unit 170 is condensed. This part is the liquid reflux 18 separated in the separation chamber 172 and returned to the tower 100. By using the pump 19, the liquid reflux 18 can be moved back to the tower 100. Instead, a gravity feed of liquid reflux 18 is provided by incorporating a separation chamber 172 above the tower 100. This liquid reflux 18 will contain any carbon dioxide that has escaped from the upper distillation zone 110. However, most of the liquid reflux 18 is typically 95% or more of methane, along with nitrogen (if present, in the initial fluid stream 10) and traces of hydrogen sulfide (if present, also in the initial fluid stream 10). It is.

  In one cooling arrangement, overhead methane stream 14 is withdrawn via an open loop refrigeration system, such as the refrigeration system shown in FIG. 6 and described in connection with FIG. In this arrangement, the returned portion of the overhead methane stream used as liquid reflux 18 is cooled by removing the overhead methane stream 14 via a cross exchanger. This overhead methane stream 14 is then pressurized to approximately 1,000 psi to 1,400 psi and then cooled with ambient air and optionally an external propane coolant. This pressurization is then directed through an expander to further cool the cooled gas stream. By using a turbo expander, even more liquid as well as some shaftwork can be recovered. US Pat. No. 6,053,007 entitled “Process For Separating a Multi-Component Gas Stream Containing at Least One Freezable Component” describes cooling of an overhead methane stream, which is incorporated herein by reference in its entirety. It is.

  It should be understood here that the present invention is not limited by the cooling method for the overhead methane stream 14. It should also be understood that the degree of cooling between the refrigeration unit 170 and the initial refrigeration unit 150 may be different. In some cases, it may be desirable to operate the refrigeration unit 150 at a higher temperature, but then to more powerfully cool the overhead methane stream 14 in the refrigeration unit 170. Again, the present invention is not limited to these types of design choices.

Returning again to FIG. 1, the liquid reflux 18 is returned to the upper distillation zone 110. The liquid reflux 18 is then carried by gravity through one or more mass transfer devices 116 in the upper distillation zone 110. In one embodiment, the mass transfer device 116 is a rectification tray that provides a cascade of series of weirs 118 and downcomers 119, similar to the tray 126 described above.
As the fluid from the liquid reflux stream 18 moves downwardly through the rectification tray 116, additional methane is vaporized from the upper distillation zone 110. This methane gas becomes part of the gas product stream 16 by rejoining the overhead methane stream 14. However, the liquid phase remaining in the liquid reflux 18 falls on the collection tray 140. This inevitably causes the liquid reflux stream 18 to pick up a small percentage of hydrocarbons and residual acid gases that move upward from the controlled freezing zone 108. A liquid mixture of methane and carbon dioxide is collected in the collection tray 140.

  The collection tray 140 is preferably defined as a substantially planar body for collecting liquid. However, like the melting tray 130, the collection tray 140 also has one, preferably a plurality of exhaust stacks, for venting the gas coming from the controlled freezing zone 108. An arrangement of exhaust stacks and caps can be used, such as those presented in components 131 and 132 in FIGS. 2B and 2C. Exhaust tube 141 and cap 142 for collection tray 140 are shown in the enlarged view of FIG. 5 and are discussed further below.

It should be noted here that any H ₂ S present in the upper distillation zone 110 is preferred to be dissolved in the liquid rather than being dissolved in the gas at the processing temperature. In this respect, H ₂ S has a relatively low relative instability. By bringing more residual gas into contact with the liquid, the cryogenic distillation column 100 pushes the H ₂ S concentration down to the desired parts per million (ppm) limit, eg, 10 or even 4 ppm standards. As the fluid moves through the mass transfer device 116 in the upper distillation zone 110, H ₂ S comes into contact with the liquid methane and is withdrawn from the gas phase and becomes part of the liquid stream 20. From there, the H ₂ S moves downward in liquid form through the lower distillation zone 106 and exits the cryogenic distillation column 100 as part of the bottom liquefied bottom acidic gas stream 22. If little or no H ₂ S is present in the feed stream, or if H ₂ S is selectively removed in the upstream process, virtually no H ₂ S is present in the overhead gas. It will be.

In the cryogenic distillation column 100, the liquid captured in the collection tray 140 is drawn from the upper distillation zone 110 as a liquid stream 20. The liquid stream 20 is mainly composed of methane. In one embodiment, the liquid stream 20 is comprised of approximately 93 mole percent methane, 3% CO ₂ , 0.5% H ₂ S, and 3.5% N ₂ . At this point, the liquid stream 20 is approximately -125 ° F to -130 ° F. This is only slightly warmer than the liquid reflux stream 18. Liquid stream 20 is directed to reflux drum 174. The purpose of the reflux drum 174 is to provide surge capability for the pump 176. Upon exiting the reflux drum 174, a spray stream 21 is created. The spray stream 21 is pressurized by a pump 176 and second reintroduction into the cryogenic distillation column 100 is performed. In this example, the spray stream 21 is pumped into the intermediate controlled freezing zone 108 and discharged through the nozzle 122.

  Certain portions of the spray stream 21, particularly methane, vaporize and evaporate upon exiting the nozzle 122. From there, the methane rises through the controlled freezing zone 108, through the stack in the collection tray 140, and through the mass transfer device 116 in the upper distillation zone 110. The methane leaves the distillation column 100 as an overhead methane stream 14 and eventually becomes part of the commodity in the gas stream 16.

The spray stream 21 from the nozzle 122 also desublimates carbon dioxide from the gas phase. In this regard, CO ₂ first dissolved in liquid methane can enter the gas phase for a moment and move upward with the methane. However, since the temperature is low in the controlled freezing zone 108, any gaseous carbon dioxide rapidly becomes a nucleus, agglomerates into a solid phase, and “snow” begins to fall. This phenomenon is called desublimation. In this way, some CO ₂ never becomes liquid again until it hits the melting tray 130. This carbon dioxide falls as “snow” on the melting tray 130 and melts into the liquid phase. From there, the CO ₂ rich liquid falls down the mass transfer device or tray 126 in the lower distillation zone 106 together with the liquid CO ₂ from the cooled raw gas stream 12 as a waterfall. At that point, any remaining methane from the spray stream 21 of the nozzle 122 should rapidly escape as a gas. These gases move upward in the cryogenic distillation column 100 and enter the upper distillation zone 110 again.

It is desirable to bring as much of the cooled liquid as possible into contact with the gas moving up the tower 100. If the gas bypasses the spray stream 21 emanating from the nozzle 122, higher levels of CO ₂ can reach the upper distillation zone 110 of the column 100. In order to improve the efficiency of gas / liquid contact within the controlled freezing zone 108, a plurality of nozzles 122 having a designed configuration can be employed. Thus, several spray headers 120 that may be designed with multiple spray nozzles 122 rather than employing a single spray source at one or more levels with a reflux fluid stream 21. May be used. Thus, the configuration of the spray nozzle 122 has an effect on the heat and mass transfer that occurs within the controlled freezing zone 108. The nozzles themselves can also be designed to optimize the droplet size and the area distribution of these droplets.

  The assignee of the present invention has previously proposed various nozzle arrangements in co-pending International Patent Publication No. 2008/091316, which has an international filing date of November 20, 2007. That application and FIGS. 6A and 6B are incorporated herein by reference to teach the nozzle configuration. The nozzle seeks to ensure 360 ° coverage within the controlled freezing zone 108 and to provide excellent gas / liquid contact and heat / mass transfer. In this way, any gaseous carbon dioxide that moves upward through the cryogenic distillation column 100 is now cooled more effectively.

The use of multiple headers 120 and corresponding overlap nozzle 122 arrangements for perfect coverage also minimizes backmixing. In this respect, the complete application range prevents fine, low mass CO ₂ particles from returning to the distillation column 100 and entering the upper distillation zone 110 again. These particles are then remixed with methane and reenter the overhead methane stream 14 and are only recycled again.

The acid gas removal system described in connection with FIG. 1 is advantageous for producing a commercial methane product 16 that is substantially free of acid gas. Product 16 is preferably liquefied and is sent down the pipeline for sale. The liquefied gas product, sufficient reflux is produced, preferably meets 1-4 mole percent is a pipeline CO ₂ standard. Carbon dioxide and hydrogen sulfide are removed via bottom stream 22.
In some cases, there is a small amount of H ₂ S with a relatively large amount of CO ₂ in the raw initial fluid stream 10. In this case, it may be desirable to selectively remove H ₂ S before the cryogenic distillation column so that a “clean” liquid CO ₂ stream can be produced in the bottom stream 22. In this way, CO ₂ may be injected directly into the reservoir for enhanced oil recovery (“EOR”) operations. Accordingly, a system and method for removing a portion of the sulfur component that is produced with the initial fluid stream 10 before acid gas removal in a cryogenic distillation column such as column 100 is proposed herein. Yes.

Several H ₂ S selection processes for removing sulfur components from the gas stream have been proposed herein. Both aqueous and non-aqueous processes are described. These processes are known as any sulfhydryl compounds such as hydrogen sulfide (H ₂ S), and also known as mercaptans, and also known as thiols (R? SH), where R is a hydrocarbon group. It is preferred to remove organic sulfur compounds having a sulfhydryl (? SH) group.
The first method for removing sulfur components upstream of the acid gas removal system employs the use of a solvent. Certain solvents have an affinity for hydrogen sulfide and can be used to separate H ₂ S from methane. The solvent can be either a physical solvent or a chemical solvent.

FIG. 6 is a schematic diagram illustrating a gas processing facility 600 for removing acid gases from a gas stream in one embodiment. The gas processing facility 600 employs a solvent process upstream of the acid gas removal system. The acid gas removal system is indicated generally at 650 and the solvent process is indicated at block 605. The acid gas removal system 650 includes a separation vessel at block 100. Block 100 generally represents the controlled freezing zone tower 100 of FIG. However, block 100 can also represent any cryogenic distillation column, such as a bulk preparative column.
In FIG. 6, the product gas stream is shown at 612. Gas stream 612 begins with a hydrocarbon production activity that takes place in a reservoir generation region, or “field” 610. It should be understood that field 610 can represent any location where gaseous hydrocarbons are produced.
Field 610 may be on land, near the coast, or offshore. This field 610 may operate from the original reservoir pressure or may be subjected to enhanced recovery procedures. The systems and methods claimed herein are not limited to the type of field under development as long as they produce hydrocarbons mixed with hydrogen sulfide and carbon dioxide. The hydrocarbon will primarily contain methane but may also contain 2-10 mole percent ethane and other heavy hydrocarbons such as propane or even traces of butane and aromatic hydrocarbons.

The gas stream 612 is “raw”, which means that no acid gas removal process has been applied. The raw gas stream 612 may pass through a pipeline, for example, from the field 610 to the gas processing facility 600. Upon arrival at the gas processing facility 600, the gas stream 612 may be directed through a dehydration process such as, for example, a glycol dehydration vessel. A dehydration vessel is shown schematically at 620. As a result of passing the raw gas stream 612 through the dehydration vessel 620, a water stream 622 is generated. In some cases, this raw gas stream 612 may be mixed with monoethylene glycol (MEG) to prevent water spillage and hydrate formation. The MEG may be sprayed, for example, on a chiller, where the liquid is collected and separated into water, more concentrated MEG, and possibly some heavy hydrocarbons, depending on the temperature of the chiller and the injected gas composition. Also good.
The water stream 622 may be sent to a water treatment facility. Alternatively, the water stream 622 can be reinjected into the underground structure. The underground structure is indicated by block 630. As a further alternative, the removed water stream 622 can be treated to meet environmental standards and then discharged as treated water into the local watershed (not shown).

  Further, passing the product gas stream 612 through the dehydration vessel 620 results in the production of a substantially dehydrated methane gas stream 624. The dehydrated gas stream 624 can contain trace amounts of nitrogen, helium and other inert gases. In connection with the system and method of the present invention, the dehydrated gas stream 624 also contains carbon dioxide and a small amount of hydrogen sulfide. The gas stream 624 may contain other sulfur components such as carbonyl sulfide, carbon disulfide, sulfur dioxide, and various mercaptans.

  The dehydrated gas stream 624 may pass through a spare refrigeration unit 625. The refrigeration unit 625 cools the dehydrated gas stream 624 to temperatures as low as approximately 20 ° F. to 50 ° F. The refrigeration unit 625 may be, for example, an air cooler or an ethylene or propane refrigerator.

It is desirable to remove sulfur components from the dehydrated gas stream 624 to prevent iron sulfide corrosion. In accordance with the gas processing facility 600, a solvent system 605 is provided. Dehydrated gas stream 624 enters solvent system 605. Solvent system 605 removes hydrogen sulfide through an absorption process by contacting gas stream 624 with a solvent. This is done at relatively low temperatures and relatively high pressures, and the solubility of the acid gas component during this process exceeds that of methane.
As described, the solvent system 605 can be either a physical solvent system or a chemical solvent system. FIG. 7A provides a schematic diagram of a physical solvent system 705A in one embodiment. Physical solvent system 705A operates to contact dehydrated gas stream 624 to remove sulfur components.

Examples of suitable physical solvents include N-methylpyrrolidone, propylene carbonate, methyl cyanoacetate, and refrigerated methanol. A preferred example of the physical solvent is sulfolane, the chemical name of which is tetramethylene sulfone. Sulfolane is an organic sulfur compound containing a sulfonyl functional group. A sulfonyl group is a sulfur atom double-bonded to two oxygen atoms. Sulfur oxygen double bonds are extremely polar and allow high solubility in water. At the same time, the four carbon ring provides affinity for the hydrocarbon. These properties make sulfolane miscible with both water and hydrocarbons, so that sulfolane is widely used as a solvent for purifying hydrocarbon mixtures.
A preferred physical solvent is Selexol ™. Selexol ™ is a trade name for a gas treatment product of Union Carbide, a subsidiary of Dow Chemical Company. Selexol ™ solvent is a mixture of dimethyl ether of polyethylene glycol. One example of such a component is dimethoxytetraethylene glycol. Selexol® also picks up any heavy hydrocarbons in the initial fluid stream 10 as well as some water. If the initial fluid stream 10 is fairly dry at the start, Selexol ™ can be used to eliminate the need for other dewatering. It should be noted here that Selexol ™ solvent is selective for H ₂ S when the Selexol ™ solvent is cooled and then pre-saturated with CO ₂ .

  Referring to FIG. 7A, it can be seen that the dehydrated gas stream 624 enters the injection separator 660. It should be understood that it is desirable to prevent liquid solvent bubbling during the acid gas removal process by keeping gas stream 624 clean. Accordingly, the injection separator 660 is used to filter out liquid impurities, such as oil-based drilling fluid and mud. Some particles can also be filtered. Brine is preferably screened using upstream dewatering vessel 620. However, the injection separator 660 can remove any condensed hydrocarbons.

  Drilling fluid and liquid such as condensed hydrocarbons are dripped from the bottom of injection separator 660. A liquid impurity stream can be seen at 662. Water-based impurities can usually be sent to a water treatment facility (not shown) or reinjected into the structure 630 to maintain reservoir pressure or for disposal. The hydrocarbon liquid is generally sent to a condensate treatment facility. The gas exits from the top of the injection separator 660. The purified gas stream can be seen at 664.

  Purified gas stream 664 may be directed from gas to gas exchanger 665. A gas to gas exchanger 665 precools the gas in the purified gas stream 664. The purified gas is then directed to the absorber 670. Absorber 670 is preferably a reverse flow contact column that receives the absorbent. In the arrangement of FIG. 7A, the purified gas stream 664 enters the bottom of column 670. At the same time, physical solvent 696 enters the top of column 670. Tower 670 may be a trayed tower, a packed tower, or other type of tower.

It should be understood that any number of non-tower devices designed for gas / liquid contact could be utilized instead. These may include static mixers and co-current contact devices. The backflow column 670 of FIG. 7A is for illustrative purposes only. It should be noted that the use of a small, co-current contactor for the gas and liquid contact vessel is preferred because it reduces the overall footprint and physical solvent system 705A mass.
The absorbent may be, for example, a solvent that is mixed with the purified gas stream 664 to “siete out” H ₂ S and some CO ₂ . Specifically, the absorbent may be the above-described Selexol (registered trademark). As a result of the process of contacting with the absorbent, a light gas stream 678 is produced. Light gas stream 678 exits from the top of column 670. The light gas stream 678 contains methane and carbon dioxide. The light gas stream 678 passes through a refrigeration process before being directed to a cryogenic distillation tower, schematically illustrated at block 100 in FIG.

Returning to FIG. 6 for a moment and referring to this, the light gas stream 678 exits the physical solvent system 705 A and passes through the chiller 626. Chiller 626 cools light gas stream 678 to a temperature as low as approximately −30 ° F. to −40 ° F. The chiller 626 may be, for example, an ethylene or propane refrigerator.
Light gas stream 678 then preferably travels through expansion device 628. The expansion device 628 may be, for example, a Joule-Thompson (“J-T”) valve. The expansion device 628 serves as an expander to achieve further cooling of the light gas stream 678. The expansion device 628 further reduces the temperature of the light gas stream 678 to a lower temperature, for example, from approximately -70 ° F to -80 ° F. Preferably, at least partial liquefaction of the gas stream 678 is also achieved. A cooled sour gas stream is generated in line 611.

Referring again to FIG. 7A, the contact tower 670 will pick up the sulfur component. These are released from the bottom of column 670 as a “rich” solvent. It can be seen that rich solvent stream 672 exits column 670. The rich solvent stream 672 may also contain some carbon dioxide.
In the arrangement of FIG. 7A, rich solvent stream 672 is conveyed through power recovery turbine 674. This allows generation of electrical energy for the physical solvent system 705A. From here, the rich solvent stream 672 is conveyed through a series of flash separators 680. In the exemplary arrangement of FIG. 7A, three separators are shown at 682, 684 and 686. Separators 682, 684, 686 operate continuously at lower temperatures and pressures according to the physical solvent process.

The first separator 682 may operate, for example, at a pressure of 500 psi and a temperature of 90 ° F. The first separator 682 releases light gas entrained in the rich solvent stream 672. These light gases shown at 681 contain primarily methane and carbon dioxide, but may have traces of H ₂ S. This light gas 681 may be directed to the cryogenic distillation column 100 (not shown in FIG. 7A). These gases can be combined with the light gas stream 678. The light gas 681 is preferably moved through the compressor 690 to increase pressure on the way to the cryogenic distillation column 100 as stream 611. If the distillation column 100 is operating at a lower pressure than the first flash stage of the solvent process 705A, ie, the first separator 682, compression may not be necessary. In this case, a pressure drop is required for overhead stream 678 so that streams 681 and 678 can be combined. This pressure drop may be induced by a JT valve near the cryogenic distillation column 100. Of course, the stream 681 must be introduced downstream of the J-T valve.

Ideally, all hydrogen sulfide and any heavy hydrocarbons from the purified gas stream 664 are captured in the rich solvent stream 672. A progressively richer solvent stream is discharged from each separator 682, 684, 686. These increasingly rich flows are indicated by lines 683, 685 and 687. Thus, the physical solvent is generally regenerated by pressure reduction, causing any dissolved methane and carbon dioxide to be flushed from the solvent.
Line 687 is a “semi-lean” solvent stream because some CO ₂ has been removed, but solvent stream 687 has not been fully regenerated. A portion of the solvent stream 687 is conveyed via a booster pump 692 and reintroduced into the contact column 670 as a semi-lean solvent at an intermediate level of the contact column. The remaining portion shown at 693 is directed to the regeneration vessel 652.

  Note that in conjunction with the second and third 684 of the three separators, each of these separators 684, 686 also emits a very small amount of light gas. These light gases mainly contain carbon dioxide together with a small amount of methane. These light gases are shown at 689 in two separate lines. Light gas 689 may be compressed and combined with line 611 and then directed to cryogenic distillation column 100. Alternatively, the light gas from line 689 may be delivered directly to the liquefied bottom acid gas stream shown at 642 in FIG.

One advantage of using a physical solvent for upstream H ₂ S removal is that the solvent is generally hygroscopic. This eliminates the need for a gas dehydration vessel 620, particularly when the initial fluid stream 10 is already substantially dry. In order to achieve this objective, the selected solvent itself is preferably non-aqueous. By this method, the solvent can be used to further dehydrate raw natural gas. In this case, the water can be included in the gas stream 655 from the regenerator 652 and exit.

The disadvantage of this process is that some light hydrocarbons and CO ₂ are co-adsorbed to some extent in the physical solvent. The use of multiple separators 682, 684, 686 removes most if not all methane from the rich solvent stream 672, usually not all.

Referring again to the regeneration vessel 652, this vessel 652 acts as a stripper. The hydrogen sulfide components are driven such that they exit the regeneration vessel 652 via the gas stream 655 as a concentrated H ₂ S stream. Concentrated H ₂ S in gas stream 655 is shown exiting physical solvent system 705A. This is also illustrated by line 655 in FIG.
The concentrated H ₂ S in the gas stream 655 is preferably sent to an acid gas injection (AGI) facility. Any CO ₂ and water vapor may be removed by using a second physical solvent process in advance. A separator is shown at 658. The separator 658 is a reflux vessel that collects condensed water and solvent while moving gas to overhead. Condensed water and solvent can also be returned to the regeneration vessel 652 via the bottom line 659. At the same time, overhead gas can also be sent via line 691 to acid gas injection (shown schematically in block 649 of FIG. 6 and discussed below).
The gas stream 655 also includes carbon dioxide. Carbon dioxide and any water vapor will exit separator 658 with H ₂ S via overhead line 691. H ₂ S is preferably sent to a downstream AGI facility 649 or may be sent (not shown) to a sulfur recovery unit (SRU).

The regeneration vessel 652 shown in FIG. 7A can separate the sulfur component from the solvent using a stripping gas. The regeneration vessel 652 can supply any number of stripping gases. An example is a fuel gas stream having a high CO ₂ content. A high CO ₂ content fuel gas helps to “pre-saturate” the solvent with CO ₂ , thereby reducing CO ₂ collection from the purified gas stream 664 so that the stripping gas Preferred for 651. It can be seen that the stripping gas flows into the regeneration vessel 652 via line 651 '. This stripping gas 651 ′ may be part of the light gas stream 689 from, for example, the lowest pressure flash stage, ie separator 686. This allows for the potential recovery of some hydrocarbons.

  The regenerated solvent is guided from the bottom of the regeneration container 652. The regenerated solvent exits as 653. The regenerated solvent 653 is carried via the booster pump 654. By using the second booster pump 694, the pressure of the line carrying the regeneration solvent 653 may be further increased. Thereafter, the regenerated solvent 653 is preferably cooled via a heat exchanger 695 optionally having a refrigeration unit. The cooled and regenerated solvent 696 is then recycled back to the contactor 670.

A portion of the regenerated solvent is removed from the bottom of the regeneration vessel 652 and sent to the reboiler 697. The reboiler warms the solvent. The warmed solvent is returned to the regeneration vessel 697 as a partially vaporized flow via line 651 ″.
FIG. 7A demonstrates one embodiment of physical solvent system 705A. However, as described, the solvent system 605 may alternatively be a chemical solvent system. In the case of a chemical solvent system, a chemical solvent, particularly an H ₂ S selective amine, will be used. Examples of such selective amines include methyldiethanolamine (MDEA) and the Flexsorb (R) family of amines. Flexsorb® is a trade name for a chemical adsorbent used to remove sulfur gas from a sour gas mixture. A Flexsorb® adsorbent or other amine is contacted with a hydrocarbon gas stream 624 or a purified gas stream 664 upstream of the cryogenic distillation column.
Amine-based solvents rely on chemical reactions with acid gas components in the hydrocarbon gas stream. This reaction process is sometimes referred to as “gas sweetening”. Such chemical reactions are generally more effective than physics-based solvents, especially at feed gas pressures below about 300 psia (2.07 MPa).
Flexsorb® amine is a preferred chemical solvent for selectively removing H ₂ S from a CO ₂ -containing gas stream. Flexsorb (TM) amines are good use H ₂ S absorption of a relatively fast rate compared to CO ₂ absorption. The high absorption rate helps prevent carbamate formation. Hydrogen sulfide produced from amine-based processes is generally at low pressure. The produced H ₂ S will be either sulfur recovered or disposed of in the ground that requires significant compression.

Removal of hydrogen sulfide using a selective amine can be accomplished by dehydration with a chemical solvent and contact with a cooled fluid stream 624. This can be done by injecting a gas stream 624 into the “absorber”. An absorber is a container that allows gas from gas stream 624 to come in contact with Flexsorb ™ or other liquid amine. Since the two fluid substances interact, the amine generates a sweetened gas stream by absorbing H ₂ S from the sour gas. The sweetened gas stream contains mainly methane and carbon dioxide. This “sweet” gas flows from the top of the absorber.

  In one embodiment, the absorber is a large, counter-current contact tower. In this arrangement, the raw gas stream 624 is injected into the bottom of the contact tower and the chemical solvent, or “lean solvent stream” is injected into the top of the contact tower. Once inside the countercurrent contact tower, the gas from the gas stream 624 moves up through the absorber. Typically, one or more trays or other internal structures (not shown) are provided in the absorber to create multiple flow paths for natural gas between the gas phase and the liquid phase. Create an interface area. At the same time, the liquid from the lean solvent stream moves down and across the series of trays in the absorber. The tray supports the interaction between natural gas and solvent flow. This process is demonstrated in connection with FIG. 1 of the patent application entitled “Removal of Acid Gases From a Gas Stream”. This application was provisionally filed on October 14, 2008 and assigned US Pat. No. 61 / 105,343. FIG. 1 and corresponding parts of the specification are hereby incorporated by reference.

A “rich” amine solution falls from the bottom of the counter-current contact tower. This includes liquid amines along with absorbed H ₂ S. The rich amine solution is removed via a regeneration process that may appear quite similar to the regeneration component described in FIG. 7A above in connection with physical solvent system 705A, although this is typically 100% It has only a single flash vessel operating at ~ 200 psig.

Backflow contactor towers used as H ₂ S scrubbing absorbers tend to be very large and heavy. This creates particular problems in offshore oil and gas production applications. Thus, alternative embodiments for H ₂ S removal from hydrocarbon gas streams resulting from oil and gas recovery are proposed herein. This includes the use of smaller, co-current contact devices. These devices can improve amine selectivity by reducing contact time and thus reducing the probability that CO ₂ is absorbed. These smaller absorbers can also reduce the size of the overall footprint of process 605.

FIG. 7B illustrates an exemplary embodiment of a chemical solvent system 705B that may be used for the solvent process 605 of FIG. The chemical solvent system 705B includes a series of parallel flow contact devices CD1, CD2,. . , CD (n-1), CDn are employed. These devices are used to contact the selective amine with the gas stream.
The co-current concept utilizes two or more contactors in series, where the sour gas stream and liquid solvent move together in the contactor. In one embodiment, the sour gas stream and the liquid solvent move together generally along the longitudinal axis of each contactor. Cocurrent contactors can operate at much higher fluid velocities. As a result, co-current contactors tend to be smaller than countercurrent contactors that utilize packed towers or towers with trays.
Similar to FIG. 7A, it can be seen that the dehydrated gas stream 624 enters the injection separator 660. Injection separator 660 serves to filter out liquid impurities such as, for example, oil-based drilling fluids and mud. The brine is preferably screened using the upstream dewatering vessel 620 shown in FIG. Some particle filtration can also take place in the injection separator 660. It should be understood that it is desirable to prevent liquid solvent bubbling during the acid gas removal process by keeping gas stream 624 clean.

Liquids such as condensed hydrocarbons and drilling fluid fall from the bottom of injection separator 660. The liquid impurity stream can be seen at 662. Impurities carried by the water are usually sent to a water treatment facility (not shown) or may be reinjected into the structure 630, and the line 622 is for maintaining reservoir pressure or for disposal. The hydrocarbon liquid is usually connected to a condensing processor. The gas exits from the top of the injection separator 660. The purified sour gas stream can be seen at 664.
The purified sour gas is guided to a series of absorbers. Here, the absorber is a co-current contact device CD1, CD2,. . , CD (n-1), CDn. Each contactor CD1, CD2,. . , CD (n−1), CDn remove a portion of the H ₂ S content from the gas stream 664, thereby releasing a progressively sweetened gas stream. The final contactor CDn provides a final sweetened gas stream 730 (n) substantially comprising methane and carbon dioxide. Gas stream 730 (n) becomes line 678 in FIG.

  In operation, the gas stream 664 enters the first co-current absorber, or contact device, CD1. Here, the gas is mixed with the liquid solvent 720. Solvent 720 preferably comprises an amine solution such as methyldiethanolamine (MDEA) or Flexsorb® amine. The liquid solvent can also include hindered amines, tertiary amines, or combinations thereof. Flexsorb (R) is an example of a hindered amine and MDEA is an example of a tertiary amine. Further, solvent stream 720 is a “semi-lean” solvent that is partially regenerated or produced by regenerator 750. The movement of “semi-lean” solvent 720 to the first contactor CD 1 is assisted by pump 724. Pump 724 moves semi-lean solvent 720 to the first contactor CD1 under appropriate pressure. An example of a suitable pressure is approximately 15 psia to 1,500 psig.

Once inside the first contactor CD1, the gas stream 664 and the chemical solvent stream 720 move along the longitudinal axis of the first contactor CD1. As they move, the liquid amine (or other solvent) interacts with the H ₂ S in the gas stream 664, either by chemically bonding the H ₂ S in an amine molecule, or H ₂ S by amine molecular absorption Let The first “rich” solvent solution 740 (1) falls from the bottom of the first contactor CD1. At the same time, the first partially sweetened gas stream 730 (1) exits the first contactor CD1 and is discharged to the second contactor CD2.

  The second contactor CD2 also represents a cocurrent separation device. A third cocurrent separation device CD3 may be provided after the second contactor CD2. Each of the second and third contactors CD2, CD3 produces a respective partially sweetened gas stream 730 (2), 730 (3). Further, each of the second and third contactors CD2, CD3 produces a respective partially filled gas treatment solution 740 (2), 740 (3). When amine is used as the solvent, this partially filled gas treatment solution 740 (2), 740 (3) will contain a rich amine solution. In the exemplary system 705B, the second filled gas treatment solution 740 (2) merges with the first filled gas treatment solution 740 (1) and passes through the regenerator 750 to regenerate. Go through the process.

  Gas streams 730 (1), 730 (2),. . . Note that the pressure in the system generally decreases as it travels downstream through 730 (n-1). As this pressure drop occurs, the upstream (or other liquid solvent) stream 740 (n), 740 (n-1),. . . The pressure at 740 (2), 740 (1) must generally increase to match the gas pressure. Thus, in system 705B, one or more small booster pumps (not shown) are connected to contactors CD1, CD2,. . . It is preferable to arrange | position between each of these. This serves to boost the liquid pressure in the system.

In system 705B, streams 740 (1), 740 (2) initially contain a “rich” solvent solution that travels through flash drum 742. The flash drum 742 operates at a pressure of approximately 100-150 psig. The flash drum 742 typically has an internal structural portion that creates a precipitation effect or serpentine flow path for the solvent stream 740 therein. Residual gases such as methane and CO ₂ are flushed from solvent stream 740 via line 744. Residual gas captured in line 744 can be reduced to an acid gas content of approximately 100 ppm, for example when contacted with a small amount of fresh amine from line 720. This concentration is low enough that this residual gas can be used as a fuel gas for system 705B.

Residual natural gas can be flushed from solvent stream 740 via line 744. The resulting rich solvent stream 746 is directed to the regenerator 750.
Prior to moving to the regenerator 750, the rich solvent stream 746 is preferably transferred via a heat exchanger (not shown). The relatively cool (close to ambient temperature) solvent stream 746 can be heated via thermal contact with the warm lean solvent stream 760 exiting the bottom of the regenerator 750. This further serves to advantageously cool the lean solvent stream 760 before it is delivered to the lean solvent cooler 764 and then to the final contactor CDn.

Regenerator 750 is defined as a stripper portion 752 that includes a tray or other internal structure (not shown) above reboiler 756. A heat source is provided to the reboiler 756 to generate heat. The regenerator 750 produces a regenerated or “lean” solvent stream 760 that is recycled for reuse in the final contactor CDn. Overhead gas removed from regenerator 750 containing concentrated H ₂ S exits regenerator 750 as impurity stream 770.
The H ₂ S rich impurity stream 770 moves to the condenser 772. This condenser 772 serves to cool the impurity stream 770. The cooled impurity stream 770 travels through a reflux accumulator 774 that separates any residual liquid (mainly condensed water) from the impurity stream 770. An acid gas stream 776 containing mainly H ₂ S is then created. The acid gas stream 776 is the same as line 655 of FIG.

Some liquid may fall from the reflux accumulator 774. This produces a residual liquid stream 775. This residual liquid stream 775 is preferably conveyed via pump 778 to boost the pressure and then reintroduced there into regenerator 750. Some of the remaining liquid will exit the bottom of the regenerator 750 as part of the lean solvent stream 760. Some water content may be added to the lean solvent stream 760 to compensate for the loss of water vapor to the sweetened gas stream 730 (n-1), 730 (n). This water can be added during the suction or suction of the reflux pump 778.
This lean or regenerated solvent 760 is at low pressure. Thus, this liquid stream representing the regenerated solvent 760 is conveyed via the pressure boost pump 762. Pump 762 is referred to as a lean solvent booster 762. From there, this lean solvent 760 passes through a cooler 764. Cooling the solvent via the cooler 764 ensures that the lean solvent 760 effectively absorbs the acid gas. The cooled lean solvent 760 is used as the solvent stream for the final separation contactor CDn.

The solvent tank 722 includes contact devices CD1, CD2,. . , CD (n−1), may be provided proximal to CDn. The lean solvent 760 can pass through the solvent tank 722. Since the solvent tank 722 may be required for the gas facility 705B, it is more preferable to provide the solvent reservoir offline.
Again, a plurality of co-current contact devices CD1, CD2,. . . Referring to CD (n-1), CDn, each contact device receives a gas stream comprising hydrocarbon gas and hydrogen sulfide. Each contact device CD1, CD2,. . . CD (n-1), CDn operates to sequentially remove H ₂ S and produce a progressively sweetened gas stream. Co-current contact devices CD1, CD2,. . . CD (n-1), CDn may be any of various short contact time mixing devices. Examples include static mixers and centrifugal agitators. Some mixing devices break the liquid apart through the discharge device. The evacuation device delivers gas through a tube similar to a Venturi tube, which then draws the liquid solvent into the tube. Due to the Venturi effect, the liquid solvent is dragged in and breaks into small droplets, increasing the contact surface area with the gas.

One preferred contact device is a ProsCon ™ contactor. This contactor utilizes a discharge device followed by a centrifugal coalescer. This centrifugal coalescer causes a large centrifugal force to reintegrate a small volume of liquid solvent. In any embodiment, it is preferable to employ small vessel technology, which allows for hardware reduction compared to large contactor towers.
The first contactor CD1 receives a raw gas stream 664. This gas stream 664 is processed in the first contactor CD1 for removal of hydrogen sulfide. A first partially sweetened gas stream 730 (1) is then released. The first partially-sweetened gas stream 730 (1) is delivered to the second contactor CD2. The first sweetened gas stream 730 (1) is then further processed for removal of hydrogen sulfide so that a second, more fully sweetened gas stream 730 (2) is released. This pattern is continued so that the third contactor CD3 produces a more fully sweetened gas stream 730 (3). The fourth contactor CD4 produces an even more sweetened gas stream 730 (4) and the last contactor produces an even more sweetened gas stream CD (n-1). To do. Each of these streams can be referred to as a “secondary” sweetened gas stream.

The final sweetened gas stream 730 (n) is discharged by the final contactor CDn. The number of contact devices (at least two) before the final contactor CDn is mainly determined by the required level of H ₂ S removal to meet the desired standard. In the system 705B of FIG. 7, the final sweetened gas stream 730 (n) still contains carbon dioxide. Accordingly, the sweetened gas stream 730 (n) must be removed via the CFZ column 100 of FIG. The sweetened gas stream 730 (n) is the same as line 678 in FIG.

In one embodiment, a combination of a mixing device and a corresponding flocculating device is employed in each contactor. Thus, for example, the first CD1 and second CD2 contactors can utilize a static mixer as their mixing device, and the third CD3 and other CD4 contactors utilize a discharge device. CDn-1 and CDn contactors can utilize centrifugal agitators. Each contactor is associated with an agglomeration device. In either embodiment, the gas streams 664, 730 (1), 730 (2),. . . 730 (n-1) and the co-currently flowing liquid solvent stream are contactors CD1, CD2,. . . It flows in the same direction via CDn. This allows the treatment reaction to take place in a short period, perhaps even as short as 100 milliseconds or less. This is advantageous for selective H ₂ S removal (relative to CO ₂ ) because certain amines react with H ₂ S more rapidly than CO ₂ .

In addition to receiving the gas flow, each co-current contactor CD1, CD2,. . . CD (n-1), CDn also receives a liquid solvent stream. In system 705B, the first contactor CD1 receives a partially regenerated solvent stream 720. Subsequent contactors CD2, CD3, CD (n-1), CDn then receive the filled solvent solution released from the next respective contactor. Thus, the second contactor CD2 receives the partially filled solvent solution 740 (3) released from the third contactor CD3, and the third contactor CD3 is released from the fourth contactor CD4. The partially filled solvent solution 740 (4) is received, and the last previous contactor CD (n-1) receives the partially filled solvent solution 740 (n) from the final contactor CDn. In other words, the liquid solvent sent to the second contactor CD2 includes a partially filled solvent solution 740 (3) discharged from the third contactor CD3, and the third contactor CD3. The liquid solvent sent to the liquid contains the partially filled solvent solution 740 (4) discharged from the fourth contactor CD4, and the liquid sent to the last previous contactor CD (n-1). The solvent includes a partially filled solvent solution 740 (n) from the final contactor CDn. Thus, the partially filled solvent solution can be used to form an increasingly sweetened gas stream 730 (1), 730 (2), 730 (3),. . . 730 (n-1) in the opposite process direction, contactors CD1, CD2, CD3,. . . Introduced into CDn.
The last separation contactor CDn also receives a liquid solvent. This liquid solvent is the regenerated solvent stream 760. The regenerated solvent stream 760 is very lean.

The chemical solvent system 705B of FIG. 7B is intended to be illustrative. Other arrangements can be used for such systems that employ multiple co-current contact devices as absorbers. Examples of such additional systems are described in the context of CO ₂ removal in US patent application Ser. No. 61 / 105,343, referenced above. FIG. 2B and corresponding portions of the specification are also incorporated herein by reference.

  In system 705B of FIG. 7B, both solvent solutions 740 (1) and 740 (2) are regenerated. Partially regenerated solvent 780 emerges from the regeneration vessel 750. This solvent 780 is placed under pressure through a booster pump 782. From there, the solvent 780 becomes a solvent stream 720 upon cooling in the heat exchanger 784. The solvent 780 is further pressurized via a booster pump 724 before being introduced as a solvent stream 720 into the first co-current contactor CD1.

Referring again to FIG. 6, light gas stream 678 (which is also line 678 in FIG. 7A and line 730 (n) in FIG. 7B) exits solvent system 605, passes through the dehydrator, and passes through chiller 626. To do. Chiller 626 cools light gas stream 678 to a temperature as low as approximately −30 ° F. to −40 ° F. The chiller 626 may be, for example, an ethylene or propane refrigerator.
Light gas stream 678 then preferably travels through expansion device 628. The expansion device 628 may be, for example, a Joule-Thompson (“J-T”) valve. The expansion device 628 serves as an expander to achieve further cooling of the light gas stream 678. The expansion device 628 further reduces the temperature of the light gas stream 678 from, for example, approximately −70 ° F. to −80 ° F. Preferably, at least partial liquefaction of the gas stream 678 is also achieved. The cooled sour gas stream is shown in line 611.

The chilled sour gas in line 611 enters the cryogenic distillation tower 100. The cryogenic distillation column 100 may be any column that operates to distill methane from acid gases via a process that intentionally freezes CO ₂ particles. The cryogenic distillation column may be, for example, the CFZ ™ column 100 of FIG. The chilled sour gas in line 611 enters tower 100 at approximately 500-600 psig.
As described in connection with FIG. 1, acid gas is withdrawn from the distillation column 100 as a liquefied acid gas bottom stream 642. In this example, the acid gas bottom stream 642 includes primarily carbon dioxide. The acid gas bottom stream 642 contains very little hydrogen sulfide or other sulfur component, such as that captured by the sulfur component removal system (solvent system 605), and as further concentrated H ₂ S stream 655 for further processing. Delivered. H ₂ S can be converted to elemental sulfur using a sulfur recovery unit (not shown). This sulfur recovery unit may be a so-called Claus process. This enables more effective sulfur recovery of a large amount of sulfur.

At least some of the bottom stream 642 is routed through a reboiler 643. From there, the fluid containing methane is again directed back to the tower 100 as a gas stream 644. Residual fluid composed primarily of carbon dioxide is released via the CO ₂ line 646. The CO _{2 in} line 646 is in liquid form. The carbon dioxide in line 646 preferably passes through pressure booster 648 and then is injected into the underground structure via one or more acid gas injection (AGI) wells, as indicated by block 649.

  Methane is discharged from the distillation column 100 as an overhead methane stream 112. This overhead methane stream 112 preferably contains approximately 2 mole percent or less of carbon dioxide. In this percentage, the overhead methane stream 112 can be used as fuel gas or sold to a specific market as natural gas. However, it may be desirable to subject the overhead methane stream 112 to further processing in accordance with certain methods herein. More specifically, overhead methane stream 112 passes through an open loop refrigeration system.

Initially, the overhead methane stream 112 passes through the cross exchanger 113. This cross exchanger 113 serves to pre-cool the liquid reflux stream 18 which is increased via the expander device 19 and then reintroduced into the cryogenic distillation column 100. The overhead methane stream 112 is then sent through the compressor 114 to increase its pressure.
The pressurized methane stream 112 is then cooled. This can be done, for example, by passing the methane stream 112 through the air cooler 115. A cold and pressurized methane stream 116 is produced. The methane stream 116 is preferably liquefied to make a product.

A portion of the cooled and pressurized methane stream 116 leaving the cooler 115 is split into a reflux stream 18. This reflux stream 18 is further cooled in heat exchanger 113 and then expanded via expander device 19 to ultimately produce the cold spray stream 21 of FIG. This cold spray stream 21 enters the distillation column 100 where it is used as a cold liquid spray. This liquid spray, or reflux, reduces the temperature of the controlled freezing zone (shown at 108 in FIG. 1) and helps freeze the CO ₂ and other acid gas particles from the dehydrated gas stream 624 described above. do.
It should be understood that FIG. 6 represents a simplified schematic diagram intended to reveal only selected aspects of the gas processing system 600. Gas treatment systems typically have many additional components, such as pressure measuring devices, temperature measuring devices, level measuring devices, and flow measuring devices, as well as heaters, chillers, condensers, liquid pumps, gas compressors, blowers, and other It will include types of separation equipment and / or sorting equipment, valves, switches, controllers, etc.

Additional methods for removing sulfur components from a raw gas stream are provided herein. One such method falls under the broad heading “redox” process. The term “redox” refers to a reductive oxidation reaction. Reductive oxidation refers to a chemical reaction in which an atom changes its oxidation number or oxidation state. In the redox process of the present invention, oxidized metal, such as chelated iron, reacts directly with H ₂ S to form elemental sulfur.
The oxidized metal is an aqueous chelate metal catalyst solution. During operation, the gas stream containing hydrogen sulfide is absorbed by contact with the chelating metal catalyst. Subsequently, the hydrogen sulfide is oxidized to elemental sulfur and at the same time the metal is reduced to a lower oxidation state. The catalyst solution is then regenerated for reuse by contacting it with an oxygen-containing gas to oxidize the metal back to a higher oxidation state.

FIG. 8 is a schematic diagram illustrating a gas processing facility 800 for removing acidic gas from a raw gas stream. In this arrangement, hydrogen sulfide is removed from the raw gas stream upstream of the acid gas removal system 650 using a redox process. This redox process is aqueous based, which means that there is no need to dewater the raw gas stream before the H ₂ S removal step is initiated.

FIG. 8 shows a gas processing facility 800 that receives the product gas stream 812. This product gas stream 812 begins with a hydrocarbon production activity that takes place in a reservoir generation region, or “field” 810. It should be understood that this field 810 can represent any location where gaseous hydrocarbons are produced. Hydrocarbons will include methane as well as hydrogen sulfide. The hydrocarbon may also include ethane as well as carbon dioxide.
In the gas processing facility 800, the gas stream 812 flows into the sulfur component removal system 850. The sulfur component removal system 850 uses a redox process. The sulfur component removal system 850 initially includes a contactor 820. This contactor 820 is defined as a chamber 825 that receives raw hydrocarbon gas from field 810. Once in the chamber 825, a chemical reaction occurs that separates hydrogen sulfide and other sulfur components from the raw gas stream 812.

Chamber 820 also receives the chelated metal oxide to cause a chemical reaction. An example of such a metal oxide is chelated iron. This chelated iron is in the form of a metal chelant solution. This metal chelant solution is delivered to chamber 825 via line 842.
Once in the chamber 825, the chelated metal solution reacts with hydrogen sulfide in the raw gas stream 812. A reduction oxidation reaction occurs. As a result, the chelated reduced metal mixture is released through the bottom line 822 along with elemental sulfur. At the same time, the gas escapes via overhead line 824. Basic reactant S ^- a ^{+ 2Fe +++ → S 0 + 2Fe} ++.

The gas in line 824 contains mainly methane and carbon dioxide. Trace amounts of ethane, nitrogen, or other components may also be present in line 824. The gas in line 824 together means sour gas.
The exemplary sulfur component removal system 850 also includes an oxidizer 830. This oxidizer 830 is defined as a chamber 835 for oxidizing the reduced metal mixture. Oxidizer 830 receives the reduced metal mixture via line 822. The pressure of the metal mixture in line 822 is controlled by valve 828.

The oxidizer 830 also receives air. Air is introduced into oxidizer 830 via line 834. In order to circulate air through chamber 835 in oxidizer 830 by air blower 838, the pressure in line 834 is increased. Once in the chamber 835, the air contacts the chelate metal mixture and oxidizes the reduced metal mixture. Air is released from the oxidizer 830 via a discharge line 836.
Oxidation produces an oxidized chelate metal mixture. This chelate mixture also contains sulfur in colloidal form. The chelate mixture containing sulfur falls from the oxidizer 830 via line 832.
The exemplary sulfur component removal system 850 also includes a separator 840. The separator 840 of FIG. 8 is shown as a centrifuge. However, other types of separators can be employed. The centrifuge 840 separates the aqueous chelant mixture containing sulfur into two components. One component is elemental sulfur. This elemental sulfur is continuously removed from the process as a pure solid product. The contact process is preferably limited to relatively low pressure (300 psig or less) because the equipment is plugged with colloidal sulfur. Elemental sulfur may be stored or more preferably sold as a commodity.

Elemental sulfur falls at line 844. The sulfur is preferably directed to a sulfur handling unit (not shown). This leaves an aqueous metal killant solution that is substantially free of elemental sulfur.
The aqueous metal catalyst solution of the removal system 850 is regenerated chelated iron. This chelated iron is again guided back to the contactor 820 by line 842. A pump 844 may be provided to increase the pressure at line 842 and carry the chelant mixture to the contact vessel 825. By this method, chelated iron (or other oxidized metal) can be recovered and reused.

Referring to the gas line 824 again, the sour gas in the gas line 824 is conveyed to the dehydration vessel 860. Since the redox process uses aqueous based material to separate H ₂ S from the raw gas stream 812, subsequent dehydration of the gas in line 824 is necessary prior to removal of the cryogenic acid gas. As a result of the sour gas turning from the gas line 824 through the dehydration vessel 860, an aqueous stream 862 is produced. The aqueous stream 862 may be sent to a water treatment facility. Alternatively, the aqueous stream 862 can be reinjected into an underground structure, such as the underground structure 630 of FIG. Further, as an alternative, the removed aqueous stream 862 can be treated to meet environmental standards and then discharged into a regional watershed (not shown) as treated water.
Similarly, turning the sour gas from line 824 through dehydration vessel 860 results in a substantially dehydrated gas stream 864. This dehydrated gas stream 864 contains methane and may also contain traces of nitrogen, helium and other inert gases. In connection with the system and method of the present invention, the dehydrated gas stream 864 also includes carbon dioxide.

The dehydrated gas stream 864 exits the dehydration vessel 860 and passes through the chiller 626. The chiller 626 cools the dehydrated gas stream 864 to temperatures as low as approximately −30 ° F. to −40 ° F. The chiller 626 may be, for example, an ethylene or propane refrigerator. A cooled light gas stream 678 is thus produced.
Light gas stream 678 then preferably travels through expansion device 628. The expansion device 628 may be, for example, a Joule-Thompson (“J-T”) valve. This expansion device 628 serves as an expander to achieve further cooling of the light gas stream 678. This expansion device 628 further reduces the temperature of the light gas stream 678 to a low temperature, for example, from approximately -70.degree. Preferably, at least partial liquefaction of the gas stream 678 is also achieved. The cooled sour gas stream is indicated by line 611.

  The cooled sour gas in line 611 is directed to the distillation column. This distillation column may be, for example, the CFZ column 100 of FIGS. The sour gas from line 611 is then processed via an acid gas removal system. This acid gas removal system can follow, for example, the acid gas removal system 650 of FIG.

Another means for removing sulfur components from the raw gas stream is through the use of a scavenger bed scavenger. The use of scavengers is known in the gas processing industry as a means of removing H ₂ S and mercaptans from gas streams. The scavengers can be solid, they can be in liquid form, or they can be catalyst solutions.
Scavengers convert sulfhydryl-containing compounds and other sulfur-containing compounds into harmless compounds such as metal sulfides. This compound can be disposed of in a safe and environmentally sound manner. There is scavenger-specific utility when conventional amine treatment is not economically feasible due to the low H ₂ S composition in the raw gas stream. One example is when the H ₂ S composition is less than approximately 300 ppm.

An example of a known liquid-based scavenger is triazine. A more specific example is an aqueous formulation of 1,3,5 tri- (2-hydroxyethyl) -hexahydro-S-triazine. Another example of a liquid-based scavenger is a nitrous acid solution.
Examples of solid scavengers are iron oxide (FeO, Fe ₂ O ₃ , or Fe ₃ O ₄ ) and zinc oxide (ZnO). Solid scavengers are generally non-renewable. Non-renewable scavenger beds must be replaced once used. Iron oxide generally requires some moisture to be effective, but does not require zinc oxide. Thus, if the sour gas stream is already dehydrated, the use of ZnO is advantageous in that it does not necessarily require additional dehydration upstream of the CO ₂ removal process. However, water can be generated from an oxidation process. Therefore, depending on the initial level of H ₂ S, subsequent dehydration may be required.

Hydrogen sulfide scavengers are most commonly applied via one of three methods. First, batch application of liquid scavenger can be used in a sparged column contactor. Second, batch application of solid scavenger can be performed in a fixed bed contactor. Third, continuous direct injection of the liquid scavenger into the container can be employed. This is the most common application.
Conventional direct injection H ₂ S capture uses a pipeline as a contactor. In this application, a liquid H ₂ S scavenger, such as triazine, is injected into the gas stream. H ₂ S is absorbed into the capture solution. The H ₂ S reacts to form a byproduct, which is subsequently removed from the raw gas stream and disposed of. An alternative to direct injection of H ₂ S capture involves extruding a liquid jet of capture agent through a small opening under high pressure. Usually, a spray nozzle is used to atomize the liquid capture agent into very small droplets. The direct injection method may have the lowest overall cost for many applications due to lower capital costs compared to batch application.

FIG. 9 is a schematic diagram illustrating a gas processing facility 900 for removing acid gases from a gas stream according to the present invention in one embodiment. In this arrangement, scavengers are used to remove hydrogen sulfide from the raw gas stream 912 upstream of the acid gas removal system 950.
FIG. 9 shows a gas processing facility 900 that receives the product gas stream 912. This production gas stream 912 begins with a hydrocarbon production activity performed in a reservoir production area, or “field” 910. It should be understood that this field 910 can represent any location where gaseous hydrocarbons are produced. Hydrocarbons will include methane as well as hydrogen sulfide. The hydrocarbon may also include ethane as well as carbon dioxide.

In the gas processing facility 900, the product gas stream 912 flows into the sulfur component removal system 950. The sulfur component removal system 950 uses an H ₂ S scavenger. Any of the capture methods described above may be employed. The exemplary sulfur component removal system 950 uses the third method described above, ie, continuously injects a liquid scavenger into the separation vessel 920.
In order to remove sulfur components from the raw gas stream 912, the raw gas stream 912 is directed to the pipeline 922. At the same time, a liquid scavenger such as triazine is introduced into the pipeline 922 via the scavenger line 944. This triazine is injected through a spray nozzle 923 and then mixed with the raw gas stream 912 in the static mixer 925. From there, the contacted raw gas stream 912 enters the separation vessel 920.

  Separation vessel 920 is defined as chamber 926. The liquid settles to the bottom of chamber 926 and the gaseous component exits to the top of chamber 926. This liquid exits via the liquid line 927. The liquid contains spent scavenger material. A portion of the liquid from line 927 is removed as effluent waste. A waste line 942 directs spilled waste to a holding tank (not shown) or other waste holding area. Waste may be carried away by truck or waste line. The remaining portion of the liquid from line 927 can be brought back into scavenger line 944 to come into contact with raw gas stream 912 if the scavenger is not fully utilized.

  The sulfur component removal system 950 also includes a scavenger vessel 930. This scavenger container 930 holds a liquid scavenger. The operator turns the liquid scavenger from the scavenger vessel 930 to the scavenger line 944 if necessary. A pump 946 is provided to increase the pressure for the injection of liquid scavenger into the pipeline 922.

  Referring again to the separation vessel 920, the separation vessel 920 can include a mist separator 924. The mist separator 924 helps prevent liquid particles from escaping from the top of the separation vessel 920 having gaseous components. This phenomenon is called flying entrainment. The mist separator 924 is similar to a mesh or membrane that creates a serpentine passage for the gas as it moves upward in the separation vessel 920. Mist separators are known. One manufacturer of mist separators is Separation Products, Inc. Alvin, Texas. Separation Products, Inc. manufactures mist separators under the trade name Amistco ™.

The gaseous component leaves the separation vessel 920 via the overhead gas line 945. This gaseous component is mainly represented by methane and carbon dioxide. Trace elements ethane, nitrogen, helium and aromatics may also be present. The gas in line 945 may be referred to as sour gas. The sour gas in the gas line 945 is conveyed to the dehydration container 960.
Since the scavenger process uses an aqueous based material to separate H ₂ S from the raw gas stream 912, dehydration of the gas in line 945 is necessary prior to cryogenic carbon dioxide removal. As a result of turning the sour gas from the gas line 945 through the dehydration vessel 960, a water stream 962 is generated. This water stream 962 may be sent to a water treatment facility. Alternatively, the water stream 962 can be reinjected into, for example, the underground structure 630 of the underground structure FIG. As a further alternative, the removed water stream 962 can be treated to meet environmental standards and then be discharged as treated water into a local watershed (not shown).

Similarly, turning sour gas from line 945 through dehydration vessel 960 results in a substantially dehydrated gas stream 964. Dehydrated gas stream 964 passes through chiller 626. Chiller 626 cools dehydrated gas stream 964 to a temperature as low as approximately −30 ° F. to −40 ° F. The chiller 626 may be, for example, an ethylene or propane refrigerator. A cooled light gas stream 678 is thus produced.
This light gas stream 678 is then preferably moved through expansion device 628. Inflator 628 may be, for example, a Joule-Thompson (“J-T”) valve. This expansion device 628 serves as an expander to achieve further cooling of the light gas stream 678. The expansion device 628 further reduces the light gas stream 678 to a low temperature, for example, from approximately -70 ° F to -80 ° F. Preferably, at least partial liquefaction of the gas stream 678 is also achieved. This cooled sour gas stream is indicated by line 611.

The cooled sour gas in line 611 is directed to the distillation column. This distillation column may be, for example, the CFZ column 100 of FIGS. The cooled gas stream is then processed through an acid gas removal system. The acid gas removal system can follow, for example, the acid gas removal system 650 of FIG.
Yet another means proposed herein for the removal of organosulfur compounds having sulfhydryl (? SH) groups is through a process known as the CrystaSulf process. This CrystaSulf process is available from CrystaTech, Inc. , Developed by Austin, Texas. This CrystaSulf process removes H ₂ S from the raw gas stream by using a modified liquid phase Claus reaction process.

A “Claus process” is a process that is sometimes used in the natural gas and petroleum refining industry to recover elemental sulfur from a hydrogen sulfide-containing gas stream. Briefly, the Claus process for producing elemental sulfur includes two main sections. The first section is about 1,800 ° to 2,200 ° F. by a portion of H ₂ S burning to SO ₂ and the formed SO ₂ reacting with the remaining H ₂ S. A thermal section that produces elemental sulfur. There is no catalyst in the thermal section. The second section is the section of the catalyst where elemental sulfur is produced at a temperature between 400 ° and 650 ° F. on a suitable catalyst (such as alumina). This reaction to produce elemental sulfur is an equilibrium reaction. Therefore, there are several stages in the Claus process where separation occurs with the aim of enhancing the overall conversion of H ₂ S to elemental sulfur. Each stage involves heating, reaction, cooling and separation.

The term “CrystaSulf” refers not only to the process, but also to the solvent used during the process. CrystaSulf (R) is a non-aqueous, physical solvent that dissolves hydrogen sulfide and sulfur dioxide, allowing them to react directly with elemental sulfur. This CrystaSulf® solvent is sometimes referred to as a liquid or scrubbing liquid. In the CrystaSulf process, hydrogen sulfide is removed from the gas stream using a non-aqueous scrubbing liquid. The scrubbing liquid may be an organic solvent for elemental sulfur, such as phenylxylylethane. Generally non-aqueous solvents are alkyl-substituted naphthalenes, diarylalkanes including phenylxylylethane, such as phenyl-o-xylylethane, phenyltolylethane, phenylnaphthylethane, phenylarylalkane, dibenzylether, diphenylether, partially It can be selected from the group consisting of hydrogenated terphenyl, partially hydrogenated diphenylethane, partially hydrogenated naphthalene and mixtures thereof.
Usually, CrystaSulf (TM) solvents employs the SO ₂ as the oxidizing agent. This causes a Claus reaction (2H ₂ S + SO ₂ → 3S + 2H ₂ O) in the solvent phase. In other words, better H ₂ S removal is achieved by adding sulfur dioxide to the solvent solution.

  The CrystaSulf process is described in US Pat. No. 6,416,729. The '729 patent is entitled “Process for Removing Hydrogen Sulfide from Gas Streams Which Include or are Supplemented with Sulfur Dioxide”. The '729 patent is hereby incorporated by reference in its entirety. An additional embodiment for the CrystalSulf process is US Pat. No. 6,818,194, entitled “Process for Removing Hydrogen Sulfide From Gas Streams Which Include or Are Supplemented with Sulfur Dioxide, by Scrubbing with a Nonaqueous Sorbent”. In the issue. The '194 patent is also incorporated herein by reference.

FIG. 10 is a schematic diagram illustrating a gas processing facility 1000 for removing acidic gas from a gas stream in another embodiment. In this arrangement, hydrogen sulfide is removed from the raw gas stream 1012 upstream of the acid gas removal system 650 using a CrystaSulf process. The CrystaSulf process is part of a sulfur component removal system 1050 for removing hydrogen sulfide.
FIG. 10 illustrates a gas processing facility 1000 that receives the product gas stream 1012. This production gas stream 1012 begins with a hydrocarbon production activity that takes place in a reservoir production area, or “field” 1010. This field 1010 has the same meaning as the fields 810 and 910 described above. Hydrocarbons are produced from field 1010. The hydrocarbon will contain methane along with hydrogen sulfide. The hydrocarbon may include ethane as well as carbon dioxide.

In the gas processing facility 1000, the product gas stream 1012 flows into the sulfur component removal system 1050. The sulfur component removal system 1050 uses the above-described CrystaSulf process. In order to remove sulfur components from the raw gas stream 1012 according to the CrystaSulf process, the raw gas stream 1012 is directed to the absorber 1020. At the same time, the liquid SO ₂ is introduced into the absorber 1020 via the line 1084. Liquefied sulfur dioxide is added as an oxidizing gas.
Liquid SO ₂ is initially maintained in storage container 1080. The SO ₂ line 1082 carries liquid SO ₂ from the storage container 1080 to the line 1084 if necessary. A pump 1076 is provided along line 1082 to increase the pressure, thereby moving liquid SO ₂ to the absorber 1020.

Absorber 1020 is defined as chamber 1025. Within this absorber 1020, the raw gas stream 1012 is in contact with a liquid solvent containing SO ₂ from line 1084. The liquid settles at the bottom of the chamber 1025 and the gaseous component exits from the top of the chamber 1025. This liquid, called the adsorbent, exits through the liquid line 1022. Adsorbents generally contain a solution of sulfur and water, along with residual hydrogen sulfide and / or sulfur dioxide in addition to the trace element methane.
Liquid is directed to flask 1030 via line 1022. The flask 1030 serves to flush water and any incorporated hydrocarbon gases from the solvent. The sulfur containing solution exits the flask via bottom stream 1036. At the same time, hydrocarbon gas and traces of water vapor exit overhead line 1032.

Overhead line 1032 is carried through compressor 1034. Increasing the pressure in overhead line 1032 helps to draw water from the hydrocarbon gas. The hydrocarbon gas is then directed to the separation vessel 1040. The separation vessel 1040 is typically a gravity separator, but a hydrocyclone or Voristep separator can also be used. Water falls from the separation vessel 1040 at line 1044. The water in line 1044 is preferably directed to a treatment facility (not shown).
Hydrocarbon gas is released from separation vessel 1040 via line 1042. The hydrocarbon gas in line 1042 merges with the raw gas stream 1012. From there, the hydrocarbon gas enters the absorber 1020 again.
Referring again to flask 1030, as described, the flask releases a sulfur-containing solution via bottom stream 1036. This sulfur-containing solution moves to the cooling loop 1038. The sulfur-containing solution merges with a portion of the clear liquid from line 1058. This clear liquid may contain, for example, an additional physical solvent.

  The pressure in the cooling loop 1038 increases as the sulfur-containing solution moves through the centrifugal pump 1052. From there, the sulfur-containing solution is cooled in a PTFE heat exchanger 1054. As the sulfur-containing solution passes through the heat exchanger 1054, it is cooled to a temperature below the saturation temperature for the dissolved sulfur. The sulfur-containing solution becomes supersaturated with respect to dissolved sulfur and thus it crystallizes.

The cooled and crystallized sulfur-containing solution enters the crystallizer 1055. Specifically, the sulfur-containing solution from line 1038 is directed to the bottom of crystallizer 1055. The cooled sulfur-containing solution contacts sulfur crystals present in the precipitation zone 1059 in the crystallizer 1055. This crystal serves to seed the supersaturated sulfur solution, resulting in the precipitation of dissolved sulfur. This creates a sulfur slurry.
The sulfur slurry exits crystallizer 1055 via sulfur slurry line 1056. The sulfur slurry in line 1056 is delivered to filter 1060. This filter 1060 separates the sulfur slurry into pure solid sulfur and a clear liquid. Solid sulfur removal is represented by line 1062. The clear liquid is discharged as filtrate through line 1064 and recycled back to the crystallizer 1055. A pump 1066 is preferably provided to carry the clear liquid back to the crystallizer 1055.

The clear liquid rises to the top of the crystallizer. A portion of the clear liquid is derived from crystallizer 1055 via line 1058. The clear liquid in line 1058 merges with the sulfur solution 1036 from the flask to form a cooling loop 1038 as discussed above. A separated portion of the clear liquid is extracted from the top of the crystallizer 1055 via line 1072. The liquid extracted from the line 1072 is heated via the heat exchanger 1074. The heated liquid merges with sulfur dioxide from line 1082. The heated liquid 1074 is withdrawn via a booster pump 1076 and then guided again into the chamber 1025 of the absorber 1020.
It should be understood that the CrystaSulf process described in connection with the sulfur component removal system 1000 is merely exemplary. Other CrystaSulf processes can also be used, such as those described in the incorporated US Pat. No. 6,416,729 and US Pat. No. 6,818,194. Regardless of the process, an overhead gas stream 1045 is generated from the absorber 1020.

The overhead gas stream 1045 contains mainly methane and carbon dioxide. Trace elements ethane, nitrogen, helium and aromatics may also be present. Sulfur components are extracted and conveyed via line 1062. Overhead gas stream 1045 may be referred to as sour gas. The sour gas in the gas stream 1045 is preferably conveyed to the dehydration vessel 1060. However, because the CrystaSulf process is non-aqueous, dewatering can occur before the raw gas stream 1012 enters the sulfur component removal system 1050.
Overhead gas stream 1045 passes through chiller 626. Chiller 626 cools gas stream 1045 to a temperature as low as approximately −30 ° F. to −40 ° F. The chiller 626 may be, for example, an ethylene or propane refrigerator. A cooled light gas stream 678 is thus produced.

  Light gas stream 678 is then preferably moved through expansion device 628. The expansion device 628 may be, for example, a Joule-Thompson (“J-T”) valve or other device described in connection with FIG. The expansion device 628 further reduces the temperature of the light gas stream 678 to a low temperature, for example, from approximately −70 ° F. to −80 ° F. Preferably, at least partial liquefaction of the gas stream 678 is also achieved. The cooled gas stream travels through line 611.

The cooled sour gas in line 611 is directed to the distillation column. The distillation column may be, for example, the CFZ column 100 of FIGS. The cooled sour gas in line 611 is then processed through an acid gas removal system. The acid gas removal system can follow the acid gas removal system 650 of FIG. 6 used, for example, to remove carbon dioxide.
Two additional methods that can be used to remove at least moderate levels of hydrogen sulfide upstream of the cryogenic distillation column include the use of an adsorbent bed. One method employs thermal swing adsorption and the other utilizes pressure swing adsorption. The adsorption bed is a molecular sieve. In either case, the molecular sieve is regenerated.

Molecular sieves are often used for dehydration, but can also be used for H ₂ S and mercaptan removal. In many cases, these uses are combined in a single packed bed where the 4A molecular sieve material layer is on top for dehydration and the 13X molecular sieve material layer removes H ₂ S and mercaptan. Located at the bottom for. Thus, the raw gas stream is both dried and desulfurized.

FIG. 11 depicts a schematic diagram illustrating a gas processing facility 1100 for removing acid gases from a gas stream in another embodiment. In this arrangement, hydrogen sulfide is removed from the raw gas stream 624 using a thermal swing adsorption system 1150 upstream of the acid gas removal system 650.
The gas processing facility 1100 generally operates in accordance with the gas processing facility 600 of FIG. At this point, the dehydrated gas stream 624 is delivered to a sulfur component removal system. From there, sour gas composed primarily of methane and carbon dioxide is cooled and delivered to the acid gas removal system 650 via line 611. However, instead of using the solvent system 605 with the absorber as a sulfur component removal system, a thermal swing adsorption system 1150 is used. This thermal swing adsorption system 1150 provides at least partial separation of hydrogen sulfide from the dehydrated gas stream 624.

The thermal swing adsorption system 1150 selectively adsorbs hydrogen sulfide and other sulfur components by using an adsorption bed 1110 while turning a light gas stream composed of methane and carbon dioxide. The light gas stream is shown being released at line 1112. Light gas stream 1112 is delivered as a sour gas stream to a distillation column, such as column 100 of FIG. 1, for separating carbon dioxide from methane.
Prior to entering the cryogenic distillation column 100, the light gas stream 1112 is preferably pre-cooled. In the exemplary gas processing facility 1100, the light gas stream 1112 passes through the refrigeration unit 626 and then through the expansion device 628. The expansion device 628 may be, for example, a Joule-Thompson (“J-T”) valve. Preferably, at least partial liquefaction of the light gas stream 1112 is achieved in connection with cooling. A cooled sour gas stream is generated and directed to the acid gas removal system 650 via line 611.

Referring again to the thermal swing adsorption system 1150, the adsorption bed 1110 in the thermal swing adsorption system 1150 is preferably a molecular sieve made from zeolite. However, other adsorbent beds such as beds made from silica gel may be employed. Those skilled in the art of hydrocarbon gas separation will understand that the choice of adsorbent bed will typically depend on the composition of the contaminants being removed. In this case, the pollutant is mainly hydrogen sulfide.
During operation, an adsorbent bed 1110 will be present in the pressurized chamber. Adsorption bed 1110 receives dehydrated gas stream 624 and adsorbs hydrogen sulfide and other sulfur components along with an amount of carbon dioxide. The adsorption bed 1110 in the adsorption system 1150 is replaced with a regenerated bed once the bed is substantially saturated with H ₂ S. H ₂ S is released from the bed 1110 in a reaction in which the dried and heated gas is used to heat the bed. Suitable gases include a portion of the overhead methane stream 112, heated nitrogen, or other available fuel gas.

Block 1140 depicts a regeneration chamber for the adsorption bed. The regeneration chamber 1140 receives the dried and heated gas 1132. In the arrangement of FIG. 11, dry gas 1132 is received from overhead methane stream 112. Overhead methane stream 112 contains primarily methane, but may also contain traces of nitrogen and helium. The overhead methane stream 112 can be compressed to increase the pressure of the gas in the regeneration chamber. A pressure booster is indicated at 1130. However, regeneration occurs primarily through increased temperatures, but is generally enhanced at lower pressures.
A 10-15 percent overhead methane stream 112 may be required for full regeneration. The regeneration chamber 1140 emits a heated, dry fluid stream 1142. This dry fluid stream 1142 is guided to the solid adsorbent bed 1110 and acts as a regenerative stream. Dry fluid stream 1142 is mainly composed of methane, some CO ₂ also contains.

  Preferably at least three adsorbent beds are employed for the thermal swing regeneration cycle. The first floor is used for adsorption as indicated at 1110, the second floor is regenerated in the regeneration chamber 1140, the third floor is already regenerated, and the first floor 1110 Is stored for use in the adsorption system 1150 when it is substantially saturated. Therefore, a minimum of three floors are used in parallel for more effective work. These beds may be filled with silica gel, for example.

As seen in FIG. 11, the concentrated H ₂ S gas stream is discharged from the adsorption system 1110 via line 1114. The concentrated hydrogen sulfide stream 1114 also acts as a regeneration stream. The regenerative stream 1114 mainly contains CH ₄ and H ₂ S, but most likely also contains traces of carbon dioxide and possibly some heavy hydrocarbons. In one aspect, the regenerative stream 1114 is cooled using a refrigeration unit 1116. This causes at least partial liquefaction of the regenerative stream 1114. Recycle stream 1114 is then introduced into separator 1120. Separator 1120 is preferably a gravity separator that separates the water in regenerative stream 1114 from light gas. Light gases typically include methane, hydrogen sulfide, and carbon dioxide.

Light gas is released from the top of the separator 1120 (shown schematically at line 1122). Light gas released from separator 1120 in line 1122 returns to dehydrated gas stream 624. At the same time, water, heavy hydrocarbons (mainly ethane) and dissolved hydrogen sulfide are released from the bottom of separator 1120 (shown schematically at line 1124). In some implementations, the recycle gas in line 1122 may require treatment for H ₂ S to ensure that it is not recycled through the system.
Note that the gas processing facility 1100 may not include the dehydration unit 620. Water will fall from the solid adsorbent bed 1110 with the regeneration stream 1114 and will not move to the sour gas stream in line 611. The water further falls from the separator 1120 with the hydrogen sulfide in line 1124. Separation of water from the sulfur compound can then be accomplished using, for example, a sour water stripper or other separator (not shown).

  In one application, a turbine (not shown) can be driven by burning spent gas from the regeneration gas heater 1140. The turbine can then drive an open loop compressor (eg, compressor 176 of FIG. 1). By removing the waste heat from such turbines and using it to preheat the regeneration gas for the hydrogen sulfide recovery process (eg, in line 1132), the regeneration gas heater 1140 is further integrated into the acid gas removal process. May be. Similarly, heat from the overhead compressor 114 can be used to preheat the regeneration gas used for the hydrogen sulfide recovery process.

It is here observed that the regeneration gas contains H ₂ S desorbed from the solid bed 1110. By contacting this gas with a solvent, H ₂ S can be removed and methane and any other hydrocarbons can be recovered. In this way, the BTU value of the gas can be recovered.
As described, pressure swing adsorption can also be used to remove hydrogen sulfide and other sulfur components upstream of the acid gas removal facility. Pressure swing adsorption, or “PSA”, generally refers to the process by which contaminants adsorb to a solid adsorbent bed. After saturation, the solid adsorbent is regenerated by reducing its pressure. By reducing the pressure, contaminants are released as a low pressure flow.

  FIG. 12 provides a schematic diagram of a gas processing facility 1200 that uses pressure swing adsorption for removal of hydrogen sulfide. The gas processing facility 1200 generally operates in accordance with the gas processing facility 600 of FIG. At this point, the dehydrated gas stream 624 is cooled and then delivered to the acid gas removal system 650 via the sour gas line 611. However, instead of using the physical solvent contact system 605 with the contact tower 670 to remove hydrogen sulfide, a pressure swing adsorption system 1250 is used. This pressure swing adsorption system 1250 provides at least partial separation of hydrogen sulfide from the raw gas stream 624.

Similar to the thermal swing adsorption system 1150, the pressure swing adsorption system 1250 uses the adsorption bed 1210 to selectively adsorb H ₂ S while releasing methane gas. The adsorbent bed 1210 is preferably a molecular sieve made from zeolite. However, other adsorbent beds such as beds made from silica gel may be employed. Those skilled in the art of hydrocarbon gas separation will again understand that the selection of the adsorbent bed typically depends on the composition of the raw gas stream 624.
As can be seen in FIG. 12, the adsorption system 1250 emits methane gas via the light gas stream 1212. This light gas stream 1212 is conveyed via the refrigeration unit 626 and then preferably via the Joules-Thompson valve 628 before entering the cryogenic distillation column 100. At the same time, the concentrated hydrogen sulfide stream is discharged from the adsorption bed 1210 via line 1214.

In operation, the adsorbent bed 1210 in the pressure swing adsorption system 1250 resides in a pressurized chamber. Adsorption bed 1210 receives dehydrated gas stream 624 and adsorbs H ₂ S along with any remaining water and any heavy hydrocarbons. Trace amounts of carbon dioxide can also be adsorbed. Adsorbent bed 1210 is replaced when bed 1210 is saturated with hydrogen sulfide and other sulfur components. H ₂ S (heavy hydrocarbons, if any) will be released from the bed in response to the decreasing pressure in the pressurized chamber. A concentrated hydrogen sulfide stream 1214 is then released.

In most cases, the majority of hydrogen sulfide and other contaminants in the concentrated hydrogen sulfide stream 1214 are released from the adsorbent bed 1210 by reducing the pressure in the pressurized chamber to atmospheric pressure. However, in some extreme cases, the pressure swing adsorption system 1250 can be assisted by applying subatmospheric pressure to the concentrated hydrogen sulfide stream 1214 using a vacuum chamber. This is indicated at block 1220. In the presence of lower pressure, sulfur components and heavy hydrocarbons desorb from the solid matrix that makes up the adsorbent bed 1210.
The mixture of water, heavy hydrocarbons and hydrogen sulfide will exit the vacuum chamber 1220 via line 1222. This mixture enters separator 1230. The separator 1230 is preferably a gravity separator that separates heavy hydrocarbons and water from hydrogen sulfide. The liquid component is discharged from the bottom (represented schematically by line 1234). Any heavy hydrocarbons in line 1234 may be sent for commercial sale after treatment for dissolved H ₂ S. Gas form hydrogen sulfide is discharged from the top of the separator 1230 (shown schematically by line 1232). H ₂ S in line 1232 is sent to a sulfur recovery unit (not shown) or injected into the underground structure as part of the acid gas injection.

  The pressure swing adsorption system 1250 can rely on multiple beds in parallel. The first floor 1210 is used for adsorption. This is known as the floor to use. The second floor (not shown) is regenerated through pressure reduction. The third bed has already been regenerated and stored for use in the adsorption system 1250 when the first bed 1210 is substantially saturated. Therefore, a minimum of three floors can be used in parallel for more effective work. These beds may be filled with, for example, activated carbon or molecular sieves.

The pressure swing adsorption system 1250 may be a fast cycle pressure swing adsorption system. In the so-called “fast cycle” process, the cycle time can be as short as a few seconds. High speed cycle PSA (“RCPSA”) units are particularly advantageous because they are much smaller than ordinary PSA equipment. Note that pretreatment may be required for the injected gas. Alternatively, the active material can be preserved by using a sacrificial layer of material at the top of the packed bed.
In one aspect, a combination of thermal swing regeneration and pressure swing regeneration may be employed.

  Another method proposed here for removing hydrogen sulfide upstream of an acid gas removal system is an adsorption dynamic separation, or process called AKS. AKS employs a relatively new type of solid adsorbent that depends on the rate at which a particular species adsorbs on a structured adsorbent relative to other species. This is in contrast to the traditional equilibrium controlled swing adsorption process where selectivity is mainly given by the equilibrium adsorption properties of the solid adsorbent. In the latter case, adsorption isotherms that compete for light product in the micropores or free volume of the adsorbent are not preferred.

In a kinetically controlled swing adsorption process, selectivity is mainly given by the diffusion properties of the adsorbent and by the transport diffusion coefficient within the micropore. Adsorbents have “kinetic selectivity” for one or more gas components. As used herein, the term “kinetic selectivity” is defined as a single component diffusion coefficient, D (m ² / sec), and the ratio of two different species. These single component diffusion coefficients are also known as Stefan-Maxwell transport diffusion coefficients measured for a given adsorbent that results in a given pure gas component. Thus, for example, the kinetic selectivity of component A relative to component B for a particular adsorbent is the same as D _A / D _B. A single component diffusion coefficient for a material can be determined by tests well known in the adsorbent material art.
A preferred means for measuring kinetic diffusion coefficients is described by Reyes et al. In “Frequency Modulation Methods for Diffusion and Adsorption Measurements in Porous Solids”, J. Phys. Chem. B. 101, pp. 614-622 (1997). The frequency response technique described is used. In a kinetically controlled separation, the kinetic selectivity (ie, D _A / D _B ) of the first component (eg, component A) relative to the second component (eg, component B) of the selected adsorbent. ) Is preferably greater than 5, more preferably greater than 20, even more preferably greater than 50.

  The adsorbent is preferably a zeolitic material. Non-limiting examples of zeolites with suitable pore sizes for removing heavy hydrocarbons include MFI, faujasite type, MCM-41 and Beta. The Si / Al ratio of the zeolite utilized in the method embodiment of the present invention for heavy hydrocarbon removal is preferably about 20 to about 1,000 to prevent excessive adsorbent deposition; Preferably it is about 200 to about 1,000. Additional technical information about the use of adsorptive dynamic separation for the separation of hydrocarbon gas components is US Patent Publication No. 2008/0282884, the entire disclosure of which is incorporated herein by reference.

FIG. 13 is a schematic diagram illustrating a gas processing facility 1300 of the present invention in another embodiment. In this arrangement, hydrogen sulfide is removed from the gas stream upstream of the acid gas removal system 650 using an adsorption bed 1310 that utilizes adsorption dynamic separation.
The gas processing facility 1300 generally operates in accordance with the gas processing facility 600 of FIG. 6A. At this point, the dehydrated gas stream 624 is cooled in the pre-refrigeration unit 625 and then delivered to the acid gas removal system 650 via the sour gas stream in line 611. However, instead of using a physical solvent contact system 605 upstream of the acid gas removal system 650 with the contact tower 670 to remove hydrogen sulfide, an AKS solid adsorbent bed 1310 is used. This adsorption bed 1310 preferentially adsorbs hydrogen sulfide.

In the current application of adsorption dynamic separation, the hydrogen sulfide component will be retained in the adsorption bed 1310. This means that H ₂ S is recovered at a lower pressure. This adsorbent bed 1310 may be used in conjunction with pressure swing adsorption or fast cycle pressure swing adsorption. As the pressure decreases, the liquid natural gas stream 1314 is discharged from the solid adsorbent bed at a low pressure. Liquid natural gas stream 1314 contains the majority of the sulfur component from dehydrated gas stream 624 and may also contain heavy hydrocarbons and traces of carbon dioxide.
An additional distillation column is required to separate hydrogen sulfide and carbon dioxide from heavy hydrocarbons. The distillation vessel is shown at 1320. The distillation vessel 1320 may be a tray column or packed column used as a contaminant purification system, for example. Hydrogen sulfide and carbon dioxide are released via overhead line 1324. Line 1324 preferably merges with acid gas line 646 for acid gas injection into reservoir 1349. Sour heavy hydrocarbons and most water molecules exit distillation vessel 1320 via bottom line 1322. The heavy hydrocarbon may be in the form of liquid natural gas, ie ethane, optionally propane. Liquid natural gas is processed for removal of H ₂ S and captured for sale.

  It should be noted that the adsorption dynamic separation process of system 1300 can be more advantageous for recovering hydrogen sulfide and heavy hydrocarbons from natural gas streams produced under large excess pressure. In this situation, the sour gas in line 611 has sufficient pressure to be processed by the cryogenic distillation column 100. An example of overpressure is a pressure exceeding 400 psig.

Adsorption bed 1310 emits a light gas stream 1312. The gas in stream 1312 is primarily composed of methane and carbon dioxide. The light gas in stream 1312 is preferably cooled before entering cryogenic distillation column 100. In the exemplary gas processing facility 1300, light gases in stream 1312 pass through refrigeration unit 626 and then through expansion device 628. A cooled sour gas stream is generated in line 611 that is directed to the acid gas removal system 650.
In another general approach for removing heavy hydrocarbons, heavy hydrocarbons are extracted from “downstream” bottom stream 646 from distillation column 100. In one example, an adsorption dynamic separation process is employed downstream of the cryogenic distillation column.

  FIG. 14 depicts a schematic diagram of a gas processing facility 1400 that employs an adsorption dynamic separation process. This gas processing facility 1400 generally follows the gas processing facility 1300 of FIG. However, in this example, instead of using the AKS solid adsorption bed 1310 upstream of the acid gas removal system 650, an AKS solid adsorption bed 1410 is used downstream of the acid gas removal system 100.

In FIG. 14, it can be seen that acid gases, namely hydrogen sulfide and carbon dioxide, are removed from the distillation column 100 as a liquefied bottom acid gas stream 642. This liquid stream 642 may be sent via a reboiler 643 where gas containing a trace amount of methane is redirected and returned to the tower 100 as a gas stream 644. Residual liquid mainly composed of acid gas is discharged via acid gas line 646.
Acid gas from line 646 is delivered to AKS solid adsorbent bed 1410. The acid gases remain cold and exist as a liquid phase while they pass through the bed 1410. Hydrogen sulfide and any heavy hydrocarbons are removed from the acid gas and discharged as a liquid natural gas stream 1412 via line 1412. At the same time, acid gas passes through the AKS solid adsorbent bed 1410 and is released as a bottom acid gas stream 1414.

The acid gas in the bottom acid gas stream 1414 remains primarily in the liquid phase. The liquefied acid gas in line 1414 is mainly CO ₂ and may be vaporized. Alternatively, the liquefied acid gas in line 1414 can be injected into the underground structure via one or more acid gas injection (AGI) wells shown at block 649. In this example, the acid gas in line 646 preferably passes through pressure booster 648.
Note that the liquid natural gas stream 1412 contains heavy hydrocarbons and hydrogen sulfide and traces of carbon dioxide. Accordingly, a distillation process is performed to separate H ₂ S and CO ₂ from the liquid natural gas stream 1412. A distillation vessel is shown at 1420. H ₂ S and a small amount of CO ₂ gas are released from the distillation vessel 1420 via the overhead line 1424. Line 1424 preferably merges with bottom acid gas stream 1414 for acid gas injection into reservoir 649. Heavy hydrocarbons exit container 1420 via bottom line 1422 and are captured for sale.

FIG. 15A is a schematic diagram of a gas processing facility 1500 of the present invention in another embodiment. In this arrangement, hydrogen sulfide is removed from the gas stream downstream of the acid gas removal system 650 using an extractive distillation process. The extractive distillation process is represented by box 1550.
This exemplary gas processing facility 1500 generally follows the gas processing facility 600 of FIG. At this point, the dehydrated gas stream 624 is cooled and then delivered to the acid gas removal system 650 via the sour gas line 611. However, instead of using the solvent contact system 605 with the contact tower upstream of the acid gas removal system 650, an extractive distillation process is used downstream of the acid gas removal system 650.

It can be seen in FIG. 15A that the chilled sour gas passes through line 611 and enters the acid gas removal system 650. The chilled sour gas in line 611 has the same composition as the dehydrated raw gas stream 624. The sour gas in line 611 contains methane along with hydrogen sulfide and carbon dioxide. Ethane and trace elements nitrogen, helium and aromatics may also be present.
Sour gas in line 611 first enters column 100. This may be the same as the CFZ tower 100 of FIGS. As described above, the CFZ tower 100 separates sour gas into an overhead methane stream 112 and a bottom acid gas stream 642. In this example, the bottom acid gas stream 642 includes both carbon dioxide and hydrogen sulfide.

  The bottom stream 642 may be sent through a reboiler 643. From there the fluid containing methane is redirected and returns to the tower 100 as a hydrocarbon gas stream 644. Residual fluid composed primarily of hydrogen sulfide and carbon dioxide is discharged via acid gas line 646. The material in the acid gas line 646 is in liquid form and enters the extractive distillation system 1550.

FIG. 15B is a detailed schematic diagram of a gas processing facility 1550 for the extractive distillation process. It can be seen that line 646 carries acid gas to the extractive distillation facility 1550. In the exemplary arrangement of FIG. 15B, three extractive distillation columns 1510, 1520 and 1530 are shown. However, it should be understood that more than three columns can be employed.
The extractive distillation column 1510 is a propane recovery column. This propane recovery column 1510 mixes the hydrocarbon solvent and acid gas stream 646 in a vessel. The temperature of the first column 1510 is typically between −100 ° and 50 ° F. In the propane recovery column 1510, the solvent absorbs hydrogen sulfide, which causes the solvent to leave the column 1510 as the solvent bottom stream 1514. This will also contain some carbon dioxide as well as heavy hydrocarbons. At the same time, carbon dioxide and traces of light hydrocarbons exit column 1510 via overhead stream 1554. Carbon dioxide in stream 1554 can be combined with acid gas injection line 1552 for injection into an underground structure (649 in FIG. 15A).

The solvent bottom stream 1514 enters the second extractive distillation column 1520. The second extractive distillation column 1520 is a CO ₂ removal column. The temperature in the CO ₂ removal column 1520 is typically between 0 ° and 250 ° F., which is higher than the temperature in the propane recovery column 1510. In the CO ₂ removal column 1520, the solvent and heavy hydrocarbons leave the column 1520 as a second solvent bottom stream 1524. At the same time, the carbon dioxide exits the second column 1520 as an overhead CO ₂ stream 1552. This overhead CO ₂ stream 1552 is preferably used for enhanced oil recovery.
The final column 1530 is shown in FIG. 15B. The final column 1530 is an additive recovery column. This additive recovery column 1530 uses a distillation scheme that separates heavy hydrocarbon components known as “liquid natural gas” from the solvent. The temperature in the third column 1530 is typically between 80 ° F. and 350 ° F., which is higher than the temperature in the second column 1530. Liquid natural gas exits column 1530 via line 1532 and is carried to a processing unit to remove any remaining H ₂ S and CO ₂ . This processing unit may be a liquid / liquid extractor, in which amine is used, for example, for H ₂ S / CO ₂ removal.

  The solvent leaves the additive recovery column 1530 as the bottom solvent stream 1534. This bottom solvent stream 1534 represents the regenerated additive. Most of the bottom solvent stream 1534 is reintroduced to the first column 1510 for the extractive distillation process. Excess solvent from stream 1534 may be combined with liquid natural gas stream 1532 for processing via line 1536.

Referring again to FIG. 15A, the carbon dioxide in line 1554 is combined with CO ₂ in line 1552 and passes through pressure booster 648 and then one or more acid gas injection (AGI) wells indicated at block 649. It is preferable to be injected into the underground structure via
As shown in the figure, several methods can be used to remove the sulfur component in connection with the acid gas removal process. In general, the method chosen depends on the state of raw natural gas or the gas being treated. For example, when the H ₂ S concentration is less than about 0.1%, dehydration is necessary anyway, so the combination of molecular sieve methods can be the best. The molecular sieve added the advantage of removing some CO ₂ that could promote “dirty” initiation.

If there is approximately 0.1% to 10% H ₂ S in the injection gas, a physical solvent such as Selexol ™ may be the best option. Ideally, the solvent is dry because it can be used to dry the injection gas to a certain level. Due to the CFZ process, the gas may require further dehydration with a (smaller) molecular sieve unit. The concentrated H ₂ S stream from the Selexol unit may be processed in a sulfur recovery unit (SRU) or may be compressed and combined with the CFZ bottom stream for underground disposal.
It should be understood that the above method for hydrogen sulfide removal can be applied in conjunction with any acid gas removal process, not just a process utilizing a “controlled freezing zone” tower. Other cryogenic distillation columns may be employed. In addition, other cryogenic distillation processes such as bulk prep can be used. The bulk fractionation tower is similar to the CFZ tower 100 of FIG. 1, but without an intermediate freezing zone. Bulk preparative columns typically operate at higher pressures than CFZ column 100, such as above 700 psig, thereby avoiding the formation of CO ₂ solids. However overhead methane stream 112 may contain significant amounts of CO _2. In either instance, if the dehydrated gas stream 624 contains approximately greater than 3% C ₂ or heavier hydrocarbons, it may be desirable to utilize a separate process for hydrogen sulfide removal.

It will be apparent that the invention described herein has been well calculated to achieve the advantages and advantages described above, but the invention may be modified without departing from its spirit. It should be understood that variations and modifications can be accepted. An improved acid gas removal process operation is achieved using a controlled freezing zone. This improvement provides a design for removing H ₂ S to very low levels in the production gas.

Claims (45)

A system for removing acid gases from a sour gas stream,
Acidity to receive the sour gas stream using a cryogenic distillation column that separates the sour gas stream into an overhead gas stream composed primarily of methane and a liquefied bottom acidic gas stream composed primarily of carbon dioxide A gas removal system;
A system comprising a sulfur component removal system upstream of an acid gas removal system that receives the raw gas stream and generally separates the raw gas stream into a hydrogen sulfide stream and a sour gas stream.   The system of claim 1, wherein the raw gas stream contains between about 4 ppm and 100 ppm sulfur components.   The system of claim 2, wherein the cryogenic acid gas removal system further comprises a heat exchanger for cooling the sour gas stream prior to entering the cryogenic distillation column. A cryogenic distillation column having a controlled freezing zone in the middle of the lower distillation zone and receiving a cryogenic liquid spray composed mainly of methane;
Refrigeration equipment downstream of the cryogenic distillation tower for cooling the overhead methane stream and returning a portion of the overhead methane stream as a cryogenic spray to the cryogenic distillation tower, the tower receiving the sour gas stream and then passing it overhead The system of claim 3, wherein the system separates into a methane stream and a bottom acid gas stream.   The system of claim 2, wherein the acid gas removal system is a bulk fractionation system.   The system of claim 2, wherein the sulfur component removal system comprises a chemical solvent system.   The system of claim 6, wherein the chemical solvent comprises methyldiethanolamine (MDEA), a selective amine from the Flexsorb® family of solvents, or a combination thereof.   The system of claim 6, wherein the chemical solvent system utilizes a plurality of co-current contactors. The co-current contactor of the chemical solvent system
A first portion of a first co-current contactor designed to receive a raw gas stream and (ii) a second liquid solvent, further comprising: (iii) consisting primarily of methane A first co-current contactor designed to discharge an optionally sweetened gas stream and (iv) a first partially filled gas treatment solution;
(Ii) designed to receive a first partially sweetened gas stream and (ii) a third liquid solvent; (iii) a second partially sweetened gas stream; and (iv) A second co-current contactor designed to release a second partially filled gas treatment solution;
(I) a previous partially sweetened gas stream and (ii) a final sweetened gas stream designed to receive the regenerated liquid solvent, and (iii) composed primarily of methane, and (Iv) a final co-current contactor designed to release the final lightly filled gas treatment solution;
A hydrogen sulfide stream is at least partially composed of a first partially filled gas treatment solution and a second partially filled gas treatment solution;
The regenerated liquid solvent is at least partially composed of a regenerated solvent stream that serves to substantially remove hydrogen sulfide from at least the first partially filled gas treatment solution and the second partially filled gas treatment solution. To be
The system according to claim 8.   The chemical solvent system of claim 9, further comprising a liquid solvent regenerator designed to receive at least a first partially filled gas treatment solution and produce a regenerated liquid solvent.   The gas treatment facility of claim 9, wherein the liquid solvent and the regenerated liquid solvent comprise a hindered amine, a tertiary amine, or a combination thereof. The co-current contactor of the chemical solvent system
A first co-current contactor, a second co-current contactor, and a final co-current contactor;
Each of these co-current contactors is designed to (i) receive a raw gas stream and a liquid solvent, and (ii) release a sweetened gas stream and a separate packed gas processing solution;
The first co-current contactor, the second co-current contactor and the final co-current contactor are designed to deliver each sweetened gas stream in series as a progressively sweetened gas stream And
The final co-current contactor, the second co-current contactor, and the first co-current contactor are arranged to deliver the respective gas treatment solution in series as an increasingly rich gas treatment solution. ,
The system according to claim 8. A first co-current contactor receives (i) an initial gas stream and (ii) a second liquid solvent, (iii) a first partially sweetened gas stream and (iv) a first Release the partially filled gas treatment solution,
A second co-current contactor receives (i) a first partially sweetened gas stream from the first co-current contactor; (ii) receives a third liquid solvent; (iii) Discharging a second partially sweetened gas stream and (iv) a second partially filled gas treatment solution;
The final co-current contactor receives (i) the previous partially sweetened gas stream and (ii) the regenerated liquid solvent, (iii) the final sweetened gas stream and (iv) Release the final lightly filled gas treatment solution,
The method of claim 12.   The system of claim 2, wherein the sulfur component removal system comprises a physical solvent system that utilizes a physical solvent.   The system of claim 14, wherein the physical solvent comprises N-methylpyrrolidone, propylene carbonate, methyl cyanoacetate, refrigerated methanol, tetramethylene sulfone, Selexol ™, or combinations thereof. An absorber for receiving a raw gas stream and separating the raw gas stream into a sour gas stream and a hydrogen sulfide stream, wherein the hydrogen sulfide stream comprises hydrogen sulfide and a liquid physical solvent;
At least two separators for treating the hydrogen sulfide stream to separate hydrogen sulfide from the physical solvent;
A regenerator for regenerating the physical solvent and returning at least a portion of the physical solvent to the absorber. The sulfur component removal system includes at least one solid adsorbent bed for substantially adsorbing the sulfur component, and the sulfur component is released as a hydrogen sulfide stream when the at least one solid adsorbent bed is regenerated, said at least one The system of claim 2, wherein the two solid adsorbent beds substantially pass methane and CO ₂ as a sour gas stream.   18. A system according to claim 17, wherein the solid adsorbent bed (i) is made of zeolitic material or (ii) comprises at least one molecular sieve.   The system of claim 18, wherein the sulfur component removal system further comprises a separator for separating carbon dioxide from the sulfur component in the hydrogen sulfide stream.   The system of claim 17, wherein the regeneration is part of a pressure swing adsorption process. The at least one solid adsorbent bed comprises at least three adsorbent beds;
A first of the at least three adsorbent beds is used to adsorb hydrogen sulfide;
Regeneration is performed in a second adsorption bed of at least three adsorption beds,
21. The system of claim 20, wherein a third of the at least three beds is set aside as a replacement for the first of the at least three beds.   The sulfur component removal system further includes a vacuum for applying a negative relative pressure to the first of the at least three adsorption beds before the hydrogen sulfide stream enters the separator, The system of claim 21, wherein the system assists in the desorption of hydrogen sulfide from the first adsorption bed.   The system of claim 17, wherein the regeneration is part of a thermal swing adsorption process. The at least one solid adsorbent bed comprises at least three adsorbent beds;
A first of the at least three beds is used to adsorb hydrogen sulfide;
Regeneration is performed in a second adsorption bed of at least three adsorption beds,
24. The system of claim 23, wherein a third of the at least three adsorption beds is set aside as a replacement for the first of the at least three adsorption beds. A sulfur component removal system is configured to: (i) receive the regeneration gas, (ii) heat the regenerated gas, and (iii) apply heat from the heat regenerated gas to the second adsorption bed. A regenerative gas heater for desorbing hydrogen sulfide from the adsorption bed of
A regenerative gas heater releases the gas stream to the first solid adsorbent bed, thereby separating the gas stream into a hydrogen sulfide stream and a sour gas stream;
25. The system of claim 24, wherein the sulfur component removal system further comprises a separator for separating any methane from the hydrogen sulfide stream. 26. The system of claim 25, wherein the sulfur component removal system further includes a cooler for receiving the hydrogen sulfide stream and cooling the hydrogen sulfide fluid stream before it enters the separator.   The sulfur component removal system includes at least one solid adsorbent bed for substantially adsorbing hydrogen sulfide, wherein the hydrogen sulfide is released as a hydrogen sulfide stream when the at least one solid adsorbent bed is regenerated, said at least one The system of claim 2, wherein the two solid adsorbent beds substantially pass methane and carbon dioxide as a sour gas stream.   28. The system of claim 27, wherein the at least one solid adsorption bed is an adsorption dynamic separation bed.   The system of claim 2, wherein the sulfur component removal system comprises a redox system. Redox system
A contactor for receiving a raw gas stream and a chelated metal oxide, wherein the chelated metal oxide is mixed with the raw gas stream to cause a reductive oxidation reaction, and (i) the chelated reduced metal and elemental sulfur A bottom aqueous solution comprising, and (ii) a contactor that discharges an overhead gas stream composed of methane and carbon dioxide;
An oxidizer for receiving an aqueous bottom solution with air and providing a chamber for an oxidation reaction, releasing an aqueous chelated metal mixture with elemental sulfur;
A separator for receiving an aqueous chelated aqueous metal mixture with elemental sulfur and separating the aqueous chelated metal mixture with elemental sulfur into a regenerated chelated metal catalyst solution and elemental sulfur;
30. A system for directing at least a portion of the regenerated chelated metal catalyst solution back to the contactor.   The system of claim 2, wherein the sulfur component removal system comprises a scavenger system. The scavenger system
A line where the liquid scavenger mixes with the raw gas stream;
32. The system of claim 31, wherein a separation vessel for separating a raw gas stream into a sour gas stream and a used scavenger stream, wherein the used scavenger stream comprises a separation vessel containing hydrogen sulfide and a liquid scavenger. .   The system of claim 2, wherein the overhead gas stream includes not only methane but also helium, nitrogen, or a combination thereof.   The system of claim 2, wherein the sulfur component removal system comprises a system for performing a CrystaSulf process. Sulfur component removal system
(I) an absorber for receiving oxidant gas as a sour gas stream and (ii) scrubbing liquid, wherein the oxidant gas mixes with the raw gas stream to cause a chemical reaction, thereby (i) releasing the sour gas stream; (Ii) an absorber that releases an adsorbent composed of water, hydrogen sulfide, and oxidizing gas;
A flask for separating the liquid adsorbent into (i) an overhead gas stream composed primarily of hydrocarbon gas and any entrained water vapor and (ii) a sulfur solution;
A separation vessel for separating water from the hydrocarbon gas and delivering the hydrocarbon gas back into the raw gas stream;
A crystallizer for receiving a sulfur solution, wherein sulfur crystals are seeded in the sulfur solution in the precipitation zone to cause precipitation of dissolved sulfur, and (i) sulfur from the lower part of the crystallizer. Discharging the slurry; (ii) a crystallizer for inducing liquid from the upper part of the crystallizer as oxidizing gas and directing a part of the liquid back to the absorber;
35. The system of claim 34, further comprising a filter for separating the sulfur slurry into pure solid sulfur and a clear liquid, wherein the clear liquid is induced to return to the crystallizer. A dehydration device for receiving the raw gas stream prior to passing through the sulfur removal system and separating the raw gas stream into a dehydrated raw gas stream and a stream composed of a substantially aqueous fluid; A system,
The system of claim 2, wherein the raw gas stream received by the sulfur component removal system is a dehydrated raw gas stream. An acid gas removal system for receiving a sour gas stream, wherein the sour gas stream contains less than about 10% sulfur components, the sour gas stream comprising an overhead gas stream composed primarily of methane, and mainly carbon dioxide and An acid gas removal system utilizing a cryogenic distillation column that separates into a liquid bottom acid gas stream composed of sulfur components;
A sulfur component removal system downstream of an acid gas removal system, comprising a sulfur component removal system that receives a bottom acid gas stream and generally separates the bottom acid gas stream into a carbon dioxide fluid stream and a hydrogen sulfide stream. A system for removing acid gases from a stream.   38. The system of claim 37, wherein the acid gas removal system further comprises a heat exchanger for cooling the sour gas stream prior to entering the distillation column. Cryogenic distillation tower
A lower freezing zone and an intermediate controlled freezing zone that receives a cryogenic liquid spray composed primarily of methane, where the tower receives the sour gas stream, and then the sour gas stream is divided into an overhead methane stream and a liquefied bottom acid gas stream. A controlled freezing zone in the middle part separating into
40. The system of claim 38, comprising refrigeration equipment downstream of the cryogenic distillation column for cooling the overhead methane stream and returning a portion of the overhead methane stream as liquid reflux to the cryogenic distillation column. Sulfur component removal system
At least one solid adsorption bed for substantially adsorbing hydrogen sulfide from the bottom acidic gas stream, wherein hydrogen sulfide is released as a hydrogen sulfide stream when the at least one solid adsorption bed is regenerated, 38. The system of claim 37, wherein the solid adsorbent bed comprises at least one solid adsorbent bed that substantially passes an acid gas comprising carbon dioxide as a carbon dioxide fluid stream.   41. The system of claim 40, wherein the at least one solid adsorption bed comprises at least one adsorption dynamic separation bed.   38. The system of claim 37, wherein the sulfur component removal system comprises an extractive distillation system having at least two extractive distillation columns. Extractive distillation system
A first extractive distillation column that acts as a propane recovery column, wherein the propane recovery column mixes the solvent and the acidic gas stream to absorb the acidic gas, thereby releasing the carbon dioxide stream separately, A first extractive distillation column that acts to leave the column as a solvent bottom stream;
A _second extractive distillation column that acts as a CO ₂ removal column, wherein the CO ₂ removal column causes the solvent and heavy hydrocarbons to separately release CO ₂ while the acid gas removal column as the second solvent bottom stream. A second extractive distillation column that acts to leave
A third extractive distillation column that serves as an additive recovery column, wherein the bottom solvent stream was regenerated while the liquid natural gas exited separately from the column overhead by using a distillation mechanism. 43. A system according to claim 42, comprising a third extractive distillation column for separating heavy hydrocarbon components known as "liquid natural gas" from the solvent to be released as an additive.   38. The system of claim 37, wherein the sour gas stream comprises less than approximately 1% sulfur component.   38. The system of claim 37, wherein the sour gas stream comprises between approximately 4 ppm and 100 ppm sulfur component.

Images