MX2012004788A - Cryogenic system for removing acid gases from a hydrocarbon gas stream, with removal of hydrogen sulfide. - Google Patents

Abstract

A system for removing acid gases from a raw gas stream includes an acid gas removal system (AGRS) and a sulfurous components removal system (SCRS). The acid gas removal system receives a sour gas stream and separates it into an overhead gas stream comprised primarily of methane, and a bottom acid gas stream comprised primarily of carbon dioxide. The sulfurous components removal system is placed either upstream or downstream of the acid gas removal system. The SCRS receives a gas stream and generally separates the gas stream into a first fluid stream comprising hydrogen sulfide, and a second fluid stream comprising carbon dioxide. Where the SCRS is upstream of the AGRS, the second fluid stream also includes primarily methane. Where the SCRS is downstream of the AGRS, the second fluid stream is principally carbon dioxide. Various types of sulfurous components removal systems may be utilized.

Description

CRYOGENIC SYSTEM FOR THE ELIMINATION OF ACID GASES FROM A HYDROCARBON GAS CURRENT. WITH ELIMINATION OF SULFIDE FROM HYDROGEN Reference to related request.

This application claims the benefit of United States Provisional Patent Application 61 / 257,277, filed on November 2, 2009, entitled CRYOGENIC SYSTEM FOR THE ELIMINATION OF ACID GASES FROM A HYDROCARBON GAS CURRENT, WITH THE ELIMINATION OF HYDROGEN SULFIDE. , the entirety of which is incorporated in the present application by way of reference.

Background.

This section is intended to present various aspects of the art, which may be associated with exemplary embodiments of the present invention. It is believed that this description helps to provide a framework in order to facilitate a better understanding of particular aspects of the present invention. Consequently, it should be understood that this section should be read under this perspective, and not necessarily as a prior art admission.

Countryside.

The present invention relates to the field of fluid separation. More specifically, the present invention relates to the separation of both hydrogen sulfide and other acid gases from a stream of hydrocarbon fluids.

Description of technology The production of hydrocarbons from a reservoir often leads to the incidental production of non-hydrocarbon gases. Such gases include contaminants such as hydrogen sulfide (H2S) and carbon dioxide (C02). When H2S and CO2 are produced as part of a hydrocarbon gas stream (such as methane or ethane), the gas stream is sometimes called "bitter gas".

Bitter gas is usually treated to remove C02, H2S and other contaminants, before sending it downstream for further processing or sale. The removal of acid gases creates a stream of "sweetened" hydrocarbon gas. The sweetened stream can be used as an environmentally acceptable fuel or as a feedstock for a chemical or gas-to-liquids installation. The sweetened gas stream can be cooled to form liquefied natural gas, or LNG.

The process of gas separation creates a question in terms of the disposal of the separated contaminants. In some cases, the concentrated acid gas (consisting mainly of H2S and C02) is sent to a sulfur recovery unit ("URA"). The URA converts H2S into benign elemental sulfur. However, in some areas (such as the Caspian Sea region), the production of additional elemental sulfur is undesirable, because there is a limited market. As a result, millions of tons of sulfur have been stored in large blocks on land in some areas of the world, mainly in Canada and Kazakhstan.

While sulfur is stored on land, the carbon dioxide associated with acid gas is sometimes vented to the atmosphere. However, the practice of venting C02 is sometimes undesirable. A proposal for the minimization of C02 emissions is a process called acid gas injection ("IGA"). The IGA means that the unwanted bitter gases are reinjected into a subterranean formation under pressure, and sequestered for potential subsequent use. Alternatively, carbon dioxide is used to create artificial reservoir pressure, for improved oil recovery operations.

In order to facilitate the IGA, it is desirable to have a gas processing facility that effectively separates the acid gas components from the hydrocarbon gases. However, for "highly sour" streams, that is, streams of production containing more than about 15% or 20% C02 or H2S, the design, construction and operation of an installation that can separate can be particularly challenging. in economic form, the pollutants of the desired hydrocarbons. Many reservoirs of natural gases contain relatively low percentages of hydrocarbons (less than 40%, for example) and high percentages of acid gases, mainly carbon dioxide, but also, hydrogen sulfide, carbonyl sulphide, carbon disulfide and various mercaptans. . In these cases, the processing of cryogenic gas can be used beneficially.

Cryogenic gas processing is a distillation process sometimes used for the separation of gases. Cryogenic gas separation generates a cooled upper gas stream, at moderate pressures (eg, 24-38 bar (350-550 pounds per square inch gauge (psig))). In addition, liquefied acid gas is generated as an "inferior" product. Because the liquefied acid gas has a relatively high density, a hydrostatic head can be beneficially used in an IGA well, in order to assist in the injection process. This means that the energy needed to pump the liquefied acid gas in the formation is less than the energy needed to compress acid gases at low pressure to the reservoir pressure. Less stages of compressors and pumps are needed.

Likewise, there are challenges with respect to the cryogenic distillation of bitter gases. When CO2 is present in concentrations greater than about 5 mole percent, at total pressure less than about 48 bar (700 psig) in the gas to be processed, it will be frozen as a solid in a conventional cryogenic distillation unit. The formation of CO2 as a solid interrupts the cryogenic distillation process. In order to avoid this problem, the transferee has previously designed several "Controlled Freeze Zone ™" (CFZ ™) processes. The CFZ ™ process capitalizes on the propensity of carbon dioxide to form solid particles, allowing the formation of frozen CO2 particles within an open portion of the distillation tower, and then capturing the particles in a fusion tray. Consequently, a clean methane stream (along with any nitrogen or helium present in the raw gas) is generated in the upper part of the tower, while generating a cold liquid CO2 / H2S stream at the base of the tower. At pressures above about 48 bar (700 psig), the "volume fractionation" distillation can be performed without fear of CO2 freezing; however, the methane generated in the upper part will have at least a certain percentage of CO2.

Certain aspects of the CFZ ™ process and associated equipment are described in U.S. Patent No. 4,533,372; U.S. Patent No. 4,923,493; U.S. Patent No. 5,062,270; U.S. Patent No. 5,120,338; and United States Patent No. 6,053,007.

As generally described in the above U.S. Patents, the distillation tower, or column, used for the cryogenic gas processing includes a minor distillation zone and an intermediate controlled freezing zone. Preferably, a superior distillation zone is also included. The column operates to create solid C02 particles by providing a portion of the column that has a temperature range below the freezing point of carbon dioxide, although above the boiling point of methane at said pressure. More preferably, the controlled freezing zone is operated at a temperature and pressure which allow the vaporization of methane and other light hydrocarbon gases, while the CO2 forms frozen (solid) particles.

As the gas feed stream moves up the column, the frozen C02 particles move away from the feed stream and descend gravitationally from the controlled freezing zone to a melting tray. There, the particles liquefy. Then a liquid stream rich in carbon dioxide flows from the melting tray to the lower distillation zone at the base of the column. The lower distillation zone is maintained at a temperature and at a pressure at which substantially no carbon dioxide solids, but the dissolved methanol boils. In one aspect, the lower acid gas stream is created at -1, 1 to 4.4 ° C (30 ° to 40 ° F).

In one embodiment, some or all of the frozen C02 particles can be collected in a tray in the lower part of the freezing zone. The particles are then transported out of the distillation tower for further processing.

The controlled freezing zone includes a cold liquid tray. This is a liquid stream enriched in methane, known as "reflux". As the vapor stream of the light hydrocarbon gases and bitter gases transported moves up through the column, the vapor stream encounters the liquid spray. The cold liquid spray helps in the separation of solid C02 particles, and at the same time, allows the evaporation of the methane gas and its upward flow in the column.

In the upper distillation zone, the methane (or upper gas) is captured and sent through the pipeline for sale, or for availability as fuel. In one aspect, the top methane stream is released at approximately -90 ° C (-130 ° F). The upper gas can be partially liquefied by additional cooling, and the liquid can be returned to the column as reflux. The liquid reflux is injected as the cold spray in the spray section of the controlled freezing zone, usually, after flowing through trays or packing the rectification section of the column.

The methane produced in the upper distillation zone complies with most of the specifications for the supply of pipes. For example, methane can meet the C02 specification of pipe less than 2 mole percent, like the specification of 4 ppm h ^ S, if enough reflux is generated, or if there are enough separation stages of packaging or trays in the upper distillation zone. However, if the original raw gas stream contains hydrogen sulfide (or other sulfur-containing compounds), these will end up in the lower liquid stream of carbon dioxide and hydrogen sulfide.

Hydrogen sulfide is a poisonous gas that is heavier than air. It is corrosive to the well and surface equipment. When hydrogen sulfide comes into contact with metal pipes and valves in the presence of water, corrosion of iron sulphide may occur. Therefore, it is convenient to remove the hydrogen sulphide and other sulfur components from the raw gas stream, before entering the cold distillation column. This allows the feeding of a stream of "sweetened" gas into the column. The C02 generated by the cryogenic process, accordingly, is substantially free of H2S, and can be used, for example, for the best oil recovery.

There is a need for a system to reduce the H2S and mercaptan content of a stream of crude natural gas, before going through cryogenic distillation for the removal of bitter gases. Alternatively, there is a need for a cryogenic gas separation system and accompanying processes that extract hydrogen sulfide from the downstream acid gas stream of a CFZ tower.

SYNTHESIS A system is provided for the removal of acid gases from a sour gas stream. In one embodiment, the system includes an acid gas removal system. The acid gas removal system uses a cryogenic distillation tower that separates the sour gas stream into an upper gas stream composed mainly of methane, and a liquefied lower acid gas stream, composed mainly of carbon dioxide. The system also includes a sulfur component removal system. The sulfur component removal system is placed upstream of the acid gas removal system. The sulfur component removal system receives a stream of raw gas, and generally separates the gross gas stream into a fluid stream having hydrogen sulphide and a bitter gas stream.

The bitter gas stream preferably comprises between about 4 ppm and 100 ppm sulfur components. Said components can be hydrogen sulfide, carbonyl sulphide and various mercaptans.

Preferably, the cryogenic acid gas removal system includes a cooling system for cooling the bitter gas stream before entering the distillation tower. Preferably, the cryogenic acid gas removal system is a "CSF" system, where the distillation tower has a lower distillation zone and an intermediate controlled freezing zone. The intermediate controlled freezing zone, or "spray section", receives a cold liquid spray composed mainly of methane. The cold spray is a liquid reflux generated from a top downstream ring of the distillation tower. Cooling equipment is provided downstream of the cryogenic distillation tower, for the cooling of the upper methane stream and the return of a portion of the higher methane stream to the cryogenic distillation tower as the cold liquid reflux.

It is understood that other acid gas removal systems can be employed in addition to the cryogenic distillation systems. For example, the acid gas removal system can be a physical solvent system that is also prone to reject H2S along with CO2. The acid gas removal system can use fractionation in volume.

Various types of sulfur component removal systems can be used, including systems that use physical solvents to separate the sulfur-containing components from a bitter gas stream. These can include redox processes (reduction-oxidation) and the use of so-called debuggers. These processes can include a process called "CrystaSulf.

In one aspect, the sulfur component removal system comprises at least one solid adsorbent bed. One or more solid adsorbent beds adsorb at least a certain amount of hydrogen sulfide, while passing the methane gas and carbon dioxide as the bitter gas stream. The solid adsorbent bed, for example, can be (i) manufactured from a zeolite material; or (ii) comprise at least one molecular sieve. The solid adsorbent bed can incidentally adsorb at least a certain amount of water.

One or more solid adsorbent beds can be beds of adsorbent kinetic separations. Alternatively, one or more solid adsorbent beds may comprise at least three solid adsorbent beds where: (i) a first of the at least three solid adsorbent beds is in service to adsorb sulfurous components; (ii) one second of at least three solid adsorbent beds passes through regeneration; and (iii) a third of at least three solid adsorbent beds is held in reserve to replace the first of the at least three solid adsorbent beds. Regeneration can be part of a thermal swing adsorption process, part of a pressure swing adsorption process, or a combination of both.

In another embodiment, the sulfur component removal system employs a chemical solvent such as a selective amine. In this case, the sulfur component removal system preferably uses a plurality of joint current contact devices.

Other types of sulfur component removal systems may be used in place of or in addition to a physical solvent or chemical solvent system. Such systems may include a redox system, the use of at least one solid adsorbent bed, or the use of at least one bed of absorbent kinetic separations.

A separate system for the removal of acid gases from a bitter gas stream is also provided in this application. In this system, they are removed substantially hydrogen sulfide and other sulfur containing compounds, downstream of an acid gas removal system. The system is designed to process a stream of acid gas. The acid gas stream is obtained from a crude gas stream which initially comprises 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 the raw gas stream and separates the gross gas stream into an upper gas stream composed mainly of methane, and a liquid lower acid gas stream composed mainly of carbon dioxide. The hydrogen sulfide can also be present in the lower acid gas stream. The system also includes a sulfur component removal system. The sulfur component removal system is placed downstream of the acid gas removal system. The sulfur component removal system receives the lower acid gas stream and generally separates the lower acid gas stream into a carbon dioxide stream and a separate stream having mainly sulfur-containing compounds.

Preferably, the acid gas removal system is a cryogenic acid gas removal system. The cryogenic acid gas removal system includes a distillation tower to receive the raw gas stream, and a cooling system, to cool the crude gas stream before entry into the distillation tower. Preferably, the cryogenic acid gas removal system is a "CFZ" system, where the distillation tower has a lower distillation zone and an intermediate controlled freezing zone. The intermediate controlled freezing zone, or "spray section", receives a cold liquid spray composed mainly of methane. The cold spray is a liquid reflux generated from a top downstream ring of a distillation tower. Cooling equipment downstream of the cryogenic distillation tower is provided for the cooling of the upper methane stream and the return of a portion of the upper methane stream to the cryogenic distillation tower as reflux, which is a liquid.

Various types of sulfur component removal systems can be used. In one aspect, the sulfur component removal system comprises at least one solid adsorbent bed. One or more solid adsorbent beds adsorb at least certain sulfur-containing components of the lower acid gas stream, and substantially pass carbon dioxide gas. The solid adsorbent bed can use, for example, adsorbent kinetic separations (SCA). The SCA bed can incidentally adsorb at least some amount of carbon dioxide. In this case, the SCA sulfur component removal system, preferably, further includes a separator such as a gravity separator. The gravity separator separates liquid heavy hydrocarbon components and hydrogen sulfide from, for example, C02 gas.

The solid adsorbent bed, alternatively, can be an iron sponge, to react directly with the H2S and eliminate it forming iron sulfide.

In another aspect, the sulfur component removal system comprises an extraction distillation process. The extraction distillation process employs at least two solvent recovery columns. The first column receives the lower acid gas stream and separates the lower acid gas stream in a first fluid stream composed mainly of carbon dioxide, and a second fluid stream composed mainly of solvent and sulfur-containing compounds.

Brief description of the drawings.

In order to be able to better understand the mode of the present inventions, certain illustrations, tables and flowcharts are attached to the present application. It is noted, however, that the drawings illustrate only selected embodiments of the inventions, and therefore, should not be considered scope limitations, since the inventions can accommodate other equally effective embodiments and applications.

Figure 1 is a side view of an illustrative CFZ distillation tower, in one embodiment. A stream of cooled raw gas is injected into the intermediate controlled freezing zone of the tower.

Figure 2A is a plan view of a melting tray, in one embodiment. The fusion tray resides inside the tower below the controlled cooling zone.

Figure 2B is a cross-sectional view of the fusion tray of Figure 2A, taken through line 2B-2B.

Figure 2C is a cross-sectional view of the fusion tray of Figure 2A, taken through the line 2C-2C.

Figure 3 is an enlarged side view of stabilization trays in the lower distillation zone of the distillation tower, in one embodiment.

Figure 4A is a perspective view of a jet tray that can be used either in the lower distillation section or in the upper distillation section of the distillation tower, in one embodiment.

Figure 4B is a side view of one of the openings of the jet tray of Figure 4A.

Figure 5 is a side view of the intermediate controlled freezing zone of the distillation tower of Figure 1. In this view, two illustrative open deflectors have been added to the intermediate controlled freezing zone.

Figure 6 is a schematic diagram showing a gas processing facility for the removal of acid gases from a gas stream, according to the present invention, in one embodiment. The gas processing facility employs an upstream solvent process of an acid gas removal system.

Figure 7A provides a detailed schematic diagram of the solvent system of Figure 6, in one embodiment. Here, the solvent system is a physical solvent system, which operates to contact a stream of dehydrated gas in order to remove hydrogen sulfide.

Figure 7B provides a detailed schematic diagram of the solvent system of Figure 6, in an alternative embodiment. Here, the solvent system is a chemical solvent system that operates to contact a stream of dehydrated gas in order to remove hydrogen sulfide.

Figure 8 is a schematic diagram showing a gas processing facility for the removal of acid gases from a gas stream in accordance with the present invention, in one embodiment. In this arrangement, hydrogen sulfide is removed from a rising gas stream of an acid gas removal system by means of a redox process.

Figure 9 is a schematic diagram showing a gas processing facility for the removal of acid gases from a gas stream in accordance with the present invention, in one embodiment. In this arrangement, hydrogen sulfide is removed from a rising gas stream of an acid gas removal system by means of a scrubber.

Figure 10 is a schematic diagram showing a gas processing facility for removing acid gases from a gas stream in accordance with the present invention, in one embodiment. In this arrangement, hydrogen sulfide is removed from a rising gas stream of an acid gas removal system by means of a CrystaSulf process.

Figure 11 is a schematic diagram showing a gas processing facility for the removal of acid gases from a gas stream according to the present invention, in one embodiment. In this arrangement, hydrogen sulfide is removed from a rising gas stream of an acid gas stripping system by means of a thermal oscillation adsorption system.

Figure 12 is a schematic diagram showing a gas processing facility for the removal of acid gases from a gas stream in accordance with the present invention, in one embodiment. In this arrangement, hydrogen sulfide is removed from a rising gas stream of an acid gas removal system by means of a pressure swing adsorption system.

Figure 13 is a schematic diagram showing a gas processing facility of the present invention, in another embodiment. In this arrangement, hydrogen sulfide is removed from a rising gas stream of an acid gas stripping system by means of an adsorption bed utilizing the kinetic adsorption separation.

Figure 14 is a schematic diagram showing a gas processing installation of the present invention, in another embodiment. In this arrangement, hydrogen sulfide is removed from a downstream gas stream of an acid gas stripping system by means of an adsorption bed utilizing the kinetic adsorption separation.

Figure 15A is a schematic diagram of a gas processing installation of the present invention, in another embodiment. In this arrangement, hydrogen sulfide is removed from a downstream gas stream of an acid gas stripping system by means of an extraction distillation process.

Figure 15B is a detailed schematic diagram of a gas processing installation for the extraction distillation process of Figure 15A.

Detailed description of certain embodiments.

Definitions.

According to this application, the term "hydrocarbon" refers to an organic compound that includes, but is not limited to, the hydrogen and carbon elements. Hydrocarbons are generally found in two classes: aliphatic, or straight chain, and cc hydrocarbons, or closed ring hydrocarbons, including cc terpenes. Examples of hydrocarbon-containing materials include any form of natural gas, petroleum, coal and bitumen, which can be used as a fuel or improved in a fuel.

According to this application, the term "hydrocarbon fluids" refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbons that are gases or liquids under the conditions of formation, under the conditions of processing, or under ambient conditions (15 ° C and 0.1 MPa (1 atm) of Pressure). The hydrocarbon fluids may include, for example, petroleum, natural gas, coal bed methane, slate oil, pyrolysis oil, pyrolysis gas, a coal pyrolysis product and other hydrocarbons occurring in a gaseous state or liquid.

The term "mass transfer device" refers to any object that receives fluids to be contacted, and passes said fluids to other objects, such as through a gravitational flow. A non-limiting example is a tray for the stabilization of certain components. Another example is a grid packaging.

According to this application, the term "fluid" refers to gases, liquids and combinations of gases and liquids, as well as combinations of gases and solids and combinations of liquids and solids.

According to this invention, the term "condensable hydrocarbons" means those hydrocarbons that are condensed at about 15 ° C and an atmosphere of absolute pressure. The condensable hydrocarbons may include, for example, a mixture of hydrocarbons having carbon numbers greater than 4.

According to this application, the term "heavy hydrocarbons" refers to hydrocarbons having more than one carbon atom. Main examples include ethane, propane and butane. Other examples include pentane, aromatics or diamanthoids.

According to this application, the term "closed loop cooling system" means any cooling system where an external working fluid such as propane or ethylene is used as a quencher in order to cool a higher methane stream. This contrasts with an "open-loop cooling system," where a portion of the upper methane stream itself is used as the working fluid.

According to this application, the term "joint current contact device" or "joint current contactor" means a device that receives (i) a gas stream and (ii) a separate solvent stream such that the current of gas and the solvent stream are brought into contact with each other, while generally flowing in the same directions within the contact device. Examples, without limitation, include an eductor, a binder or a static blender plus blender.

A "non-absorbent gas" means a gas that is not significantly absorbed by a solvent during a gas sweetening process.

According to this application, the term "natural gas" refers to a multi-component gas obtained from a well of crude oil (associated gas) or from an underground formation carrying gas (non-associated gas). The composition and pressure of natural gas can vary significantly. A typical natural gas stream contains methane (Ci) as a significant component. The natural gas stream may also contain ethane (C2), higher molecular weight hydrocarbons and one or more acid gases. Natural gas may also contain minor amounts of contaminants such as water, nitrogen, wax, and crude oil.

According to this application, an "acid gas" means any gas that dissolves in water to produce an acid solution. Examples, without limitation, of acid gases include hydrogen sulfide (H2S) and carbon dioxide (CO2). The sulfur compounds include carbon disulfide (CS2), carbonyl sulfide (COS), mercaptans or mixtures thereof.

The term "liquid solvent" means a substantially liquid phase fluid that, preferably, absorbs acid gases, in order to remove or "separate" at least a portion of the acid gas components from a gas stream. The gas stream may be a stream of hydrocarbon gas or another gas stream, such as a gas stream having nitrogen.

A "sweetened gas stream" refers to a fluid stream in a substantially gaseous phase that has had at least a portion of acid gas components removed.

According to this application, the terms "lean" and "rich", with respect to the removal of absorbent liquid from a gas component selected from a gas stream, are relative, and only imply, respectively, a lower or higher degree. of content of the selected gas component. The respective terms "pure" and "rich" do not necessarily indicate, respectively, either that an absorbent liquid is totally devoid of the selected gaseous component, or that it is unable to absorb more of the selected gas component, nor do they require it. In fact, it is preferred, as will be evident below, that the so-called "rich" absorbent liquid produced in a first contactor in a series of two or more contactors retains significant or substantial residual absorption capacity. Conversely, it will be understood that an absorbent liquid will be capable of substantial absorption, although it may retain a lower concentration of the removed gas component.

The term "crude gas stream" refers to a hydrocarbon fluid stream where the fluids are mainly in a gas phase, and which has not gone through stages for the removal of carbon dioxide, hydrogen sulfide or other acidic components.

The term "bitter gas stream" refers to a hydrocarbon fluid stream where the fluids are mainly in a gas phase, and contain at least 3 mole percent carbon dioxide or more than 4 ppm hydrogen sulfide .

According to this application, the term "subsurface" refers to the geological strata that appear below the earth's surface.

Description of the specific embodiments.

Figure 1 depicts a schematic view of a cryogenic distillation tower 100, which may be used in connection with the present inventions, in one embodiment. The cryogenic distillation tower 100 can be referred to indistinctly, in this application, a "cryogenic distillation tower", a "column", a "CFZ column" or just a "tower".

The cryogenic distillation tower 100 of Figure 1 receives an initial fluid stream 10. The fluid stream 10 is composed mainly of production gases. Typically, the fluid stream represents a dried gas stream from a well head or collection of well heads (not exposed), and contains about 65% to about 95% methane. However, the fluid stream 10 may contain a lower percentage of methane, such as about 30% to 65%, or even a percentage as low as 20% to 40%.

Methane can occur along with trace elements from other hydrocarbon gases, such as ethane. In addition, minimal amounts of helium and nitrogen may be present. In the present application, the fluid stream 10 will also include certain contaminants. These include acid gases such as CO2 and H2S.

The initial fluid stream 10 can be presented at a postproduction pressure of approximately 41 bar (600 pounds per square inch (psi)). In some cases, the pressure of the initial fluid stream 10 may be up to about 52 bar (750 psi) or even 69 bar (1000 psi).

The fluid stream 10 is typically cooled before entering the distillation tower 100. A heat exchanger 150, such as a shell and tube heat exchanger, is provided for the initial fluid stream 10. A refrigeration unit (not exposed) ) provides cooling fluid (such as liquid propane) to the heat exchanger 150, in order to lower the temperature of the initial fluid stream 10 to approximately -34 to -40 ° C (-30 ° to -40 ° F). The cooled fluid stream can then be transported through an expansion device 152. The Expansion device 152 may be, for example, a Joule-Thompson valve ("J-T").

The expansion device 152 serves as an expander to obtain additional cooling of the fluid stream 10. Preferably, partial liquefaction of the fluid stream 10 is achieved. A Joule-Thompson (or "JT") valve is preferred for currents. of gas feed that are prone to the formation of solids. The expansion device 152 is preferably mounted near the cryogenic distillation tower 100 in order to minimize heat loss in the feed pipe and to minimize the possibility of sealing with solids, in the case that some components (such as as CO2 or benzene) fall below their freezing points.

As an alternative to a J-T valve, the expander device 152 can be a turbo expander. A turbo expander provides more cooling, and creates a stem working source for processes such as the refrigeration unit mentioned above. The heat exchanger 150 is part of the refrigeration unit. In this way, the operator can minimize the total energy requirements for the distillation process. However, the turboexpander may not handle frozen particles as well as the J-T valve.

In either case, the heat exchanger 150 and the expander device 152 convert the raw gas into the initial fluid stream 10, in a stream of cooled fluid 12. Preferably, the temperature of the cooled fluid stream 12 is about - 40 ° to -57 ° C (-40 ° to -70 ° F). In one aspect, the cryogenic distillation tower 100 is operated at a pressure of about 38 bar (550 psi), and the cooled fluid stream 12 is at about -52 ° C (-62 ° F). Under these conditions, the cooled fluid stream 12 is in a substantially liquid phase, although, inevitably, some vapor phase can be transported in the cooled fluid stream 12. More likely, no solid formation has arisen due to the presence of C02.

The CFZ 100 cryogenic distillation tower is divided into three primary sections. These sections are a lower distillation zone, or "stabilization section" 106, an intermediate controlled freezing zone, or "spray section" 108, and an upper distillation zone, or "rectification section" 110. In the arrangement of the tower of Figure 1, the cooled fluid stream 12 is introduced into the distillation tower 100 in the controlled cooling zone 108. However, the cooled fluid stream 12 can alternatively be introduced near the top of the lower distillation zone 106.

It is observed in the arrangement of Figure 1 that the lower distillation zone 106, the intermediate spray section 108, the upper distillation zone 110, and the related components are housed within an individual container 100. However, for sea applications in which it may be necessary to consider the height of the tower 100 and movement issues, or for remote locations in which transport limitations represent a matter, the tower 110, optionally, can be divided into two separate pressure vessels (not exposed). For example, the lower distillation zone 106 and the controlled freezing zone 108 can be located in one container, while the upper distillation zone 108 is in another container. Then external piping is used to interconnect the two vessels.

In any of the embodiments, the temperature of the lower distillation zone 106 is greater than the supply temperature of the cooled fluid stream 12. The temperature of the lower distillation zone 106 is designed to be much higher than the boiling point of the methane in the cooled fluid stream 12, at the operating pressure of the column 100. In this manner, the methane is preferably stabilized from the heavier hydrocarbon components and liquid acid gas. Naturally, those skilled in the art will understand that the liquid within the distillation tower 100 is a mixture, which means that the liquid will "boil" at some intermediate temperature between the pure methane and the pure CO2. Also, in the event that If there are heavier hydrocarbons present in the mixture (such as ethane or propane), this will increase the boiling temperature of the mixture. These factors become consideration for the design, for the operating temperatures within the cryogenic distillation tower 100.

In the lower distillation zone 106, the CO2 and any other fluid of liquid phase falls gravitationally towards the base of the cryogenic distillation tower 100. At the same time, the methane and other vapor phase fluids are separated and rise towards the upper part of the tower 100. This separation is mainly achieved through the density differential between the gas and liquid phases. However, the separation process is optionally aided by internal components within the distillation tower 100. As described below, these include a melting tray 130, a plurality of conveniently configured mass transfer devices 126, and a line optional heater 25. Also, a side reheater (see 173) may be added to the lower distillation zone 106, in order to facilitate the removal of methane.

Again, with reference to Figure 1, the cooled fluid stream 12 can be introduced into the column 100 near the top of the lower distillation zone 106. Alternatively, it may be convenient to introduce the feed stream 12 into the freezing zone controlled 08 on the melting tray 130. The injection point of the cooled fluid stream 12 is a design issue dictated mainly by the composition of the initial fluid stream 10.

When the temperature of the cooled fluid stream 12 is sufficiently high (such as above -57 ° C (-70 ° F)), so that solids are not expected, it may be convenient to inject the stream of cooled fluid 12 directly into the lower distillation zone 106 through a two-phase flash box type device (or vapor distributor) 124 in the column 100. The use of a flash box 124 serves to at least partially separate the two-phase vapor-liquid in the cooled fluid stream 12. Flash case 124 may be grooved, so that two-phase fluid collides with baffles in flash box 124.

If solids are anticipated due to a low inlet temperature, it may be necessary that the cooled fluid stream 12 be partially separated in a vessel 173, prior to feeding into the column 100, as described above. In this case, the cooled feed stream 12 can be separated in a two-phase separator 173, in order to minimize the possibility of sealing solids from the inlet line and the internal components of the column 100. The gas vapor leaves the phase separator 173 through a container inlet line 11, where it enters column 100 through an inlet manifold 121. The gas then travels upwardly through column 100. A liquid / solid suspension 13 is discharged from the phase separator 173. The liquid / solid suspension is directed to the column 100 through the steam distributor 124 and the fusion tray 130. The liquid / solid suspension 13 can be fed to the column 100. by gravity or by a bomb 175.

In any of these arrangements, that is, with or without the two-phase separator 173, the cooled fluid stream 12 (or 11) enters the column 100. The liquid component leaves the flash box 124 and travels in descending order through a collection of stabilization trays 126, within the lower distillation zone 106. Stabilization trays 126 include a series of landfills 128 and descent tubes 129. These are described more fully below, in connection with Figure 3. Stabilization trays 126, in combination with the hottest temperature in the lower distillation zone 106, cause the methane to separate from the solution. The resulting vapor carries methane and any transported carbon dioxide molecule that has been removed by boiling.

The steam proceeds upwardly through the risers or chimneys 131 of the melting tray 130 (seen in Figure 2B) and into the freezing zone 108. The chimneys 131 act as a steam distributor for uniform distribution through the freezing zone 108. The steam will then come into contact with the cold liquid of the spray manifolds 120, in order to "freeze" the CO2. In other words, the CO2 will freeze and then precipitate or "snow" again on the melting tray 130. The solid C02 then melts and flows gravitationally in liquid form on the melting tray 130 and through the lower distillation zone 106, below.

As will be described in more detail below, the spray section 108 is an intermediate freezing zone of the cryogenic distillation tower 100. With the alternative configuration where the cooled fluid stream 12 is separated in the container 173 before entering the tower 100, a portion of the separated liquid / solid suspension 13 is introduced into the tower 100, immediately onto the melting tray 130. Accordingly, a liquid-solid mixture of acid gas and heavier hydrocarbon components will flow from the distributor 121 , where solids and liquids fall on the melting tray 130.

The melting tray 130 is configured to gravitationally receive liquid and solid materials, mainly CO2 and H2S, from the intermediate controlled freezing zone 108. The melting tray 130 serves to cool the liquid and solid materials and direct them down through the lower distillation zone 106 in liquid form for further purification. The melting tray 130 collects and warms the solid-liquid mixture from the controlled freezing zone 108 in a liquid mass. The melting tray 130 is designed to release the steam flow back to the controlled freezing zone 108, so as to provide adequate heat transfer to melt the solid CO 2 and facilitate the draining of liquid / suspension to the lower distillation, or lower distillation zone 106 of column 100 below melting tray 130.

Figure 2A provides a plan view of the melting tray 130, in one embodiment. Figure 2B provides a cross-sectional view of the fusion tray 130, taken through line B-B of Figure 2A. Figure 2C shows a cross-sectional view of the fusion tray 130, taken through the line C-C. The fusion tray 130 will be described with reference to these three drawings, collectively.

First, the melting tray 130 includes a base 134. The base 134 can be substantially a flat body. However, in the preferred embodiment set forth in Figures 2A, 2B and 2C, the base 134 employs a substantially non-planar profile. The non-planar configuration provides a greater surface area for the contact of liquids and solids that reach the melting tray 130 from the controlled cooling zone 108. This serves to increase the heat transfer from the vapors passing from the zone of lower distillation 106 of column 100, to liquids and solids in thawing. In one aspect, the base 134 is corrugated. In another aspect, the base 134 is substantially sinusoidal. This aspect of the tray design is shown in Figure 2B. It is understood that, alternatively, other non-planar geometries may be used to increase the heat transfer area of the melting tray 130.

The base of the melting tray 134 is preferably inclined. The inclination is shown in the side view of Figure 2C. While most solids should be fused, the tilt serves to ensure that no un-fused solids in the liquid mixture are drained from the melting tray 130 and into the distillation zone 106 below.

In the view of Figure 2C, a sump or central channel 138 is seen in the melting tray 130. The base of the melting tray 134 slopes inwards towards the channel 138, in order to supply the solid mixture. liquid. The base 134 can be tilted in any way, so as to facilitate the gravitational extraction of liquid.

As described in U.S. Patent No. 4,533,372, the fusion tray was referred to as a "chimney tray". This is due to the presence of a single exit chimney. The fireplace provides an opening to through which the vapors can move upwards through the chimney tray. However, the presence of a single chimney means that all the gases that move up through the chimney pan had to exit through a single opening. On the other hand, in the melting tray 130 of Figures 2A, 2B and 2C, a plurality of chimneys 131. are provided. The use of multiple chimneys 131 provides better vapor distribution. This contributes to the best heat / mass transfer in the intermediate controlled freezing zone 108.

The chimneys 131 can be of any profile. For example, the chimneys 131 may be round, rectangular, or in any other manner that allows steam to pass through the melting tray 130. The chimneys 131 may also be narrow and extend upward in the controlled freezing zone 108. This allows a beneficial pressure drop to distribute the steam evenly as it rises in the controlled freezing zone CFZ 108. The chimneys 131 are preferably located on peaks of the corrugated base 134 in order to provide a area of additional heat transfer.

The upper openings of the chimneys 131 are preferably covered with hoods 132. This minimizes the possibility that solids falling from the controlled freezing zone 108 can avoid falling on the melting tray 130. In Figures 2A, 2B and 2C, the caps 132 are observed on each of the chimneys 131.

The fusion tray 130 can also be designed with bubble-type caps. The bubble-like caps define convex depressions in the base 134 which rises from below the melting tray 130. The bubble-like caps further increase the surface area in the melting tray 130., in order to provide additional heat transfer to the liquid rich in C02. With this design, adequate liquid extraction, such as a greater angle of inclination, should be provided in order to ensure that the liquid is directed to the stabilization trays 126 below.

Referring again to Figure 1, the melting tray 130 can also be designed with an external liquid transfer system. The transfer system serves to ensure that all liquid is substantially free of solids, and that sufficient heat transfer has been provided. The transfer system first includes an extraction nozzle 136. In one embodiment, the extraction nozzle 136 resides within the extraction sump, or channel 138 (shown in Figure 2C). The fluids collected in the channel 138 are supplied to a transfer line 135. The flow through the transfer line 135 can be controlled by a control valve 137 and an "LC" level controller (observed in Figure 1) . The fluids are returned to the lower distillation zone 106 by means of a 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 closes. If the operator chooses not to employ the transfer system in the lower distillation zone 106, then the control valve 137 is closed, and the fluids are immediately directed to the mass transfer devices, or "stabilization trays" 126 below. the melting tray 130, for stabilization by means of a drain descent pipe 139.

With the use or without the use of an external transfer system, the Solid C02 is warmed on the melting tray 130 and converted into a CO2-rich liquid. The melting tray 130 is heated from below by means of the vapors from the lower distillation zone 106. Optionally, additional heat can be added to the tray of fusion 130, or on the basis of melting tray 134, by various means such as heater line 25. Heater line 25 utilizes already available thermal energy from a base reheater 160, in order to facilitate thawing of the solids.

The C02 rich liquid is extracted from the melting tray 130 with liquid level control, and is gravitationally introduced into the lower distillation zone 106. As noted, a plurality of stabilization trays 126 are provided in the distillation zone lower 106 below the melting tray 130. The stabilization trays 126 are preferably in a substantially parallel relationship, one on the other. Each of the stabilization trays 126 can be located, optionally, with a very slight inclination, with a weir, in such a way that a level of liquid is maintained on the tray. The fluids flow gravitationally along each tray, over the spillway, and then flow down the next tray by means of a drop tube.

Stabilization trays 126 may be presented in a variety of arrangements. Stabilization trays 126 may be arranged in a generally horizontal relationship in order to form a cascading liquid flow in back and forth movement. However, it is preferred that the stabilization trays 126 be arranged so as to create a cascaded liquid flow that is divided by stabilization trays separated substantially along the same horizontal plane. This is shown in the arrangement of Figure 3, where the liquid flow is divided at least once, so that the liquid flows through separate trays and falls into two opposite descent tubes 129.

Figure 3 provides a side view of a stabilization tray 126, in one embodiment. Each of the stabilization trays 126 receives and collects fluids from above. Each stabilization tray 126 preferably has a weir 128, which serves as a dam to allow the collection of a small mass of fluid on each of the stabilization trays 126. The construction can be 1, 3 to 2.5 cm (½ to 1 inch), although any height can be used. A water fall effect is created by means of landfills 128, as the fluid falls from a tray 126 onto a subsequent lower tray 126. In one aspect, no inclination is provided to the stabilization trays 126, although the effect of falling water is created through a configuration of higher descent tube 128. The fluid is brought into contact with vapor coming from above, rich in lighter hydrocarbons that stabilize the methane and remove it from the flowing liquid cross-shaped in this "contact area" of the trays 126. The landfills 128 serve to dynamically seal the drop tubes 129 in order to help prevent steam from passing through the drop tubes 129, and at to further facilitate the separation of hydrocarbon gases.

The percentage of methane in the liquid becomes less and less as the liquid moves downward through the lower distillation zone 106. The range of the 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 methane content of the liquid can be as high as 25 mole percent, while in the base stabilization tray, the methane content can be as low as low as 0.04 mole percent. The methane content is rapidly eliminated along the stabilization trays 126 (or other mass transfer devices). 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 crude gas stream 10. However, it is typically necessary to use only a few. Stabilization tray levels 126 in order to remove the methane, for example, to a desired level of 1% or less in the liquefied acid gas.

Various configurations of individual stabilization trays 126 that facilitate the separation of methane can be employed. The stabilization tray 126 may simply represent a panel with sieve holes or bubble-like caps. However, in order to provide additional heat transfer to the fluid and prevent unwanted blockage due to solids, so-called "jet trays" can be employed under the melting tray. Instead of trays, random or structured packaging can also be used.

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

In operation, one or more jet trays 426 may be located in the lower distillation zone 106 and upper distillation zone 110 of the tower 100. The trays 426 may be arranged with multiple passes, such as the pattern of the stabilization trays 126. of Figure 3. However, any tray or package arrangement can be used, which facilitates the separation of methane gas. The fluid cascades down on each jet tray 426. The fluids then flow along the body 424. The tabs 422 are optimally oriented to move the fluid quickly and efficiently through the tray 426. Optionally, a tube can be provided. attached descent (not shown) so as to move the liquid to the subsequent tray 426. The openings 425 also allow the upward travel of the gas vapors released during the fluid movement process in the lower distillation zone 106, in a further manner. effective towards the melting tray 130 and through the chimneys 131.

In one aspect, the trays (such as trays 126 or 426) can be made of materials resistant to contamination, i.e., materials that prevent the formation of solids. The materials resistant to contamination are used in some processing equipment to prevent the formation of corrosive metal particles, polymers, salts, hydrates, fines of catalysts or other solid chemical compounds. In the case of the cryogenic distillation tower 100, the contamination resistant materials can be used in trays 126 or 426, in order to limit the adhesion of CO2 solids. For example, a Teflon ™ coating may be applied to the surface of the trays 126 or 426.

Alternatively, a physical design can be provided to ensure that the CO2 does not begin to form as a solid along the internal diameter of the column 100. In this aspect, the jet tabs 422 can be oriented to push the liquid along the length of the column. the wall of the column 100, in order to avoid the accumulation of solids along the wall of the column 100 and guarantee good vapor-liquid contact.

In any of the tray arrangements, as the downflow liquid collides with the stabilization trays 126, separation of materials occurs. The methane gas is separated from the solution and moves upwards in the form of vapor. However, C02 is generally cold and at a high enough concentration so that, for the most part, it remains in its liquid form and travels down to the base of the lower distillation zone 106, although, necessarily, certain C02 amount will be vaporized in the process. The liquid is then moved out of the cryogenic distillation tower 100 into an outlet line as a lower fluid stream 22.

Upon exiting the distillation tower 100, the lower fluid stream 22 enters the reheater 160. In Figure 1, the reheater 160 is a turkey type vessel that provides reboiling steam to the base of the stabilization trays. A line of reboiling steam is observed at 27. In addition, the reboiling steam can be supplied through a heater line 25, in order to provide supplementary heat to the melting tray 130. The supplemental heat is controlled through a valve 165 and a temperature controller TC. Alternatively, a heat exchanger, such as a thermosyphon heat exchanger (not shown) can be used to cool the initial fluid stream 10 in order to save energy. In this regard, the liquids that enter the reheater 160 remain at a relatively low temperature, for example, from about -1.1 to 4.4 ° C (30 ° to 40 ° F). By integrating heat with the initial fluid stream 10, the operator can partially warm and boil the lower fluid stream 22 of the distillation tower 100, while pre-cooling the production fluid stream 10. For this case, the fluid that provides supplemental heat through line 25 is a return of the vapor phase of reheater 160.

It is contemplated that, under certain conditions, the melting tray 130 may operate without the heater line 25. In these cases, the melting tray 130 may be designed with an internal heating characteristic such as an electric heater. However, it is preferred to offer a heat system employing the available heat energy in the lower fluid stream 22. The warm fluids in the heater line 25 exit, in one aspect, at -1.1 to 4.4 °. C (30 ° to 40 ° F), so that they contain relative caloric energy. Accordingly, in Figure 1, a warm vapor stream is shown in the heater line 25, directed to the melting tray 130 through a heating coil (not exposed) on the melting tray 130. warm steam, alternatively, can be attached to the transfer line 135.

In operation, most of the reboiling steam stream is introduced into the base of the column, through line 27, on the lower liquid level and in the last stabilization tray 126, or below it. As the boiling vapor passes up through each tray 126, the residual methane is stabilized out of the liquid. This vapor cools as it travels up the tower. As the steam stream of line 27 reaches corrugated melting tray 130, the temperature may drop to approximately -29 ° C to -18 ° C (-20 ° F to 0 ° F). However, it remains quite warm, compared to the melt solid in the melting tray 130, which can be around -45 ° to -57 ° C (-50 ° F to -70 ° F). The steam still has sufficient enthalpy to melt the COa solids as it comes into contact with the melting tray 130.

With reference again to the reheater 160, the fluids in a lower stream 24 leaving the superheater 160 in the form of a liquid can pass through. optionally through an expansion valve 162. The expansion valve 162 reduces the pressure of the lower liquid product, to effectively provide a cooling effect. Therefore, a cooled lower stream 26 is provided. The CO2-rich liquid exiting reheater 160 can be pumped into the well through one or more IGA wells (schematically observed at 250 in Figure 1) . In some situations, liquid C02 can be pumped into a partially recovered oil reservoir as part of an improved oil recovery process. Consequently, C02 could be a miscible injector. As an alternative, C02 could be used as a miscible flood agent for improved oil recovery.

Referring again to the lower distillation zone 160 of the tower 100, the gas moves upwardly through the lower distillation zone 106, through the chimneys 131 in the melting tray 130, and into the interior of the the controlled freezing zone 108. The controlled freezing zone 108 defines an open chamber having a plurality of spray nozzles 122. As the steam moves upwardly through the controlled freezing zone 108, the steam becomes much colder. The vapor is contacted with the liquid methane ("reflux") that comes from the spray nozzles 122. This liquid methane is much colder than the steam in upward movement, having been cooled by an external cooling unit that includes a heat exchanger 170. In one arrangement, the liquid methane leaves the spray nozzles 122 at a temperature of about -84 ° C (-120 ° F) to -90 ° C (-130 ° F). However, as the liquid methane evaporates, it absorbs heat from its surroundings in order to reduce the temperature of the rising steam. The vaporized methane also flows upward due to its low density (relative to liquid methane) and the pressure gradient inside the distillation tower 100.

As the methane vapors move further up the cryogenic distillation tower 100, they leave the intermediate controlled freezing zone 108 and enter the upper distillation zone 110. The vapors continue to move upward along with other vapors. light gases separated from the original cooled fluid stream 12. The combined hydrocarbon vapors move out of the top of the cryogenic distillation tower 100, to become an upper methane stream 14.

The hydrocarbon gas in the upper methane stream 14 moves in the external refrigeration unit 170. In one aspect, the refrigeration unit 170 utilizes an ethylene refrigerant or other refrigerant capable of cooling the upper methane stream 14 to about -93 ° C to -98 ° C (-135 ° to -145 ° F). This serves to at least partially liquefy the upper methane stream 14. The cooled methane stream 14 is then moved to a reflux condenser or separation chamber 172.

The separation chamber 172 is used to separate the gas 16 from the liquid, sometimes referred to as the "liquid reflux" 18. The gas 16 represents the lighter hydrocarbon gases, mainly methane, from the original crude gas stream. Nitrogen and helium can also occur. The methane gas 16, naturally, is the "product" sought, ultimately, to be captured and marketed, along with any remaining ethane. This non-liquefied portion of the upper methane stream 14 is also available for on-site fuel.

A portion of the upper methane stream 14 leaving the refrigeration unit 170 is condensed. This portion is liquid reflux 18, which is separated in the separation chamber 172 and returned to the tower 100. A pump 19 can be used to move the liquid reflux 18 back to the tower 100. Alternatively, the separation chamber 172 is mounted on the tower 100 in order to provide a gravity feed of the liquid reflux 18. The liquid reflux 18 will include any carbon dioxide that has escaped from the upper distillation zone 110.

However, most of the liquid reflux 18 is methane, typically 95% or more, with nitrogen (if present in the initial fluid stream 10) and minimal amounts of hydrogen sulfide (if it also occurs in the fluid stream). initial 10).

In a cooling arrangement, the upper methane stream 14 is taken through an open ring cooling system, such as the cooling system set forth and described in connection with Figure 6. In this arrangement, the upper methane stream 14 is taken through a cross-exchanger to cool a return portion of the upper methane stream used as the liquid reflux 18. Next, the upper methane stream 14 is pressurized to about 69 bar (1000 psi) to 96 bar (1400 psi), and then, cooled using ambient air, and possibly, an external propane coolant. The pressurized and cooled gas stream is then directed through an expander for subsequent cooling. A turbo expander can be used to recover even more liquid, as well as some stem work. U.S. Patent No. 6,053,007, entitled "Process for separating a multi-component gas stream containing at least one freezing component" describes the cooling of a higher methane stream, and is incorporated into this. application as a reference, in its entirety.

It is understood in this application that the present inventions are not limited to the cooling method for the upper methane stream 14. It is further understood that the degree of cooling between the cooling unit 170 and the initial cooling unit 150 can be varied. In some cases, it may be convenient to operate the refrigeration unit 150 at a higher temperature, and then, be more aggressive with the cooling of the upper methane stream 14 in the refrigeration unit 170. Again, the present inventions are not limited to these types of design choices.

Referring again to Figure 1, the liquid reflux 18 is returned to the upper distillation zone 110. The liquid reflux 18 is then gravitationally transported through one or more mass transfer devices 116 in the upper distillation zone 110. In one embodiment, the mass transfer devices 116 are rectification trays that provide a series of cascading weirs 118 and descent tubes 119, similar to the trays 126 described above.

As the fluids of the liquid reflux stream 18 move downwardly through the rectification trays 116, the additional methane vaporizes from the upper distillation zone 110. The methane gases meet the methane stream upper 14 to form part of the gas product stream 16. However, the remaining liquid phase of the liquid reflux 18 falls on a collection tray 140. As it does so, the liquid reflux stream 18 will inevitably pick up a small percentage of liquid. hydrocarbon and residual acid gases that move upwardly from the controlled freezing zone 108. The liquid mixture of methane and carbon dioxide is collected in a collection tray 140.

The collecting tray 140 preferably defines a substantially flat body for the collection of liquids. However, as with the melting tray 130, the collection tray 140 also has one, and preferably, a plurality of chimneys for venting the gases that come from the controlled freezing zone 108. A chimney and cap arrangement can be used. such as that presented by components 131 and 132 in Figures 2B and 2C. The chimneys 141 and the caps 142 for the collection tray 140 are shown in the enlarged view of Figure 5, which is described in more detail below.

It is noted here that in the upper distillation zone 110, any H2S present has a preference towards dissolution in the liquid, as compared to the gas, at the processing temperature. In this regard, H2S has a comparatively low relative volatility. By contacting the remaining vapor with more liquid, the cryogenic distillation tower 100 lowers the concentration of H2S to be within the desired limit of parts per million (ppm), such as a specification of 10 or even 4 ppm. As the fluid moves through the mass transfer devices 116 in the upper distillation zone 110, the H2S contacts the liquid methane and is entrained out of the vapor phase and becomes a part of the liquid phase. the liquid stream 20. From there, the H2S moves in liquid form down through the lower distillation zone 106 and, ultimately, leaves the cryogenic distillation tower 100 as part of the lower stream of liquefied acid gas 22. For those cases where there is little or no H2S in the feed stream, or if the H2S is selectively removed by an upstream process, practically no H2S will be present in the upper gas.

In the cryogenic distillation tower 100, the liquid captured in the collection tray 140 is extracted outside the upper distillation zone 110 as a liquid stream 20. The liquid stream 20 is composed mainly of methane. In one aspect, the liquid stream 20 is comprised of about 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 at about -87 ° C (-125 ° F) to -90 ° C (-130 ° F). This temperature is only slightly warmer than the liquid reflux stream 18. The liquid stream 20 is directed to a reflow drum 174. The purpose of the reflow drum 174 is to provide stirring capacity for a pump 176. Upon exiting the drum reflux 174, a spray stream 21 is created. The spray stream 21 is pressurized in a pump 176 for a second reintroduction in the cryogenic distillation tower 100. In this case, the spray stream 21 is pumped into the freezing zone intermediate controlled 108 and emitted through the nozzles 122.

A certain portion of the spray stream 21, in particular methane, vaporizes and evaporates as it leaves the nozzles 122. From there, the methane rises through the controlled freezing zone 108, through the chimneys in the collection tray 140, and through the mass transfer devices 116 in the upper distillation zone 110. The methane leaves the distillation tower 100 as the upper methane stream 14, and ultimately, becomes part of the commercial product in the gas stream 16.

The spray stream 21 of the nozzles 122 further causes the desublimation of the carbon dioxide from the gas phase. In this aspect, C02 initially dissolved in liquid methane can momentarily enter the gas phase and move upwards with methane. However, due to the cold temperature within the controlled freezing zone 108, any gaseous carbon dioxide nucleates rapidly and agglomerates into a solid phase, and begins to "snow". This phenomenon is called desublimation. In this way, a certain amount of C02 never enters the liquid phase again until it hits the melting tray 130. This carbon dioxide "snows" on the melting tray 130, and melts in the liquid phase. From there, the C02 rich liquid cascades from the mass transfer devices or the trays 126 in the lower distillation zone 106, together with the liquid CO2 from the cooled raw gas stream 12, as described above. At this point, any remaining methane from the spray stream 21 of the nozzles 122 should quickly separate to form steam. These vapors move upward in the cryogenic distillation tower 100 and enter the upper distillation zone 110 again.

The greatest possible contact of the cooled liquid with the gas moving upwardly of the tower 100 is desirable. If the vapor avoids the spray current 21 emanating from the nozzles 122, high levels of C02 could reach the upper distillation zone 110 of the tower 100. In order to improve the efficiency of the gas / liquid contact in the controlled freezing zone 108, a plurality of nozzles 122 having a designed configuration can be employed. Accordingly, instead of employing a single spray source at one or more levels with the reflux fluid stream 21, several optionally designed spray manifolds 120 with multiple spray nozzles can be used. 122. Therefore, the configuration of the spray nozzles 122 has an effect on the mass and heat transfer that takes place within the controlled cooling zone 108. Furthermore, the nozzles themselves can be designed so as to generate optimum sizes of drop and distribution of area of said drops.

The assignee of this application has previously proposed various nozzle arrangements in copending WO Patent Publication No. 2008/091316, which has the international filing date of November 20, 2007. This application and Figures 6A and 6B are incorporated in FIG. this request as a reference, for the descriptions of the nozzle configurations. The nozzles seek to ensure a 360 ° coverage within the controlled freezing zone 108 and provide good vapor and liquid contact and heat and mass transfer. This, in turn, cools more efficiently any gaseous carbon dioxide that moves upwardly through the cryogenic distillation tower 100.

The use of multiple manifolds 120 and a corresponding arrangement of overlap nozzles 122 for full coverage also minimizes inverse mixing. In this regard, full coverage prevents fine particles of low mass CO2 from moving back up from distillation tower 100 and back into the upper distillation zone 0. These particles would then remix with methane and enter again in the top 14 methane stream, only to be recycled again.

The above acid gas removal system described in relation to Figure 1 is profitable for the production of a commercial methane product 16 which is substantially free of acid gases. The product 16 is preferably liquefied and sent through a pipeline for sale. The liquefied gas product, preferably, meets a C02 pipe specification of 1 to 4 mole percent, where enough reflux is generated. Carbon dioxide and hydrogen sulfide are removed through the lower stream 22.

In some cases, small amounts of H2S are present with relatively large amounts of C02 in the crude initial fluid stream 10. In this case, it may be convenient to selectively remove the H2S before the cryogenic distillation tower, in order to produce a "clean" liquid C02 stream in the lower stream 22. In this way, C02 can be injected directly into a reservoir for enhanced oil recovery operations ("EOR", in its acronym in English). Therefore, systems and methods for the removal of a portion of the sulfur components produced with the initial fluid stream 10 before the removal of acid gas in a cryogenic distillation tower such as the tower are proposed in this application. 100 A number of selective H 2 S processes are proposed in this application for the removal of the sulfurous components from a gas stream. Both aqueous and non-aqueous processes are described. Preferably, the processes remove any sulfhydryl compound such as hydrogen sulfide (H2S) and organosulfur compounds having a sulfhydryl group (-SH), known as mercaptans, also known as thiols (R-SH), where R is a hydrocarbon group.

A first method for the removal of upstream sulfur components from an acid gas removal system employs the use of solvents. Certain solvents have an affinity for hydrogen sulfide and can be used to remove H2S from methane. The solvents can be either physical or chemical solvents.

Figure 6 is a schematic diagram showing a gas processing facility 600 for the removal of acid gases from a gas stream, in one embodiment. The gas processing facility 600 employs a rising upstream solvent process of an acid gas stripping system. The acid gas removal system is generally indicated by 650, while the solvent process is indicated by Block 605. The acid gas removal system 650 includes a separation vessel in Block 100. Block 100 generally indicates the tower of the controlled freezing zone 100 of Figure 1. However, Block 100 may also represent any cryogenic distillation tower such as a bulk fractionation tower.

In Figure 6, a production gas stream is shown at 612. The gas stream 612 originates from the hydrocarbon production activities that take place in a reservoir development area, or "reservoir" 610. It is understood that the 610 reservoir can represent any location where gaseous hydrocarbons are produced.

The 610 deposit can be on land, near the coast or offshore. The 610 reservoir can operate from an original reservoir pressure, or it can be subjected to improved recovery procedures. The systems and methods claimed in this application are not limited to the type of deposit that is in development, provided that hydrocarbons contaminated with hydrogen sulfide and carbon dioxide are produced. The hydrocarbons will mainly comprise methane, although, in addition, they include 2 to 10 mole percent of ethane and other heavy hydrocarbons such as propane or even minimal amounts of butane and aromatic hydrocarbons.

The 612 gas stream is "gross", which means that it has not gone through acid gas removal processes. The raw gas stream 612 can be passed through a pipeline, for example, from the reservoir 610 to the gas processing facility 600. Upon arrival at the gas processing facility 600, the gas stream 612 can be directed to through a dehydration process, such as a glycol dehydration vessel. A dehydration vessel is schematically shown at 620. As a result of the passage of the stream of raw gas 612 through the dehydration vessel 620, an aqueous stream 622 is generated. In some cases, the stream of raw gas 612 can be mixed with monoethylene glycol (MEG) in order to prevent water fall and hydrate formation. The MEG can be sprayed on a cooler, for example, and liquids, collected for separation in water, more concentrated MEG and possibly, some heavy hydrocarbons, according to the temperature of the cooler and the composition of the inlet gas.

The aqueous stream 622 can be sent to a water treatment facility. Alternatively, the aqueous stream 622 can be reinjected into a subsurface formation. A subsurface formation is indicated in block 630. Still alternatively, the removed aqueous stream 622 can be treated in order to comply with the environmental guidelines, and then, released in the local basin (not exposed) as treated water.

In addition, as a result of the passage of the production gas stream 612 through the dehydration vessel 620, a substantially dehydrated methane gas stream 624 is produced. The dehydrated gas stream 624 may contain minimal amounts of nitrogen, helium and others. inert gases. In relation to the present systems and methods, the dehydrated gas stream 624 also includes carbon dioxide and small amounts 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 is passed, optionally, through a preliminary cooling unit 625. The cooling unit 625 cools the dehydrated gas stream 624 to a temperature of about -7 ° C to 10 ° C ( 20 ° F to 50 ° F). The cooling unit 625 can be, for example, an air cooler or an ethylene or propane cooler.

It is convenient to remove the sulfur components from the dehydrated gas stream 624 in order to avoid corrosion of iron sulfide. According to the gas processing facility 600, a solvent system 605 is provided. The dehydrated gas stream 624 enters the solvent system 605. The solvent system 605 is brought into contact with the gas stream 624 with a solvent in order to eliminate hydrogen sulfide through an absorption process. This takes place at relatively low temperatures and at relatively high pressures, where the solubility of the acid gas components is greater than that of the methane.

As noted, the solvent system 605 can be either a physical solvent system or a chemical solvent system. Figure 7A provides a schematic diagram of a physical solvent system 705A, in one embodiment. The physical solvent system 705A operates in order to bring the dehydrated gas stream 624 into contact in order to remove the sulfur components.

Examples of suitable physical solvents include N-methyl pyrrolidone, propylene carbonate, methyl cyanoacetate and chilled methanol. A preferred example of a physical solvent is sulfolane, which has a chemical designation of tetramethylene sulfone. Sulfolane is an organosulfur compound that contains a sulfonyl functional group. The sulfonyl group is a sulfur atom double bonded to two oxygen atoms. The double bond of sulfur-oxygen is highly polar, in order to allow high solubility in water. At the same time, the four-carbon ring provides affinity for hydrocarbons. These properties allow the miscibility of sulfolane in both water and hydrocarbons, in order to achieve its disseminated use as a solvent for the purification of hydrocarbon mixtures.

A preferred physical solvent is Selexol ™. Selexol ™ is a trade name for a gas treatment product of Union Carbide, a subsidiary of the Dow Chemical Company. Selexol ™ solvent is a mixture of dimethyl ethers of polyethylene glycols. An example of one of said components is dimethoxy tetraethylene glycol. Selexol® will also collect any heavy hydrocarbon in the initial fluid stream 10, as well as a certain amount of water. When the initial fluid stream 10 is quite dry in the beginning, the use of Selexol ™ can eliminate the need for further dehydration. It is observed here that if the solvent Selexol ™ is cooled and then is presaturated with CO2, the solvent Selexol ™ will be selective towards H2S.

With reference to Figure 7A, a stream of dehydrated gas 624 can be observed entering an inlet separator 660. It is understood that it is It is convenient to keep the 624 gas stream clean, so as to avoid the foaming of liquid solvent during the acid gas removal process. Therefore, the inlet separator 660 is used to filter liquid impurities such as sludge and oil-based drilling fluids. In addition, some particle filtration can take place. Preferably, the brine is separated using the upstream dewatering vessel 620. However, the inlet separator 660 can remove any condensed hydrocarbon.

Liquids such as drilling fluids and condensed hydrocarbons are separated from the base of inlet separator 660. A stream of liquid impurities is observed at 662. Water-based impurities are typically sent to a water treatment facility (unexposed) ), or they can be reinjected into the 630 formation in order to sustain the reservoir pressure or for waste. The hydrocarbon liquids are generally sent to a condensate treatment plant. The gas leaves the top of inlet separator 660. A clean gas stream is observed at 664.

The clean gas stream 664 is optionally directed to a gas gas exchanger 665. The gas gas exchanger 665 precools the gas in the clean gas stream 664. The clean gas is then directed to an absorbent 670. The absorbent 670 , preferably, it is a countercurrent contact tower that receives an absorbent. In the arrangement of Figure 7A, the clean gas stream 664 enters the base of the tower 670. At the same time, the physical solvent 696 enters the top of the tower 670. The tower 670 may be a tower of trays , a packed tower, or another type of tower.

It is understood that, alternatively, any number of non-tower type devices designed for gas and liquid contact can be used. These may include static mixers and joint current contact devices. The countercurrent tower 670 of Figure 7A is presented purely for illustrative purposes. It should be noted that the use of compact, current contactors is preferred joint, for gas and liquid contact containers, since these can reduce the overall trace and weight of the physical solvent system 705A.

The absorbent can be, for example, a solvent that is mixed with the stream of clean gas 664 to "separate" the H2S, and incidentally, a certain amount of CO2. The absorbent can be, specifically, Selexol®, described above. As a consequence of the process of contacting the absorber, a light gas stream 678 is generated. The light gas stream 678 comes from the upper part of the tower 670. The light gas stream 678 contains methane and carbon dioxide. The light gas stream 678 goes through a cooling process before being directed to the cryogenic distillation tower, shown schematically in Block 100 of Figure 6.

Again, with momentary reference to Figure 6, the light gas stream 678 leaves the physical solvent system 705A and passes through a cooler 626. The cooler 626 cools the light gas stream 678 to a temperature of about -34. at -40 ° C (-30 ° to -40 ° F). The cooler 626 may be, for example, an ethylene or propane cooler.

The light gas stream 678 is then preferably moved through an expansion device 628. The expansion device 628 may be, for example, a Joule-Thompson valve ("J-T"). The expansion device 628 serves as an expander to obtain additional cooling of the light gas stream 678. The expansion device 628 further reduces the temperature of the light gas stream 678, for example, to approximately -57 ° C to - 62 ° C (-70 ° F to -80 ° F). Preferably, an at least partial liquefaction of the gas stream 678 is also achieved. A stream of cooled gas is produced in the line 611.

Referring again to Figure 7A, the contact tower 670 will collect sulfur components. These are released from the base of the 670 tower as a "rich" solvent. A stream of rich solvent 672 leaving the tower 670 is observed.

The solvent solvent stream 672 may also include a certain amount of carbon dioxide.

In the arrangement of Figure 7A, the rich solvent stream 672 is transported through a dust recovery turbine 674. This allows the generation of electrical energy for the physical solvent system 705A. From there, rich solvent stream 672 is transported through a series of flash separators 680. In the illustrative arrangement of Figure 7A, three spacers are shown at 682, 684 and 686. Separators 682, 684 and 686 operate at progressively lower pressures and temperatures according to the physical solvent process.

The first separator 682 can operate, for example, at a pressure of 34 bar (500 psi) and at a temperature of 32 ° C (90 ° F). The first separator 682 releases light gases transported in the solvent stream 672. These light gases, exposed at 681, comprise mainly methane and carbon dioxide, although they may have minimal amounts of H2S. The light gases 681 can be directed to the cryogenic distillation tower 100 (not shown in Figure 7A). These gases can be combined with the light gas stream 678. The light gases 681 preferably travel through a compressor 690 in order to reinforce the pressure en route to the cryogenic distillation tower 100 as the stream 61. Compression may not be necessary if the distillation tower 100 is operated at a lower pressure than the first flash stage, i.e., the first separator 682, of the solvent processes 705A. In such a case, a pressure drop for the upper stream 678 will be required, in order to be able to combine the streams 681 and 678. This pressure drop can be induced by a JT valve near the cryogenic distillation tower 100. Naturally, the 681 current will have to be introduced downstream of the JT valve.

Ideally, all of the hydrogen sulfide and heavy hydrocarbons in clean gas stream 664 have been captured with solvent stream 672. A progressively richer solvent stream is released from each separator 682, 684 and 686. These streams progressively richer are denoted as lines 683, 685 and 687. Accordingly, the physical solvent is generally regenerated by the reduction of pressure, to achieve the flash of any undissolved methane and carbon dioxide, from the solvent.

Line 687 is a "half-life" solvent stream, because a certain amount of CO2 has been removed, although solvent stream 687 has not been completely regenerated. A portion of this solvent stream 687 is transported through a booster pump 692 and reintroduced into the contact tower 670 as a semi-black solvent, at an intermediate level in the contact tower. The remaining portion, exposed at 693, is directed to a regeneration vessel 652.

In relation to the second 684 and the third 686 of the three separators, it is observed that each of these separators 684 and 686 also releases very small amounts of light gases. These light gases will mainly include carbon dioxide and small amounts of methane. These light gases are shown in two separate lines at 689. The light gases 689 can be compressed and combined with the line 611, and then, they can be directed to the cryogenic distillation tower 100. Alternatively, the light gases of the lines 689 can be supplied directly to a lower liquefied acid gas stream exposed at 642 in Figure 6.

An advantage of the use of a physical solvent for the removal of upstream H2S is that the solvent is generally hygroscopic. This can eliminate the need for a gas dehydration vessel 620, in particular, where the initial fluid stream 10 is already substantially dry. For this purpose, it is preferable that the selected solvent itself is not aqueous. In this way, the solvent can be used in order to further dehydrate the crude natural gas. In this case, the water may exit in a steam stream 655 of the regenerator 652.

A disadvantage of this process is that some light hydrocarbons and C02 will coadministered in the physical solvent at some range. The use of multiple separators 682,684 and 686 does remove most of the methane from the solvent stream 672, although, typically, not the entirety.

Referring again to the regeneration vessel 652, the vessel 652 acts as a stabilizer. The hydrogen sulfide components are conducted to the outside, so that they exit the regeneration vessel 652 through the steam stream 655 as a concentrated H2S stream. The H2S concentrated in steam stream 655 is shown coming out of the physical solvent system 705A. It is also shown on line 655 in Figure 6.

The H2S concentrated in the vapor stream 655, preferably, is sent to an acid gas injection (IGA) installation. Optionally, a second physical solvent process can be used, before the elimination of any amount of C02 and water vapor. A separator is shown at 658. Separator 658 is a reflux vessel that recovers condensed water and solvent while allowing the gas to rise. The condensed water and the solvent can be returned to the regeneration vessel 652 through the lower line 659. At the same time, the upper gas can be sent to the acid gas injection (shown schematically in Block 649 of Figure 6). and described below) through line 691.

The steam stream 655 will also include carbon dioxide. The carbon dioxide and any water vapor will leave the separator 658 through the upper line 691, together with the H2S. Preferably, the H2S is sent downstream to the IGA installation 649, or optionally, it can be sent to a sulfur recovery unit (URA) (not exposed).

The regeneration vessel 652 shown in Figure 7A can utilize a stabilization gas to remove sulfurous components from the solvent. The regeneration vessel 652 can be fed with any amount of stabilization gases. An example is a fuel gas stream with a high C02 content. A fuel gas with a high C02 content is preferred for stabilization gas 651, since it can help to "presaturate" the solvent with C02, in order to lead to less C02 collection from the clean gas stream 664. stabilizing gas fed to regeneration vessel 652 through line 651 '. The stabilization gas 651 'for example, may be a portion of the light gas stream 689 of the lower pressure flash stage, ie, the separator 686. This allows a potential recovery of a certain amount of the hydrocarbons.

The regenerated solvent is directed from the base of the regeneration vessel 652. The regenerated solvent exits as 653. The regenerated solvent 653 is transported through a booster pump 654. Optionally, a second booster pump 694 is used in order to ascend additionally the pressure in the line carrying regenerated solvent 653. Next, the regenerated solvent 653 is cooled, preferably, through a heat exchanger 695 possibly having a cooling unit. Next, a cooled and regenerated solvent 696 is then recycled back to contactor 670.

A portion of the regenerated solvent is taken from the base of the regeneration vessel 652 and sent to a reheater 697. The superheater warms the solvent. The warmed solvent is returned to the regeneration vessel 697 through line 651"as a partially vaporized stream.

Figure 7A demonstrates an embodiment of a physical solvent system 705A. However, as noted, the solvent system 605 may alternatively be a chemical solvent system. The chemical solvent system will use chemical solvents, in particular, selective amines of hfeS. Examples of such selective amines include methyl diethanol amine (MDEA) and the family of Flexsorb® amines. Flexsorb® is a registered trademark for a chemical absorbent used in the removal of sulfurous gases from a mixture of bitter gas. A Flexsorb® absorber or other amine is contacted with the hydrocarbon gas stream 624 or a clean gas stream 664 upstream of a cryogenic distillation tower.

Amine-based solvents are held in a chemical reaction with the acid gas components in the hydrocarbon gas stream. The process of the reaction is sometimes called "gas sweetening." Such chemical reactions, in general, are more effective than physical-based solvents, in particular, at feed gas pressures below about 2.07 Pa (300 psia).

Flexsorb® amines are preferred chemical solvents for the selective removal of H2S from gas streams containing CO2. Flexsorb® amines benefit from the relatively fast rate of absorption of H2S, compared to the absorption of C02. The rapid rate of absorption helps prevent the formation of carbamates. Hydrogen sulfide generated from amine-based processes is generally at low pressure. The exit H2S will suffer the recovery of sulfur, or underground waste, which requires significant compression.

The removal of hydrogen sulphide using a selective amine can be achieved by contacting the dehydrated fluid stream and cooling 624 with the chemical solvent. This can be done by injecting the gas stream 624 into an "absorbent". The absorbent is a container that allows contact of the 624 gas stream with the Flexsorb ™ solvent or other liquid amine. As the two fluid materials interact, the amine absorbs H2S from the bitter gas, to produce a stream of sweetened gas. The sweetened gas stream contains mainly methane and carbon dioxide. This "sweet" gas flows out of the top of the absorbent.

In one aspect, the absorbent is a large countercurrent contact tower.

In this arrangement, the 624 crude gas stream is injected into the base of the contact tower, while the chemical solvent, or "lean solvent stream", is injected into the top of the contact tower. Once inside the countercurrent flow contact tower, the gas in the gas stream 624 moves upwardly through the absorbent. Usually, one or more trays or other internal elements (not exposed) are provided inside the absorbent, in order to create multiple flow paths for the natural gas, and to create interfacial area between the gas and liquid phases. At the same time, the liquid of the lean solvent stream moves downward and through the succession of trays in the absorbent. The trays help the interaction of natural gas with the solvent stream. This process is demonstrated in connection with Figure 1 of a patent application entitled: "Removal of acid gases from a gas stream". This request was provisionally presented on October 14, 2008, and it was assigned Act No. U. S. 61 / 105.343. Figure 1 and corresponding portions of the specification are incorporated in this application for reference.

A "rich" amine solution leaves the base of the countercurrent contact tower. This comprises the liquid amine, together with the absorbed H2S. The rich amine solution is carried through a regeneration process that can be very similar to the regeneration components described in Figure 7A, above, in relation to the physical solvent system 705A, although, usually, it only has a single flash vessel operating at 7-14 bar (100-200 psig).

The countercurrent contact tower used as an absorbent for the separation of H2S tends to be very large and heavy. This creates particular difficulty in offshore oil and gas production applications. Accordingly, an alternative embodiment for the removal of H2S from hydrocarbon gas streams, inherent in the recovery of oil and gas, is proposed in this application. This embodiment involves the use of smaller countercurrent contacting devices. These devices can improve the selectivity of the amine by reducing contact time, and thus, reducing the possibility of C02 absorption. These smaller absorbent devices can also reduce the size of the total trace of the 605 process.

Figure 7B demonstrates an illustrative embodiment of a chemical solvent system 705B, which can be used for the solvent process 605 of Figure 6. The chemical solvent system 705B employs a series of joint flow contact devices CD1, CD2 ,. .., CD (n-1), CDn. These devices are used to contact the selective amine with the gas stream.

The concept of joint current flow uses two or more contactors in series, where a stream of bitter gas and a liquid solvent move together inside the contactors. In one embodiment, the bitter gas stream and the liquid solvent move together generally along the longitudinal axis of the respective contactors. The joint current flow contactors can operate at much higher fluid speeds. Consequently, the joint current flow contactors tend to be smaller than the countercurrent flow contactors, which use packed towers or trays.

As with Figure 7A, a stream of dehydrated gas 624 can be observed entering an inlet separator 660. The inlet separator 660 serves to filter out liquid impurities such as oil and mud-based drilling fluids. The brine is preferably separated using the upstream dewatering vessel 620, set forth in Figure 6. Some particle filtration may also take place in the inlet separator 660. It is understood that it is convenient to keep the gas stream 624 clean, so to avoid foaming of the liquid solvent during the acid gas treatment process.

Liquids such as condensed hydrocarbons and drilling fluids exit the base of the inlet separator 660. A stream of liquid impurities is observed in 662. The impurities carried by the water are typically sent to a water treatment facility (not exposed) , or they can be reinjected into the 630 formation with line 662 in order to sustain reservoir pressure or for disposal. Hydrocarbon liquids typically go to a condensate treatment instrument. The gas leaves the top of the inlet separator 660. A clean sour gas stream is observed at 664.

The clean bitter gas is directed to a series of absorbents. Here, the absorbers are joint current contact devices CD1, CD2, ..., CD (n-1), CDn. Each contactor CD1, CD2 CD (n-1), CDn removes a portion of the content of H2S of the gas stream 664, in order to liberate a progressively sweetened gas stream. A final contactor CDn provides a final sweetened gas stream 730 (n) comprising substantially methane and carbon dioxide. The gas stream 730 (n) becomes line 678 of Figure 6.

In operation, the gas stream 664 enters a first joint current absorber, or contact device, CD1. There, the gas is mixed with a liquid solvent 720. The solvent 720 preferably consists of an amine solution such as methyldiethanol amine (MDEA), or a Flexsorb® amine. The liquid solvent may further comprise an hindered amine, a tertiary amine, or combinations thereof. Flexorb® is an example of an hindered amine, while MDEA is an example of a tertiary amine. In addition, the solvent stream 720 is a partially regenerated or "semi-coarse" solvent produced by a regenerator 750. The movement of the "semi-coarse" solvent 720 in the first contactor CD1 is aided by a pump 724. The pump 724 moves the semi-coarse solvent 720 to the first contactor CD1 at reduced pressure. An example of an adequate pressure is approximately 1 to 103 bar (15 psia to 1500 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 travel, the liquid amine (or other solvent) interacts with the H2S in the 664 gas stream, to produce the chemical binding of H2S to amine molecules, or absorption by these molecules. A first "rich" solvent solution 740 (1) exits the bottom of the first contactor CD1. At the same time, a first partially sweetened gas stream 730 (1) moves out of the first contactor CD1 and is released to a second contactor CD2.

The second contactor CD2 also represents a joint current separation device. Optionally, a third joint current separating device CD3 is provided after the second contactor CD2. Each of the second and third contactors CD2, CD3, generates a respective partially sweetened gas stream, 730 (2), 730 (3). In addition, each of the second and third contactors, CD2, CD3, generates a respective partially charged gas treatment solution, 740 (2), 740 (3). When an amine is used as the solvent, the partially charged gas treatment solutions 740 (2), 740 (3) will comprise rich amine solutions. In the illustrative system 705B, the second charged gas treatment solution 740 (2) is melted with the first charged gas treatment solution 740 (1) and goes through a regeneration process, which includes passing through the regenerator 750 .

It is noted that as the 664 gas moves through the progressively sweetened gas streams 730 (1), 730 (2), ... 730 (n-1) in a downstream direction, the pressure in the system it will generally decrease. As this happens, the pressure in the progressively richer amine streams (or other liquid solvent) 740 (n), 740 (n-1), ... 740 (2), 740 (1) in the current direction Ascending generally needs to increase to match gas pressure. Accordingly, placement in the system 705B of one or more booster pumps (unexposed) between each of the contactors CD1, CD2, ... This will serve to reinforce the liquid pressure in the system is preferred.

In the system 705B, the streams 740 (1), 740 (2) comprise "rich" solvent solutions that first move through the flash drum 742. The flash drum 742 operates at a pressure of about 7 to 10 bar (100 to 150 psig). Flash drum 742 typically has internal parts that create a settling effect of a sinuous flow path for solvent stream 740. Waste gases such as methane and C02 are flashed from solvent stream 740 through line 744 The waste gases captured in line 744 can be reduced to an acid gas content of about 100 ppm, if they are contacted, for example, with a small amount of fresh amine from line 720. This concentration is sufficiently low so that the waste gases can be used as fuel gas for the 705B system.

The residual natural gas can be flashed from solvent stream 740 through line 744. The resulting rich solvent stream 746 is directed to a regenerator 750.

Before moving in the regenerator 750, the rich solvent stream 746 is preferably moved through a heat exchanger (not shown). The relatively cold solvent stream (close to room temperature) 746 can be heated by the term contact with a warm lean solvent stream 760 leaving from the base of the regenerator 750. This, in turn, serves to beneficially cool the current of lean solvent 760 before delivery to a lean solvent cooler 764, and then, to a final contactor CDn.

The regenerator 750 defines a stabilizing portion 752 comprising trays or other internal elements (not exposed) on a reheater 756. A heat source is provided to a reheater 756 in order to generate heat. The regenerator 750 produces the stream of regenerated or "lean" solvent 760, which is recycled for reuse in the final contactor CDn. The stabilized upper gas of the regenerator 750 containing concentrated H2S leaves the regenerator 750 as a stream of impurities 770.

The impurity stream rich in H2S 770 is moved to a condenser 772. The condenser 772 serves to cool the impurity stream 770. The cooled impurity stream 770 is moved through a reflux accumulator 774 that separates any remaining liquid (in most, condensed water) of impurities stream 770. A stream of acidic gas 776 is then created which mainly comprises H2S. Acid gas stream 776 is the same as line 655 of Figure 6.

A certain amount of liquid can fall out of the reflux accumulator 774. This produces a waste liquid stream 775. The waste liquid stream 775 is preferably conveyed through a pump 778 to boost the pressure, where it is then reintroduced into the regenerator 750. A certain amount of the residual liquid will leave the regenerator 750 at the base as part of the stream of lean solvent 760. Optionally, some water content can be added to the stream of lean solvent 760, in order to balance the loss of water vapor for sweetened gas streams 730 (n-1), 730 (n). This water can be added to the ingestion or suction of the reflux pump 778.

The lean or regenerated solvent 760 is at low pressure. Therefore, the liquid stream representing regenerated solvent 760 is conveyed through a pressure booster pump 762. The pump 762 is referred to as a lean solvent booster 762. From there, the lean solvent 760 passes through a cooler 764. Cooling of the solvent by means of cooler 764 ensures that lean solvent 760 will absorb acid gases efficiently. The cooled lean solvent 760 is used as the solvent stream for the last separation contactor CDn.

Optionally, a solvent tank 722 is provided close to the contact devices CD1, CD2, CD (n-1), CDn. The lean solvent 760 can pass through the solvent tank 722. More preferably, the solvent tank 722 is off-line and provides a solvent reservoir, when it may be necessary for the installation of 705B gas.

Referring again to the plurality of joint current contact devices CD1, CD2, ... CD (n-1), CDn, each contact device receives a gas stream that includes a hydrocarbon gas and a hydrogen sulfide. Each contact device CD1, CD2, ... CD (n-1), CDn operates to successively remove the H2S and produce a progressively sweetened gas stream. The joint current contact devices CD1, CD2, ... CD (n-1), CDn can be any of a variety of short contact time mixing devices. Examples include static mixers and centrifugal mixers. Some mixing equipment separates liquid through an eductor. The eductor supplies gas through a Venturi-type tube that, in turn, draws liquid solvent into the tube.

Due to the Venturi effect, the liquid solvent is entrained and decomposed into small droplets, in order to allow a large surface area of contact with the gas.

A preferred contact device is the ProsCon ™ contactor. This contactor uses an eductor, followed by a centrifugal agglutinator. The centrifugal binder induces large centrifugal forces for the reintegration of the liquid solvent in a small volume. In any embodiment, the technology of compact container is preferably used, in order to allow the reduction of physical support in comparison with the large contact towers.

The first contactor CD1 receives the stream of raw gas 664. The gas stream 664 is treated in the first contactor CD1 for the removal of hydrogen sulphide. Then a first partially sweetened gas stream 730 (1) is released. The first partially sweetened gas stream 730 (1) is supplied to the second contactor CD2. There, the first stream of sweetened gas 730 (1) is further treated for the removal of hydrogen sulfide, so that a second stream of more fully sweetened gas 730 (2) is released. This pattern is continued so that a third contactor CD3 produces a more fully sweetened gas stream 730 (3); a fourth contactor CD4 produces an even sweeter gas stream 730 (4); and a next and last contactor produces an even sweeter gas stream CD (n-1). Each of these can be termed a "subsequent" sweetened gas stream.

A final sweetened gas stream 730 (n) is released by the final contactor CDn. The number of contact devices (at least two) before the final contactor CDn is dictated mainly by the level of H2S removal required to meet the desired standards. In system 705B of Figure 7, the final sweetened gas stream 730 (n) still contains carbon dioxide. Therefore, the sweetened gas stream 730 (n) must be taken through the CFZ tower 100 of Figure 6. The sweetened gas stream 730 (n) is the same as line 678 of Figure 6.

In one aspect, a combination of a mixing device and a corresponding binder device is used in each contactor. Consequently, for example, the first contactor CD1 and the second contactor CD2 can use static mixers as their mixing devices, the third contactor CD3 and other contactors CD4 can use eductors, and the contactors CDn-1 and CDn can use centrifugal mixers. Each contactor has an associated agglutination device. In any embodiment, the gas streams 664, 730 (1), 730 (2), ... 730 (n-1) and the liquid solvent streams in joint current flow through the contactors CD1, CD2, ... CDn at the same address. This allows a short period of time for the treatment reactions to take place, perhaps, even as short as 100 milliseconds or less. This may be convenient for the selective removal of H2S (relative to C02), since certain amines react more rapidly with H2S than with CO2.

In addition to receiving a gas stream, each co-current contactor CD1, CD2, ... CD (n-1), CDn also receives a stream of liquid solvent. In system 705B, first contactor CD1 receives a partially regenerated solvent stream 720. Next, subsequent contactors CD2, CD3, CD (n-1), CDn receive charged solvent solutions released from the next respective contactor. Accordingly, the second contactor CD2 receives partially charged solvent solution 740 (3) released from the third contactor CD3; the third contactor CD3 receives a partially charged solvent solution 740 (4) released from the fourth contactor CD4; and the next and last CD contactor (n-1) receives a partially loaded solvent solution 740 (n) from the final contactor CDn. In other words, the liquid solvent received in the second contactor CD2 comprises the partially charged solvent solution 740 (3) released from the third contactor CD3; the liquid solvent received in the third contactor CD3 comprises the partially charged solvent solution 740 (4) released from the fourth contactor CD4; and the liquid solvent received in a subsequent contactor and last CD (n-1) comprises the solvent solution partially loaded 740 (n) of the final contactor CDn. In this way, partially charged solvent solutions are introduced into the contactors CD1, CD2, CD3, ... CDn in a processing direction opposite to that of the progressively sweetened gas streams 730 (1), 730 (2), 730 (3), ... 730 (n-1).

The last separation contactor CDn also receives a liquid solvent. The liquid solvent is the stream of regenerated solvent 760. The stream of regenerated solvent 760 is highly lean.

The chemical solvent system 705B of Figure 7B is intended to be illustrative. Other arrangements may be used for such a system employing a plurality of joint current contact devices as absorbers. An example of such an additional system is described in the context of the elimination of C02 in the United States Act No. 61 / 105,343, referenced above. Figure 2B and corresponding portions of the specification are also incorporated in this application by way of reference.

In system 705B of Figure 7B, both solvent solutions 740 (1) and 740 (2) go through regeneration. The partially regenerated solvent 780 leaves the regeneration vessel 750. The solvent 780 is placed under pressure through the booster pump 782. From there, the solvent 780 is cooled in the heat exchanger 784, to become the solvent stream 720. The solvent 780 is further pressurized through the booster pump 724, before being introduced into the first joint current contactor CD1 as the solvent stream 720.

Referring again to Figure 6, the light gas stream 678 (which is also line 678 in Figure 7A and line 730 (n) in Figure 7B) exits the solvent system 605, passes through a dehydrator , and passes through a cooler 626. The cooler 626 cools the light gas stream 678 to a temperature of about -34 to -40 ° C (-30 ° to -40 ° F). The cooler 626 may be, for example, an ethylene or propane cooler.

The light gas stream 678 below is preferably moved through an expansion device 628. The expansion device 628 may be, for example, a Joule-Thompson valve ("J-T"). The expansion device 628 serves as an expander in order to obtain additional cooling of the light gas stream 678. The expansion device 628 further reduces the temperature of the light gas stream 678 to, for example, about -57 °. C at -62 ° C (-70 ° F to -80 ° F). Preferably, at least partial liquefaction of the gas stream 678 is also achieved. The cooled gas stream is indicated on line 611.

The bitter gas cooled in line 611 enters the cryogenic distillation tower 100. The cryogenic distillation tower 100 can be any tower that operates to distill the methane from the acid gases through a process that intentionally freezes CO2 particles. The cryogenic distillation tower may be, for example, the CFZ ™ 100 tower of Figure 1. The cooled bitter gas from line 611 enters tower 100 at approximately 34 to 41 bar (500 to 600 psig).

As explained in relation to Figure 1, the acid gases are removed from the distillation tower 100 as a lower stream of liquefied acid gas 642. In this case, the lower stream of acid gas 642 comprises mainly carbon dioxide. The lower stream of acid gas 642 contains very little hydrogen sulfide or other sulfur components, since these are captured by the sulfur component removal system (which is solvent system 605) and supplied as the concentrated H2S stream 655 for the additional processing. The H2S can be converted to elemental sulfur using a sulfur recovery unit (not exposed). The sulfur recovery unit can be a so-called Claus process. This allows the recovery of more efficient sulfur for large amounts of sulfur.

At least part of the bottom stream 642 is sent through a reheater 643. From there, the methane-containing fluid is redirected back to the tower 100 as a gas stream 644. The remaining fluid compound mainly by carbon dioxide is released through the line of C02 646. C02 in line 646 is presented in liquid form. The carbon dioxide in line 646 is preferably passed through a booster 648, and then injected in a subsurface formation through one or more acid gas injection wells (IGA), as indicated in block 649.

The methane is released from the distillation tower 100 as a top methane stream 112. The top methane stream 112, preferably, will comprise no more than about 2 mole percent carbon dioxide. With this percentage, the upper methane stream 112 can be used as a fuel gas, or it can be marketed in certain markets as natural gas. However, according to certain methods of this application, it is desirable that the top methane stream 112 passes through further processing. More specifically, the top methane stream 112 is passed through an open loop cooling system.

First, the upper methane stream 112 passes through a cross-over exchanger 113. The cross-over exchanger 113 serves to pre-congeal the liquid reflux stream 8 introduced in the cryogenic distillation tower 100 after expansion through a expander device 19. The top methane stream 112 is then sent to a compressor 114, in order to increase its pressure.

Next, the pressurized methane stream 112 is cooled. This cooling can be done, for example, by passing the methane stream 112 through an air cooler 115. A cold, pressurized methane stream 116 is produced. The methane stream 116 is preferably liquefied in order to generate a commercial product.

A portion of the cooled and pressurized methane stream 116 leaving the cooler 115 is divided into the reflux stream 18 The reflux stream 18 is additionally cooled in the heat exchanger 113, then expanded through the expander device 19 so as to of generating, ultimately, the current of cold spray 21 of Figure 1. The cold spray stream 21 enters the distillation tower 100, where it is used as a cold liquid spray. Liquid spraying, or reflux, reduces the temperature of the controlled freezing zone (shown at 108 in Figure 1) and helps freeze C02 or other acid gas particles to remove them from the dehydrated gas stream 624, as described before.

It will be appreciated that Figure 6 represents a simplified schematic diagram proposed to clarify only selected aspects of the gas processing system 600. A gas processing system will usually include many additional components, such as heaters, chillers, condensers, liquid pumps, compressors of gas, blowers, other types of separation and fractionation equipment, valves, switches, controllers, together with pressure, temperature, level and flow measuring devices.

Other methods for the removal of sulfurous components from a stream of crude gas are provided in this application. One such method is referred to by the term "redox" processes. The term "redox" represents a reduction-oxidation reaction. Reduction-oxidation describes chemical reactions in which atoms have their oxidation number or oxidation state changed. In the redox process of the present invention, an oxidized metal, such as chelated iron, reacts directly with H2S, to form elemental sulfur.

Oxidized metal is an aqueous chelated metallic catalyst solution. In operation, the gas stream containing hydrogen sulfide is contacted with the chelated metal catalyst to effect absorption. The subsequent oxidation of the hydrogen sulfide to elemental sulfur and the concurrent reduction of the metal to a lower oxidation state take place. The catalyst solution is then regenerated for reuse by its contact with a gas containing oxygen, in order to oxidize the metal back to a higher oxidation state.

Figure 8 is a schematic diagram showing a gas processing facility 800 for the removal of acid gases from a stream of raw gas. In this arrangement, the hydrogen sulfide is removed from a stream of raw gas from an acid gas removal system 650 by means of a redox process. The redox process is water based, which means that the dehydration of the crude gas stream does not necessarily have to take place before the start of the H2S removal stages.

Figure 8 shows the gas processing facility 800 that receives a production gas stream 812. The production gas stream 812 originates from the hydrocarbon production activities that take place in a reservoir development area, or " reservoir "810. It is understood that reservoir 810 can represent any location where gaseous hydrocarbons are produced. The hydrocarbons will comprise methane, as will hydrogen sulfide. The hydrocarbons may also include ethane, as well as carbon dioxide.

In the gas processing facility 800, the gas stream 812 is fed to a sulfur component removal system 850. The sulfur component removal system 850 utilizes a redox process. The sulfur component removal system 850 first comprises contactor 820. Contactor 820 defines a chamber 825 that receives crude hydrocarbon gases from reservoir 810. Once in chamber 825, a chemical reaction separating the hydrogen sulfide and a hydrogen atom occurs. other sulphurous components of the 812 crude gas stream.

In order to produce the chemical reaction, the chamber 820 also receives a chelated oxidized metal. An example of said oxidized metal is chelated iron. The chelated iron is in the form of a metal chelating solution. The metal chelant solution is supplied in chamber 825 through line 842.

Once inside chamber 825, the chelated metal solution reacts with hydrogen sulfide in the raw gas stream 812. A reduction-oxidation reaction takes place. Accordingly, a chelated reduced metal mixture, together with elemental sulfur, is discharged through a lower line 822. At the same time, the gases escape through the upper line 824. The basic reaction is S ~ + 2 Fe +++ - * S ° + 2 Fe ++.

The gases in line 824 mainly comprise methane and carbon dioxide. Minimal amounts of ethane, nitrogen or other components may also be present on line 824. Together, the gases on line 824 represent a bitter gas.

The illustrative sulfur component removal system 850 further includes an oxidant 830. Oxidizer 830 defines a chamber 835 for oxidation of the reduced metal mixture. Oxidizer 830 receives the reduced metal mixture through line 822. The pressure of the metal mixture in line 822 is controlled by valve 828.

The oxidant 830 also receives air. The air is introduced into oxidant 830 through line 834. The pressure in line 834 is increased in order to circulate air through chamber 835 in oxidant 830 by air blower 838. Once inside from chamber 835, the air is brought into contact with the chelated metal mixture, to achieve oxidation of the reduced metal mixture. Air is vented to exit oxidant 830 through vent line 836.

Oxidation produces a mixture of oxidized chelated metal. The chelated mixture also contains sulfur in colloidal form. The chelated sulfur mixture is extracted from oxidant 830 through line 832.

The illustrative sulfur component removal system 850 further includes a separator 840. The separator 840 of Figure 8 is shown as a centrifuge. However, other types of separators can be used. The centrifuge 840 separates the aqueous chelant mixture with sulfur, in two components. One component is elemental sulfur. Elemental sulfur is continuously removed from the process, as a solid product with high purity. The contact process, preferably, it is limited to comparatively low pressures (21 bar or less (300 psig or less)), due to the sealing of the equipment with colloidal sulfur. The elemental sulfur can be stored, or more preferably, marketed as a commercial product.

The elemental sulfur is extracted in line 844. Preferably, the sulfur is directed to a sulfur handling unit (not exposed). This leaves an aqueous metallic chelant solution substantially devoid of metallic sulfur.

The aqueous metal catalyst solution in the elimination system 850 is a regenerated chelated iron. The chelated iron is redirected back to contactor 820 via line 842. A pump 844 can be provided in order to increase the pressure in line 842, and transport the chelator mixture to contact container 825. In this way, chelated iron ( or another oxidized metal) can be recovered and reused.

Again, with reference to the gas line 824, the bitter gas in the gas line 824 is conveyed to a dewatering vessel 860. Because the redox process uses a water-based material for the separation of H2S from the stream of water. raw gas 812, the subsequent dehydration of the gas in line 824 is necessary before the removal of cryogenic acid gas. As a result of the passage of the bitter gas from the gas line 824 to the dehydration vessel 860, an aqueous stream 862 is generated. The aqueous stream 862 can be sent to a water treatment facility. Alternatively, the aqueous stream 862 may be reinjected into a subsurface formation, such as the subsurface formation 630 of Figure 6. Even alternatively, the removed aqueous stream 862 may be treated in order to meet environmental standards, and then, released in the local basin (not exposed) as treated water.

Further, as a consequence of the passage of the bitter gas from line 824 through the dehydration vessel 860, a substantially dehydrated gas stream 864 is produced. The dehydrated gas stream 864 comprises methane, and in addition, may contain minimal amounts of nitrogen, helium and other inert gases. In In connection with the present systems and methods, the dehydrated gas stream 864 also includes carbon dioxide.

The dehydrated gas stream 864 leaves the dehydration vessel 860 and passes through a cooler 626. The cooler 626 cools the dehydrated gas stream 864 to a temperature of about -34 to -40 ° C (-30 ° to - 40 ° F). The cooler 626 may be, for example, an ethylene or propane cooler. A chilled light gas stream 678 is thus generated.

The light gas stream 678 is then preferably moved through an expansion device 628. The expansion device 628 may be, for example, a Joule-Thompson valve ("J-T"). The expansion device 628 serves as an expander to obtain additional cooling of the light gas stream 678. The expansion device 628 further reduces the temperature of the light gas stream 678, for example, to approximately -57 ° C to - 62 ° C (-70 ° F to -80 ° F). Preferably, an at least partial liquefaction of the gas stream 678 is also achieved. The cooled bitter gas stream is produced in line 611.

The bitter gas cooled in line 611 is directed to a distillation tower. The distillation tower can be, for example, a CFZ 100 tower of Figures 1 and 6. The bitter gas of line 611 is then processed through an acid gas stripping system. The acid gas removal system can be, for example, in accordance with the acid gas removal system 650 of Figure 6.

Another means for the removal of sulfurous components from a stream of crude gas is through the use of scrubbers in a scrubber bed. The use of scrubbers is known in the gas processing industry, as a way to remove H2S and mercaptans from a gas stream. The scrubbers can be solid, they can be in liquid form, or they can be a catalyst solution.

The scrubbers convert compounds that contain sulfhydryl and others that contain sulfur into harmless compounds, such as metal sulfides. The compounds can be disposed of safely and favorably for the medium ambient. The scrubbers have particular utility when the composition of H2S in a stream of crude gas is low, so that the conventional treatment of amine is not economically viable. An example is that where the H2S composition is less than about 300 ppm.

An example of a known liquid based scrubber 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 scrubber is a nitrite solution.

Examples of solid scrubbers are iron oxide (FeO, Fe203 or Fe3Ü4) and zinc oxide (ZnO). Solid scrubbers are generally non-regenerable. Once a non-regenerable debugging bed is exhausted, it must be replaced. Iron oxide generally requires some moisture to be effective, while zinc oxide does not require it. Consequently, if the bitter gas stream has already been dehydrated, the use of ZnO will be convenient, in terms of which additional dehydration will not necessarily be required upstream of the CO2 removal process. However, water can be generated from the oxidation process. Therefore, according to the initial level of H2S, subsequent dehydration may be necessary.

Hydrogen sulfide scavengers are most commonly applied through one of three methods. First, an application of batches of liquid scavenging agents can be used in a splashed tower contactor. Secondly, an application of batches of solid debugging agents in a fixed-bed contactor can be used. Third, continuous direct injection of liquid scavengers into a container can be employed. This is the most common application.

The conventional direct injection H2S scrubbing uses a pipeline as a contactor. In application, a liquid H2S scavenger, such as triazine, is injected into the gas stream. The H2S is absorbed by the purifying solution. The H2S is reacted in order to form byproducts, which are subsequently removed from the raw gas stream and discarded. An alternative method for the direct injection of the H2S scrubber involves the introduction of a liquid jet of the scrubbing agent through a small opening at high pressure. Typically, an atomizing nozzle is used in order to produce the atomization of the liquid scavenging agent in the form of very small droplets. For many applications, a direct injection approach has the potential of lower total costs, due to its low cost of capital in relation to batch applications.

Figure 9 is a schematic diagram showing a gas processing facility 900 for the removal of acid gases from a gas stream in accordance with the present invention, in one embodiment. In arrangement, the hydrogen sulfide is removed from a stream of raw gas 912 upstream of a 950 acid gas removal system by means of a scrubber.

Figure 9 shows the gas processing facility 900 receiving a production gas stream 912. The production gas stream 912 originates from the hydrocarbon production activities that take place in a reservoir development area, or " reservoir "910. It is understood that reservoir 910 can represent any location where gaseous hydrocarbons are produced. The hydrocarbons will comprise methane, as will hydrogen sulfide. The hydrocarbons may also include ethane, as well as carbon dioxide.

In the gas processing facility 900, the production gas stream 912 is fed to a 950 sulfur component removal system. The 950 sulfur component removal system utilizes an H2S scrubber. Any of the purification methods described above can be used. The illustrative sulfur component removal system 950 uses the d method mentioned above, that is, a liquid scrubber with continuous injection in a separation vessel 920.

In order to remove the sulfurous components from the raw gas stream 912, the raw gas stream 912 is directed to a pipe 922. At the same time, a liquid scrubber, such as triazine, is introduced into the pipe 922, through of a 944 scrubber line. The triazine is injected through a spray nozzle 923, and then, it is mixed with the stream of crude gas 912 in a static mixer 925. From there, the stream of raw gas in contact 912 enters. in the separation vessel 920.

The separation vessel 920 defines a chamber 926. The liquids settle at the base of the chamber 926, while the gaseous components exit at the top of the chamber 926. The liquids exit through the line of liquid 927. The liquids they comprise exhausted scrubber material. A portion of the liquids in line 927 is disposed of as effluent waste. Waste line 942 directs effluent waste to a maintenance tank (not exposed) or other waste maintenance area. The waste can be transported by means of a truck or a waste line. The remaining portion of the liquids of line 927 can be redirected back to the scrubber line 944, for contact with the raw gas stream 912, if the scrubber is not completely depleted.

The sulfur component removal system 950 further includes a scrubber container 930. The scrubber container 930 holds the liquid scrubbing agent. The operator passes the liquid cleaning agent from the scrubber container 930 to the scrubber line 944, as necessary. A pump 946 is provided to increase the pressure for the injection of the liquid scrubbing agent into the 922 pipe.

Referring again to the separation vessel 920, the separation vessel 920 may include a mist eliminator 924. The mist eliminator 924 helps to prevent liquid particles from escaping from the top of the separation vessel 920 with the gaseous components. This phenomenon is called drag, or transport. The mist eliminator 924 is similar to a network or a membrane that creates a sinuous path for the vapor, as it travels upward in the separation vessel 920. The mist eliminators are known. A source of mist eliminators is Separation Products, Inc., of Alvin, Texas. Separation Products, Inc. manufactures mist eliminators under the Amistco ™ trademark.

The gaseous components leave the separation vessel 920 through the upper gas line 945. The gaseous components mainly represent methane and carbon dioxide. Trace elements of ethane, nitrogen, helium and aromatics may also be present. The gas in line 945 can be termed a bitter gas. The bitter gas in the gas line 945 is taken to a dehydration vessel 960.

Because the scrubbing process uses a water-based material for the separation of H2S from the raw gas stream 912, the dehydration of the gas in line 945 is necessary before the removal of cryogenic carbon dioxide. As a result of the passage of bitter gas from the gas line 945 through the dehydration vessel 960, an aqueous stream 962 is generated. The aqueous stream 962 can be sent to a water treatment facility. Alternatively, the aqueous stream 962 can be reinjected into a subsurface formation, such as the subsurface formation 630 of Figure 6. Even alternatively, the eliminated aqueous stream 962 can be treated in order to meet environmental standards, and then released. in the local basin (not exposed) as treated water.

In addition, as a consequence of the passage of the bitter gas from line 945 through the dehydration vessel 960, a substantially dehydrated gas stream 964 is produced. The dehydrated gas stream 964 is passed through a cooler 626. The chiller 626 cools the dehydrated gas stream 964 at a temperature of about -34 to -40 ° C (-30 ° to -40 ° F). The cooler 626 may be, for example, an ethylene or propane cooler. A chilled light gas stream 678 is thus generated.

The light gas stream 678 is then preferably moved through an expansion device 628. The expansion device 628 may be, for example, a Joule-Thompson valve ("J-T"). The expansion device 628 serves as an expander to obtain additional cooling of the light gas stream 678. The expansion device 628 further reduces the temperature of the light gas stream 678, for example, to approximately -57 ° C to - 62 ° C (-70 ° F to -80 ° F). Preferably, an at least partial liquefaction of the gas stream 678 is also achieved. The cooled bitter gas stream is indicated on line 611.

The bitter gas cooled in line 611 is directed to a distillation tower. The distillation tower can be, for example, a CFZ 100 tower of Figures 1 and 6. The cooled gas stream is then processed through an acid gas stripping system. The acid gas removal system can be, for example, in accordance with the acid gas removal system 650 of Figure 6.

Yet another means proposed in this application for the removal of organosulfur compounds having a sulfhydryl group (-SH) is through what is known as a CrystaSulf process. The CrystaSulf process was developed by CrystaTech, Inc., of Austin, Texas. The CrystaSulf process uses a modified liquid phase Claus reaction process in order to remove H2S from a stream of raw gas.

A "Claus process" is a process that is sometimes used in the refinery and natural gas industries for the recovery of elemental sulfur from gas streams containing hydrogen sulfide. Briefly, the Claus process for the production of elemental sulfur comprises two primary sections. The first section is a thermal section where part of the H2S is burned to S02, and the formed S02 reacts with the remaining H2S to generate elemental sulfur at approximately 982 ° C to 1204 ° C (1800 ° to 2200 ° F). No catalyst is present in the thermal section. The second section is a catalytic section where elemental sulfur is produced at temperatures between 204 and 343 ° C (400 ° and 650 ° F). on a suitable catalyst (such as alumina). The reaction for the production of elemental sulfur is an equilibrium reaction; consequently, there are several stages in the Claus process where the separations are made in an effort to improve the total conversion of H2S to elemental sulfur. Each stage involves heating, reaction, cooling and separation.

The term "CrystaSulf refers only to one process, but also to a solvent used in the process CrystaSulf® is a nonaqueous physical solvent that dissolves hydrogen sulfide and sulfur dioxide, so they can react directly to obtain elemental sulfur. The CrystaSulf® solvent is sometimes called a liquor, or a separation liquor.In the CrystaSulf process, the hydrogen sulfide is removed from a gas stream using the non-aqueous separation liquor.The separation liquor can be a solvent organic for elemental sulfur such as a phenylxyethyl ethane In general, the non-aqueous solvent may be selected from the group consisting of alkyl substituted naphthalenes, alkane diaryls including phenylxyl ethanes such as phenyl-o-xylylethane, phenyl tolyl ethanes, phenyl naphthyl ethans, phenyl aryl alkanes, dibenzyl ether, diphenyl ether, partially hydrogenated terphenyls, partially hydrogenated diphenyl ethane, partially naphthalene hydrogenated and their mixtures.

Typically, the Crystasulf® solvent uses SO2 as an oxidant. This allows the Claus reaction (2H2S + S02 -> 3S + 2H20) to take place in the solvent phase. In other words, sulfur dioxide is added to the solvent solution in order to obtain better H2S removal.

The CrystaSulf process is described in U.S. Patent No. 6,416,729. Said patent is entitled "Process for the removal of hydrogen sulphide from gas streams that include sulfur dioxide, or that are supplemented with sulfur dioxide". Said patent is incorporated in this application by way of reference in its entirety. Other embodiments for the CrystaSulf process are described in U.S. Patent No. 6,818,194, entitled "Process for the removal of hydrogen sulphide from gas streams that include sulfur dioxide or that are supplemented with sulfur dioxide, by the separation with a non-aqueous absorbent ". Said patent is also incorporated in this application by way of reference.

Figure 10 is a schematic diagram showing a gas processing facility 1000 for the removal of acid gases from a gas stream in another embodiment. In this arrangement, hydrogen sulfide is removed from a stream of raw gas 1012 upstream of an acid gas removal system 650, by means of a CrystaSulf process. The CrystaSulf process is part of a 1050 sulfur component removal system for the removal of hydrogen sulphide.

Figure 10 shows the gas processing facility 1000 receiving a production gas stream 1012. The production gas stream 1012 originates from the hydrocarbon production activities that take place in a reservoir development area, or " reservoir "1010. The reservoir 1010 is synonymous with reservoirs 810 and 910 described above. The hydrocarbons are produced from the 1010 reservoir. The hydrocarbons will comprise methane along with hydrogen sulfide. The hydrocarbons may also include ethane, as well as carbon dioxide.

In the gas processing facility 1000, the production gas stream 1012 is fed into the sulfur component removal system 1050. The sulfur component removal system 1050 uses the CrystaSulf process described above. In order to remove the sulfurous components from the raw gas stream 1012 according to the CrystaSulf process, the raw gas stream 1012 is directed to an absorbent 1020. At the same time, liquid S02 is introduced into the absorbent 1020 through the line 1084. The liquefied sulfur dioxide is added as an oxidizing gas.

The liquid S02 is originally maintained in a storage container 1080. The S02 1082 line carries liquid S02 from the storage vessel 1080 to the line 1084, as necessary. A pump 1076 is provided along line 1082 for increasing the pressure, so as to move liquid S02 to absorbent 1020.

The absorbent 1020 defines a chamber 1025. In the absorbent 1020, the raw gas stream 1012 is contacted with the liquid solvent containing S02 of the line 1084. The liquids settle to the base of the chamber 1025, while the gaseous components exit at the top of chamber 1025. Liquids, called absorbent, exit through liquid line 1022. The absorbent comprises, in general, a solution of sulfur and water, together with trace elements of methane plus dioxide of Sulfur or residual hydrogen sulfide.

The liquids are directed through line 1022 to a 1030 flask. The flask 1030 serves to flash the water and any hydrocarbon gas transported, from the solvent. The sulfur-containing solution leaves the flask through the lower stream 1036. At the same time, the hydrocarbon gases and minimum amounts of water vapor exit an upper line 1032.

The upper line 1032 is carried through a compressor 1034. The reinforcement of the pressure of the upper line 1032 helps to separate the water from the hydrocarbon gases. The hydrocarbon gases are then directed to a separation vessel 1040. The separation vessel 1040 is typically a gravitational separator, although a hydrocyclone or Vortistep separator may also be used. The water falls from the separation vessel 1040 on the line 1044. The water on the line 1044 is preferably directed to a treatment facility (not exposed).

The hydrocarbon gases are released from the separation vessel 1040 through line 1042. The hydrocarbon gases in line 1042 are combined with the stream of crude gas 1012. From there, the hydrocarbon gases enter the absorbent 1020 again.

Again, with reference to the flask 1030, as seen, the flask releases a sulfur-containing solution through the lower stream 1036. The sulfur-containing solution is moved to a cooling ring 1038. The sulfur-containing solution is combined with a portion of a clear liquor of line 1058. The transparent liquor may include, for example, additional physical solvent.

The pressure in the cooling ring 1038 is increased as the sulfur-containing solution is moved through a centrifugal pump 1052. From there, the sulfur-containing solution is cooled in a PTFE heat exchanger. (polytetrafluoroethylene) 1054. As the sulfur-containing solution passes through the heat exchanger 1054, it is cooled below the saturation temperature with respect to the dissolved sulfur. The solution containing sulfur becomes supersaturated with respect to the dissolved sulfur, which, consequently, crystallizes.

The solution containing cooled and crystallized sulfur enters a crystallizer 1055. Specifically, the sulfur-containing solution of line 1038 is directed to the base of crystallizer 1055. The cooled sulfur-containing solution is contacted with sulfur crystals present in a settling zone 1059 within crystallizer 1055. The crystals act to sow the supersaturated sulfur solution in order to effect the precipitation of the dissolved sulfur. This creates a suspension of sulfur.

The sulfur suspension leaves crystallizer 1055 through sulfur suspension line 1056. The sulfur suspension in line 1056 is supplied to a 1060 filter. Filter 1060 separates the sulfur suspension into pure solid sulfur and a clear liquor . The removal of solid sulfur is represented by line 1062. The clear liquor is released as a product filtered through line 1064 and recycled back to crystallizer 1055. Preferably, a pump 1066 is provided for the movement of transparent liquor back to the crystallizer 1055 The transparent liquor rises towards the top of the crystallizer. A portion of the clear liquor is directed from the crystallizer 1055 through line 1058. The clear liquor in line 1058 is combined with the sulfur solution 1036 of the flask to form the cooling ring 1038, as described above. . A separate portion of the clear liquor is withdrawn from the top of crystallizer 1055 through line 1072. The liquor extracted in line 1072 is heated through a heat exchanger 1074. The heated liquor is combined with sulfur dioxide line 1082. The heated liquor 1074 is carried through the booster pump 1076, and then, it is redirected to the chamber 1025 of the absorbent 1020.

It is understood that the CrystaSulf process described in connection with the sulfur component removal system 1000 is merely illustrative. Other CrystaSufl processes may be used, such as those described in U.S. Patent No. 6,416,729 and U.S. Pat. No. 6,818,194 incorporated. Regardless of the process, a top gas stream 1045 is generated from the absorbent 1020.

The upper gas stream 1045 contains mainly methane and carbon dioxide. Trace elements of ethane, nitrogen, helium and aromatics may also be present. The sulfurous components have been extracted and transported through line 1062. Upper gas stream 1045 can be termed bitter gas. The bitter gas in the gas stream 1045 is preferably taken to a dehydration vessel 1060. However, because the CrystaSulf process is not aqueous, the dehydration may take place before the 1012 crude gas stream enters the system. of elimination of sulphurous components 1050.

The upper gas stream 1045 is passed through a cooler 626. The cooler 626 cools the gas stream 1045 to a temperature of about -34 to -40 ° C (-30 ° to -40 ° F). The cooler 626 may be, for example, an ethylene or propane cooler. A chilled light gas stream 678 is thus generated.

The light gas stream 678 is then preferably moved through an expansion device 628. The expansion device 628 may be, for example, a Joule-Thompson ("JT") valve or other device described in connection with the Figure 6. The expansion device 628 further reduces the temperature of the light gas stream 678, for example, to about -57 ° C to -62 ° C (-70 ° F to -80 ° F). Preferably, an at least partial liquefaction of the gas stream 678 is also achieved. The cooled gas stream is indicated on line 611.

The bitter gas cooled in line 611 is directed to a distillation tower. The distillation tower can be, for example, a CFZ 100 tower of Figures 1 and 6. The bitter gas cooled in line 611 is then processed through an acid gas stripping system. The acid gas removal system can be, for example, in accordance with the acid gas removal system 650 of Figure 6 used for the removal of carbon dioxide.

Two additional methods that can be used for the removal of at least reduced levels of upstream hydrogen sulfide from a cryogenic distillation tower involve the use of an adsorbent bed. One method uses adsorption of thermal oscillation, while the other uses adsorption of pressure oscillation. Adsorbent beds are molecular sieves. In each case, the molecular sieves are regenerated.

Molecular sieves are often used for dehydration, although they can also be used for the removal of H2S and mercaptan. More often, these sieves are combined in a single packed bed, with a layer of molecular sieve material 4A on top for dehydration, and a layer of 13X molecular sieve material on the base, for the removal of H2S and mercaptan. Consequently, a stream of crude gas is dried and desulfurized.

Figure 1 presents a schematic diagram showing a gas processing facility 1100 for the removal of acid gases from a gas stream, in another embodiment. In this arrangement, the hydrogen sulfide is removed from a stream of raw gas 624 upstream of an acid gas stripping system 650 by means of an adsorption system of thermal oscillation 1150.

The gas processing facility 1100 generally operates in accordance with the gas processing facility 600 of Figure 6. In this regard, a stream of dehydrated gas 624 is supplied to a sulfur component removal system. From there, the bitter gas composed mainly of methane and carbon dioxide is cooled and supplied to an acid gas removal system 650 through line 611. However, instead of using a solvent system 605 together with an absorbent As the sulfur component removal system, a thermal oscillation adsorption system 1150 is used. The thermal oscillation adsorption system 1150 provides the at least partial separation of hydrogen sulfide from the dehydrated gas stream 624.

The thermal oscillation adsorption system 1150 uses an adsorbent bed 1110 to selectively adsorb hydrogen sulphide and other sulfur components, while passing a stream of light gas composed of methane and carbon dioxide. The light gas stream is shown being released on line 1112. The light gas stream 1112 is supplied to a distillation tower, such as tower 100 of Figure 1, as a stream of bitter gas for the separation of dioxide from gas. methane carbon.

The provision of precooling to the light gas stream 112 is preferred, before entering the cryogenic distillation tower 100. In the illustrative gas processing facility 1100, the light gas stream 1112 is passed through a refrigeration unit 626 , and then, through an expansion device 628. The expansion device 628 may be, for example, a Joule-Thompson ("JT") valve. Preferably, at least partial liquefaction of the light gas stream 1112 is achieved in relation to the cooling. A stream of cooled bitter gas is generated which is directed to the acid gas removal system 650 through line 611.

Again, with reference to the thermal oscillation adsorption system 1150, the adsorbent bed 1110 in the thermal oscillation adsorption system 1150 is preferably a molecular sieve manufactured from zeolite. However, other adsorbent beds may be employed, such as a bed made from silica gel. Those skilled in the art of hydrocarbon gas separation will understand that the selection of the adsorbent bed will typically depend on the composition of the removed contaminant. In this case, the pollutant is, mainly, hydrogen sulfide.

In operation, the adsorbent bed 1110 will reside in a pressurized chamber. The adsorbent bed 1110 receives the dehydrated gas stream 624 and adsorb hydrogen sulfide and other sulfur components together with a certain amount of carbon dioxide. The adsorbent bed 1110 and the adsorption system 1150 will be replaced with a regenerated bed, once the bed is substantially saturated with H2S. The H2S will be released from the bed 1110 in response to the bed heating, using a dry-heated gas. Suitable gases include a portion of the top methane stream 112, heated nitrogen, or an otherwise available combustible gas.

Block 1140 represents a regeneration chamber for an adsorbent bed. The regeneration chamber 1140 receives a heated, dry gas 1132. In the arrangement of Figure 11, the dry gas 1132 is received from the upper methane stream 112. The upper methane stream 112 mainly comprises methane, although it may also include minimum amounts of nitrogen and helium. The upper methane stream 112 can be compressed in order to raise the gas pressure in the regeneration chamber. A pressure booster 1130 is shown. However, regeneration mainly takes place through the higher temperature, although it is generally increased by the lower pressures.

It may be necessary 10 to 15 percent of the upper methane stream 112 for proper regeneration. The regeneration chamber 1140 releases a stream of heated, dry fluid 1142. The dry fluid stream 1142 is directed to the solid absorbent bed 1110 and acts as a regeneration stream. The dry fluid stream 1142 is comprised mainly of methane, although it may also contain a certain amount of C02.

For a regeneration cycle of thermal oscillation, preferably at least three adsorbent beds are used; a first bed is used for adsorption, as shown in 1110; a second bed passes through the regeneration in the regeneration chamber 1140; and a third bed has already been regenerated, and is in reserve for use in the adsorption system 1150, when the first bed 1110 is substantially saturated. Consntly, a minimum of three beds are used in parallel, for a more efficient operation. These beds can be packaged, for example, with silica gel.

As seen in Figure 11, a concentrated H2S gas stream from the adsorption system 1110 is released through line 1114. The concentrated hydrogen sulfide stream 1114 also acts as a regeneration stream. The regeneration stream 1114 comprises, mainly, CH4 and H2S, although, with greater probabilities, it will also contain minimum amounts of carbon dioxide and, possibly, certain heavy hydrocarbons. In one aspect, the regeneration stream 1114 is cooled using a refrigeration unit 1116. This causes at least partial liquefaction of the regeneration stream 1114. The regeneration stream 1114 is then introduced into a separator 1120. The separator 1120 is, preferably, a gravity separator separates the water in the regeneration stream 1114 from the light gases. The light gases comprise, in general, methane, hydrogen sulfide and carbon dioxide.

The light gases are released from the upper part of the separator 1120 (shown schematically on line 1122). The light gases released from the separator 1120 on line 1122 are returned to the dehydrated gas stream 624. At the same time, water, heavy hydrocarbons (mainly ethane) and dissolved hydrogen sulfide are released from the base of the separator 1120 (exposed in schematic form on line 1124). In some implementations, it may be necessary to treat the recycle gas in line 1122 for H2S, in order to ensure that it is not recycled through the system.

It is noted that the gas processing facility 1100 may optionally not include a dehydration unit 620. The water will fall from the solid absorbent bed 1110 with the regeneration stream 1114, and will not pass through the bitter gas stream of the line 611. water will also fall from the separator 1120 with the hydrogen sulfide in line 1124. The separation of water from sulfur compounds then it can be achieved using, for example, a sour water stabilizer or other separator (not shown).

In one application, the spent gas from the regeneration gas heater 1140 can be burned in order to drive a turbine (not exposed). The turbine, in turn, can drive an open ring compressor (such as the compressor 176 of Figure 1). The regeneration gas heater 1140 can also be integrated into the acid gas removal process by carrying the waste heat from said turbine and using it for the preheating of the regeneration gas (such as in line 1132) for the recovery process of the gas. hydrogen sulfide. Also, the heat of the upper compressor 114 can be used for the preheating of the regeneration gas used for the hydrogen sulphide recovery process.

It is noted here that the regeneration gas contains the H2S which has been desorbed from the solid bed 1110. The gas can be contacted with a solvent in order to remove the H2S and recover the methane and any other hydrocarbon. In this way, the BTU (British Thermal Unit: British thermal unit) value of the gas can be recovered.

As noted, the pressure swing adsorption can also be used to remove hydrogen sulphide and other upstream sulfur components from an acid gas stripping facility. The pressure oscillation adsorption, or "PSA", refers, in general, to a process where a contaminant is adsorbed by a solid absorbent bed. After saturation, the solid absorber is regenerated by decreasing its pressure. The reduction in pressure causes the release of the contaminant as a low pressure stream.

Figure 12 provides a schematic diagram of a gas processing facility 1200 utilizing pressure swing adsorption for the removal of hydrogen sulphide. The gas processing facility 1200 operates generally in accordance with the gas processing facility 600 of Figure 6. In this regard, a stream of dehydrated gas 624 is cooled and then supplied to an acid gas removal system 650 through the 611 bitter gas line. However, instead of using a physical solvent contact system 605 together with the contact tower 670 to remove the hydrogen sulfide, it uses a pressure swing adsorption system 1250. The pressure swing adsorption system 1250 provides the at least partial separation of hydrogen sulphide from the 624 crude gas stream.

As with the thermal oscillation adsorption system 1150, the pressure swing adsorption system 1250 utilizes an adsorbent bed 1210 in order to selectively adsorb H2S while releasing methane gas. The adsorbent bed 1210 is preferably a molecular sieve manufactured from zeolite. However, other adsorbent beds may be employed, such as a bed made from silica gel. Those skilled in the art of separating hydrocarbon gases will again understand that the selection of the adsorbent bed will typically depend on the composition of the 624 crude gas stream.

As seen in Figure 12, the adsorption system 1250 releases methane gas through a stream of light gas 1212. The light gas stream 1212 is transported through a cooling unit 626, and then, preferably, through of a Joules-Thompson 628 valve, prior to entry into the cryogenic distillation tower 100. At the same time, a stream of concentrated hydrogen sulfide is released from the adsorbent bed 1210 via line 1214.

In operation, the adsorbent bed 1210 in the pressure swing adsorption system 1250 resides in a pressurized chamber. The adsorbent bed 1210 receives the dehydrated gas stream 624 and absorbs H2S together with any remaining water and any heavy hydrocarbon. Minimal amounts of carbon dioxide can also be adsorbed. The adsorbent bed 1210 will be replaced once the bed 1210 is saturated with hydrogen sulphide and other sulfur components. The H2S (and heavy hydrocarbons, if any) will be released from the bed in response to the depression reduction in the pressurized chamber. A stream of concentrated hydrogen sulfide 1214 is then released.

In most cases, reducing the pressure in the pressurized chamber to ambient pressure will cause the release of most of the hydrogen sulphide and other contaminants in the concentrated hydrogen sulfide stream 1214, from the adsorbent bed 1210. In some extreme cases, however, the pressure swing adsorption system 1250 can be aided by the use of a vacuum chamber, in order to apply sub-environmental pressure to the concentrated hydrogen sulfide stream 1214. This is indicated in the block 1220. In the presence of lower pressure, the sulfurous and heavy hydrocarbon components will desorber from the solid matrix forming the adsorbent bed 1210.

A mixture of water, heavy hydrocarbons and hydrogen sulfide will leave the vacuum chamber 1220 through the line 1222. The mixture will enter a separator 1230. The separator 1230, preferably, is a gravity separator separating the heavy hydrocarbons and the water of hydrogen sulfide. The liquid components are released from the base (shown schematically on line 1234). Any heavy hydrocarbon in line 1234 can be sent for commercial sale after treatment for the dissolved hfeS. The hydrogen sulfide in gaseous form is released from the top of the separator 1230 (shown schematically in line 1232). The H2S on line 1232 is sent to a sulfur recovery unit (unexposed) or injected into a subsurface formation as part of the acid gas injection.

The pressure oscillation adsorption system 1250 can be supported on a plurality of beds in parallel. A first bed 1210 is used for adsorption. This is known as a service bed. A second bed (not exposed) goes through regeneration through pressure reduction. A third bed has already been regenerated, and is in reserve for use in the adsorption system 1250 when the first bed 1210 is substantially saturated. Consequently, a minimum number of three beds can be used, in parallel, for more efficient operation. These beds can be packaged, for example, with activated carbons or molecular sieves.

The pressure swing adsorption system 1250 can be a rapid cycle pressure swing adsorption system. In so-called "fast cycle" processes, cycle times can be as short as a few seconds. A fast cycle PSA unit ("RCPSA") will be particularly convenient as it is quite compact in relation to a normal PSA device. It should be noted that pretreatment for the inlet gas may be necessary. Alternatively, a layer of sacrificial material may be used in the upper part of the packed bed, to preserve the active material.

In one aspect, a combination of thermal oscillation regeneration and pressure swing regeneration can be employed.

Another method proposed in this application for the removal of upstream hydrogen sulfide from an acid gas stripping system is a process called "kinetic adsorption separations", or SCA. The SCA employs a relatively new class of solid adsorbents that is based on the rate at which certain species are adsorbed by structured adsorbents relative to other species. This contrasts with traditional swing control adsorption processes, where selectivity is imparted primarily by the equilibrium adsorption properties of the solid adsorbent. In the latter case, the competitive adsorption isotherm of the light product in the micropores or the free volume of the adsorbent is not favored.

In a kinetically controlled oscillation adsorption process, the selectivity is imparted mainly by the diffusion properties of the adsorbent, and by the transport diffusion coefficient in the micropores. The adsorbent has a "kinetic selectivity" for one or more gaseous components. According to this application, the term "kinetic selectivity" is defined as the ratio of diffusion coefficients of individual components, D (in m2 / sec), for two different species. These diffusion coefficients of individual components are also known as Stefan-Maxwell transport diffusion coefficients, which are measured for a given adsorbent for a pure gaseous component. Therefore, for example, the kinetic selectivity for a particular adsorbent for component A with respect to component B will be equal to DA / DB. The diffusion coefficients of individual components for a material can be determined by means of well known tests in the art of adsorbent materials.

The preferred way to measure the kinetic diffusion coefficient is with a frequency response technique described by Reyes et al., In "Frequency Modulation Methods for Diffusion and Adsorption Measures in Porous Solids", J. Phys. Chem. B., 101 , pp. 614-622 (1997). In a kinetically controlled separation, it is preferred that the kinetic selectivity (i.e., DA / DB) of the adsorbent selected for the first component (e.g., Component A) with respect to the second component (e.g., Component B) be superior to 5, more preferably, greater than 20, and even more preferably, greater than 50.

It is preferred that the adsorbent material be a zeolite material. Non-limiting examples of zeolites having appropriate pore sizes for the removal of heavy hydrocarbons include MFI, faujasite, MCM-41 and Beta. It is preferred that the Si / Al ratio of zeolites used in one embodiment of a process of the present invention for the removal of heavy hydrocarbons be from about 20 to about 1000, preferably, from about 200 to about 1000, In order to avoid excessive contamination of the adsorbent. Additional technical information on the use of kinetic adsorption separation for the separation of gaseous hydrocarbon components is presented in U.S. Patent Publication No. 2008/0282884, the entire disclosure of which is incorporated herein by reference.

Figure 13 is a schematic diagram showing a gas processing facility 1300 of the present invention, in another embodiment. In this arrangement, hydrogen sulfide is removed from a rising gas stream of an acid gas removal system 650 by means of a 3 0 adsorption bed using the kinetic adsorption separation.

The gas processing facility 1300 generally operates in accordance with the gas processing facility 600 of Figure 6A. In this regard, a stream of dehydrated gas 624 is cooled in a preliminary cooling unit 625, and then, supplied to an acid gas removal system 650 through a stream of bitter gas in line 611. However, in Instead of using a physical solvent contact system 605 together with the contact tower 670 upstream of the acid gas removal system 650 for the removal of hydrogen sulphide, an SCA 1310 solid adsorbent bed is used. The adsorbent bed 1310 adsorbs preferentially hydrogen sulfide mind.

In the present application of kinetic adsorption separation, the hydrogen sulfide components will be retained by the adsorbent bed 1310. This means that the H2S will be recovered at a lower pressure. The adsorbent bed 1310 can be used in conjunction with the pressure swing adsorption or the rapid cycle pressure swing adsorption. With the pressure reduction, a stream of natural gas liquids 1314 is released from the solid adsorbent bed at low pressure. The natural gas liquids stream 1314 contains most of the sulfur components of the dehydrated gas stream 624, and in addition, may contain heavy hydrocarbons and minimal amounts of carbon dioxide.

In order to separate the hydrogen sulfide and the carbon dioxide from the heavy hydrocarbons, an additional distillation column is needed. A distillation vessel is shown at 1320. The distillation vessel 1320 can be, for example, a packed column or tray used as a contaminant cleaning system. Hydrogen sulfide and carbon dioxide are released through the upper line 1324. Line 1324 is preferably combined with the acid gas line 646 for the injection of acid gas into the reservoir 1349. Heavy, bitter, hydrocarbons and most of the water molecules leave the distillation vessel 1320 through a lower line 1322. The heavy hydrocarbons may be in the form of natural gas liquids, ie, ethane, and possibly, propane. Natural gas liquids are treated for the removal of H2S and captured for sale.

It is observed that the process of kinetic adsorption separations of the system 1300 can be more beneficial for the recovery of hydrogen sulfide and heavy hydrocarbons from natural gas streams produced with a great excess of pressure. In this situation, the bitter gas in line 611 has adequate pressure to be processed by the cryogenic distillation tower 100. An example of excess pressure is a pressure greater than 27 bar (400 psig).

The adsorbent bed 1310 releases a stream of light gas 1312. The gases in stream 312 are comprised primarily of methane and carbon dioxide. It is preferred to provide cooling to the light gases in stream 1312, prior to entry into the cryogenic distillation tower 100. In the illustrative gas processing facility 1300, the light gases in stream 1312 are passed through a unit 626, and then, through an expansion device 628. A cooled bitter gas stream is generated on line 611, which is directed to the acid gas removal system 650.

In another general approach for the removal of heavy hydrocarbons, the heavy hydrocarbons are extracted from the lower stream 646"downstream" of the distillation tower 100. In one example, a kinetic separation process of adsorption downstream from the tower is employed. of cryogenic distillation.

Figure 14 depicts a schematic diagram of a gas processing facility 1400 employing a kinetic adsorption separation process. This 1400 gas processing facility is generally in agreement with the gas processing facility 1300 of Figure 13. However, in this case, instead of the use of a solid adsorbent bed SCA 1310 upstream of an acid gas removal system 650, an SCA solid adsorbent bed is used 1410 downflow of 100 acid gas removal system.

It can be seen in Figure 14 that acid gases, ie, hydrogen sulfide and carbon dioxide, are removed from distillation tower 100 as a stream of lower liquefied acid gas 642. This liquid stream 642 can optionally be sent. through a reheater 643, where the gas containing minute amounts of methane is redirected back to the tower 100 as gas stream 644. The remaining liquid composed mainly of acid gases is released through the acid gas line 646.

The acid gases of line 646 are supplied to the solid adsorbent bed SCA 1410. The acid gases remain cold and reside in a liquid phase as they pass through the bed 1410. The hydrogen sulfide and any heavy hydrocarbons are removed from the gases acids and released through line 1412 as a stream of natural gas liquids 1412. At the same time, the acid gases pass through the solid adsorbent bed SCA 1410 and are released as a stream of lower acid gas 1414.

The acid gases in the lower acid gas stream 1414 remain in a mainly liquid phase. The liquefied acid gases in line 1414 are mainly C02 and can be vaporized. Alternatively, the liquefied acid gases in line 1414 can be injected in a subsurface formation through one or more acid gas injection wells (IGA) as indicated by block 649. In this case, the acid gas in the line 646 is preferably passed through a 648 pressure booster.

It is noted that the liquid stream of natural gas 1412 contains heavy hydrocarbons as well as hydrogen sulfide and minimal amounts of carbon dioxide. Thus, a distillation process is carried out in order to separate H2S and C2 from the 1412 natural gas liquids stream. A distillation vessel is shown at 1420. The H2S and minimum amounts of C02 gases are released from the vessel of distillation 1420 through an upper line 1424. Line 1424 is preferably fused with the lower acid gas stream 1414 for injection of acid gas into the reservoir or 649. Heavy hydrocarbons leave vessel 1420 through a lower line 1422 , and are captured for sale.

Figure 15A is a schematic diagram of a gas processing facility 1500 of the present invention, in another embodiment. In this arrangement, the hydrogen sulfide is removed from a downstream gas stream of an acid gas removal system 650 by means of an extraction distillation process. The extraction distillation process is represented in Box 1550.

The illustrative gas processing installation 1500 is generally in accordance with the gas processing facility 600 of Figure 6. In this regard, a stream of dehydrated gas 624 is cooled and then supplied to an acid gas removal system 650 to through the 611 bitter gas line. However, instead of using a solvent contact system 605 together with upstream contact towers of the acid gas removal system 650, a downstream stream distillation distillation process is used. acid gas removal system 650.

It can be seen in Figure 15A that the cooled bitter gas passes through line 61 and enters the acid gas removal system 650. The acid gas cooled in line 6 1 has the same composition as the dehydrated crude gas stream 624. The bitter gas in stream 611 comprises methane together with hydrogen sulfide and carbon dioxide. Ethane may also be present, as well as trace elements of nitrogen, helium and aromatics.

The bitter gas in line 611 first enters column 100. This may be the same as CFZ 100 tower in Figures 1 and 6. As described above, the CFZ 100 tower separates the bitter gas into a methane stream upper 112 and a lower acid gas stream 642. In this case, the lower acid gas stream 642 includes both carbon dioxide and hydrogen sulfide.

The lower stream 642 can be sent, optionally, through a reheater 643. From there, the methane-containing fluid is redirected back to the tower 100, as a stream of 644 hydrocarbon gas. The remaining fluid mainly composed of sulfur of hydrogen and carbon dioxide is released through the acid gas line 646. The material in the acid gas line 646 is presented in liquid form, and enters the 1550 extraction distillation system.

Figure 15B is a detailed schematic diagram of the 1550 gas processing facility for the extraction distillation process. Line 646 can be observed by conveying acid gases to the extraction distillation facility 1550. In the illustrative arrangement of Figure 15B, three extraction distillation columns 1510, 1520 and 1530 are shown. However, it is understood that more can be used. of three columns.

The extraction distillation column 1510 is a propane recovery column. The propane recovery column 1510 mixes a hydrocarbon solvent with the acid gas stream 646 in a vessel. The temperature in the first column 1510 is generally from -73 ° C to 10 ° C (-100 ° to 50 ° F). In the 1510 propane recovery column, the solvent absorbs hydrogen sulfide, to get the solvent out of the column 1510 as the lower stream of solvent 1514. It will also contain a certain amount of carbon dioxide, as well as heavy hydrocarbons. At the same time, the carbon dioxide and minimum amounts of light hydrocarbons leave the column 1510 through an overhead stream 1554. The carbon dioxide in stream 1554 can be combined with the 1552 acid gas injection line, for injection in a subsurface formation (649 in Figure 15A).

The lower stream of solvent 1514 enters the second extraction distillation column 1520. The second extraction distillation column 1520 is a C02 elimination column. The temperature in the elimination column of C02 1520 is, in general, from -18 to 121 ° C (0 ° F to 250 ° F), which is higher than the temperature in the 1510 propane recovery column. In the C02 1520 elimination column, the solvent and the Heavy hydrocarbons leave the column 1520 as a second lower stream of solvent 1524. At the same time, the carbon dioxide leaves the second column 1520 as a stream of upper C02 1552. The upper CO2 stream 1552, preferably, is used to Improved oil recovery.

A final column 1530 is shown in Figure 15B. The final column 1530 is an additive recovery column. The additive recovery column 1530 utilizes distillation principles in order to separate the heavy hydrocarbon components, known as "natural gas liquids", from the solvent. The temperature in the third column 1530 is, in general, from 27 to 177 ° C (80 ° F to 350 ° F), which is higher than the temperature in the second column 1530. Natural gas liquids exit the column 1530 through line 1532, and are taken to a treatment unit for the removal of any remaining CO2 and H2S. This treatment unit can be a liquid-liquid extractor, in which, for example, amine is used for the removal of H2S / CO2.

The solvent leaves the additive recovery column 1530 as a lower solvent stream 1534. The lower solvent stream 1534 represents a regenerated additive. The majority of the lower solvent stream 1534 is reintroduced into the first column 1510 for the extraction distillation process. The excess solvent of stream 1534 may optionally be combined with the liquid stream of natural gas 1532 for treatment by line 1536.

Again, with reference to Figure 15A, the carbon dioxide on line 1554, preferably, is combined with C02 on line 1552 and passed through a pressure booster 648, and then, injected into a line formation. subsurface through one or more acid gas injection wells (IGA), as indicated in block 649.

As can be seen, a number of methods can be used to remove the sulfur components in connection with an acid gas removal process. In general, the method selected depends on the condition of the crude natural gas, or the gas to be treated. For example, if the concentration of H2S is less than about 0.1%, a combined molar sieve approach may be better, since, anyway, dehydration is necessary. Molecular sieves have added the elimination benefit of a certain amount of C02, which can facilitate a "dirty" start.

For cases of approximately 0.1% to 10% H2S in the inlet gas, the best option may be a physical solvent such as Selexol ™. It will be ideal for the solvent to be dry, since it can be used to dry the inlet gas to a certain level. For CFZ processing, the gas may require additional dehydration by means of a (smaller) molecular sieve unit. The concentrated H2S stream from the Selexol unit can be processed in a sulfur recovery unit (URA), or it can be compressed and combined with the CFZ lower stream for waste in the well.

It is understood that the methods described above for the removal of hydrogen sulfide can be applied in connection with any gas removal process, not only with a process using a "controlled freezing zone" tower. Other cryogenic distillation columns may be used. In addition, other cryogenic distillation processes, such as fractionation by volume, can be used. A volume fractionation tower is similar to the CFZ 100 tower of Figure 1, although it does not have an intermediate freezing zone. A volume fractionation tower typically operates at a pressure greater than a CFZ 100 tower, such as greater than 48 bar (700 psig), in order to avoid the formation of C02 solids. However, the upper methane stream 112 may contain significant amounts of C02. In any case, the use of a separate process for the removal of hydrogen sulfide is convenient when the stream of dehydrated gas 624 comprises more than about 3% C2 or heavy hydrocarbons.

While it will be evident that the inventions described in this application are well calculated to achieve the benefits and advantages set forth above, it will be appreciated that inventions are sensitive to modification, variation and change, without departing from their spirit. Improvements are provided in the operation of an acid gas removal process using a controlled freezing zone. The improvements provide a design for the removal of H2S to very low levels in the gas product.

Claims (45)

1. A system for the removal of acid gases from a bitter gas stream, comprising: an acid gas removal system to receive the bitter gas stream, where the acid gas removal system uses a cryogenic distillation tower that separates the bitter gas stream into an upper gas stream composed mainly of methane, and a stream of liquefied lower gas composed mainly of carbon dioxide; Y an upstream sulfide component removal system from the acid gas removal system, where the sulfur component removal system receives a stream of raw gas and generally separates the crude gas stream into a stream of hydrogen sulfide and the stream of bitter gas.

2. The system of claim 1, wherein the crude gas stream contains between about 4 ppm and 100 ppm sulfur components.

3. The system of claim 2, wherein the cryogenic acid gas removal system further comprises a heat exchanger for cooling the bitter gas stream before entry into the cryogenic distillation tower.

4. The system of claim 3, wherein: the cryogenic distillation tower comprises a lower distillation zone and an intermediate controlled freezing zone which receives a cold liquid spray composed mainly of methane, where the tower receives and then separates the bitter gas stream into a higher methane stream and the stream of lower acid gas; Y cooling equipment downstream of the cryogenic distillation tower, for the cooling of the upper methane stream and the return of a portion of the higher methane stream to the cryogenic distillation tower, such as cold spray.

5. The system of claim 2, wherein the acid gas removal system is a volume fractionation system.

6. The system of claim 2, wherein the sulfur component removal system comprises a chemical solvent system.

7. The system of claim 6, wherein the chemical solvent comprises methyl diethanol amine (MDEA), a selective amine of the Flexsorb® family of solvents, or combinations thereof.

8. The system of claim 6, wherein the chemical solvent system uses a plurality of co-current contactors.

9. The system of claim 8, wherein the joint current contactors of the chemical solvent system comprise: a first co-current contactor configured to receive (i) the raw gas stream, and (ii) a second liquid solvent, wherein the first co-current contactor is also configured to release (iii) a first partially sweetened compound gas stream mainly by methane, and (iv) a first partially charged gas treatment solution; a second co-current contactor configured to receive (i) the first partially sweetened gas stream and (ii) a third liquid solvent, and which is configured to release (iii) a second partially sweetened gas stream and (iv) a second partially charged gas treatment solution; Y a final joint current contactor configured to receive (i) a previous partially sweetened gas stream, and (ii) a regenerated liquid solvent, and which is configured to release (iii) a stream of final sweetened gas composed primarily of methane, and (iv) a final highly charged gas treatment solution; where: the hydrogen sulfide stream is composed at least in part of the first partially charged gas treatment solution and the second partially charged gas treatment solution; Y the regenerated liquid solvent is composed at least in part by a stream of regenerated solvent, whereby the hydrogen sulfide has been substantially removed from at least the first partially charged gas treatment solution and the second partially gas treatment solution. charged

10. The chemical solvent system of claim 9, further comprising: a liquid solvent regenerator configured to receive at least the first partially charged gas treatment solution, and to produce the regenerated liquid solvent.

1. The gas processing facility of claim 9, wherein: the liquid solvent and the regenerated liquid solvent comprise an hindered amine, a tertiary amine or combinations thereof.

12. The system of claim 8, wherein the joint current contactors of the chemical solvent system comprise: a first joint current contactor, a second joint current contactor and a final joint current contactor, wherein each of these joint current contactors is configured (i) to receive the stream of raw gas and a liquid solvent; and (i) to release a stream of sweetened gas and a separate charged gas treatment solution; wherein the first joint current contactor, the second joint current contactor and the final joint current contactor are configured to supply the respective sweetened gas streams as progressively sweetened gas streams in series; Y where the final joint current contactor, the second joint current contactor and the first joint current contactor are arranged so as to supply the respective gas treatment solutions as progressively richer gas treatment solutions in series.

13. The method of claim 12, wherein: the first joint current contactor receives (i) the initial gas stream and (ii) a second liquid solvent, and releases (iii) a first partially sweetened gas stream and (iv) a first partially charged gas treatment solution; the second joint current contactor receives (i) the first partially sweetened gas stream from the first joint current contactor and (ii) a third liquid solvent, and releases (iii) a second partially sweetened gas stream and (iv) a second one partially charged gas treatment solution, and the final joint current contactor receives (i) a previously partially sweetened gas stream and (ii) a regenerated liquid solvent, and releases (iii) a final sweetened gas stream and (iv) a slightly charged final gas treatment solution .

14. The system of claim 2, wherein the sulfur component removal system comprises a physical solvent system utilizing a physical solvent.

15. The system of claim 14, wherein the physical solvent comprises N-methyl pyrrolidone, propylene carbonate, methyl cyanoacetate, chilled methanol, tetramethylene sulfone, Selexol ™, or combinations thereof.

16. The system of claim 14, wherein the physical solvent system comprises: an absorbent for receiving the stream of crude gas and separating the stream of crude gas in the bitter gas stream and the hydrogen sulfide stream, where the stream of hydrogen sulfide comprises hydrogen sulfide and a liquid physical solvent; at least two separators for processing the hydrogen sulphide stream, so as to separate the hydrogen sulfide from the physical solvent; Y a regenerator for the regeneration of the physical solvent and the return of at least a part of the physical solvent to the absorbent.

17. The system of claim 2, wherein: the sulfur component removal system comprises at least one solid adsorbent bed for the substantial adsorption of the sulfur components, where the sulfur components are released as the hydrogen sulphide stream when at least one solid adsorbent bed is regenerated; Y one or more solid adsorbent beds pass substantially methane and CO2 as the bitter gas stream.

18. The system of claim 17, wherein the solid adsorbent bed (i) is manufactured from a zeolite material, or (ii) comprises at least one molecular sieve.

19. The system of claim 18, wherein the sulfur component removal system further comprises a separator for the removal of carbon dioxide from sulfur components in the hydrogen sulphide stream.

20. The system of claim 17, wherein the regeneration is part of a pressure swing adsorption process.

21. The system of claim 20, wherein one or more solid adsorbent beds comprise at least three adsorbent beds, where: the first of the at least three adsorbent beds is in service for the adsorption of hydrogen sulfide; the second of the at least three adsorbent beds goes through regeneration; Y the third of the at least three adsorbent beds is held in reserve to replace the first of the at least three adsorbent beds.

22. The system of claim 21, wherein the sulfur component removal system further comprises a vacuum for the application of negative relative pressure to the first of the at least three adsorbent beds, in order to assist in the desorption of hydrogen sulphide from the first of the at least three adsorbent beds, before the hydrogen sulphide stream enters the separator.

23. The system of claim 17, wherein the regeneration is part of a thermal oscillation adsorption process.

24. The system of claim 23, wherein at least one solid adsorbent bed comprises at least three adsorbent beds, where: the first of the at least three adsorbent beds is in service for the adsorption of hydrogen sulphide; the second of the at least three adsorbent beds goes through regeneration; Y the third of the at least three adsorbent beds is held in reserve to replace the first of the at least three adsorbent beds.

25. The system of claim 24, wherein: The sulfur component removal system further comprises a regeneration gas heater for (i) receiving a regeneration gas, (i) heating the regenerated gas, and (iii) desorbing hydrogen sulfide from the second adsorbent bed by application of heat, from the heated regenerated gas, to the second adsorbent bed; the regeneration gas heater releases a gas stream to the first solid adsorbent bed for separation of the gas stream in the hydrogen sulfide stream and the bitter gas stream; Y The sulfur component removal system further comprises a separator for the separation of any methane from the hydrogen sulphide stream.

26. The system of claim 25, wherein the sulfur component removal system further comprises a cooler for receiving the hydrogen sulphide stream and cooling the hydrogen sulfide fluid stream before entering the separator.

27. The system of claim 2, wherein: the sulfur component removal system comprises at least one solid adsorbent bed for the substantial adsorption of hydrogen sulphide, where the hydrogen sulfide is released as the hydrogen sulphide stream when at least one solid adsorbent bed is regenerated; Y At least one solid adsorbent bed passes substantially methane and carbon dioxide ran the bitter gas stream.

28. The system of claim 27, wherein at least one solid adsorbent bed is a bed of kinetic adsorption separations.

29. The system of claim 2, wherein the sulfur component removal system comprises a redox system.

30. The system of claim 29, wherein the redox system comprises: a contactor for receiving the stream of raw gas and a chelated oxidized metal, wherein the chelated oxidized metal is mixed with the stream of raw gas so as to cause a reduction-oxidation reaction and release (i) a lower aqueous solution comprising a chelated reduced metal and elemental sulfur, and (ii) a superior gas stream composed of methane and carbon dioxide; an oxidant for receiving the lower aqueous solution together with air, and providing a chamber for an oxidation reaction, wherein the oxidant releases an aqueous metal chelated mixture with elemental sulfur; a separator for receiving the aqueous chelated metal mixture with elemental sulfur, and separating the aqueous metal chelated mixture with elemental sulfur in a solution of regenerated chelated metal catalyst and elemental sulfur; Y a line for directing at least a portion of the chelated metal catalyst solution regenerated back to the contactor.

31. The system of claim 2, wherein the sulfur component removal system comprises a scrubber system.

32. The system of claim 31, wherein the scrubber system comprises: a line where a liquid scrubbing agent is mixed with the stream of raw gas; a separation vessel for the separation of the stream of raw gas in the sour gas stream and a spent scrubber stream, where the spent scrubber stream comprises hydrogen sulfide and the liquid scrubber agent.

33. The system of claim 2, wherein the upper gas stream comprises not only methane, but, in addition, helium, nitrogen or combinations thereof.

34. The system of claim 2, wherein the sulfur component removal system comprises a system for the implementation of a process CrystaSulf.

35. The system of claim 34, wherein the sulfur component removal system further comprises: an absorbent to receive (i) the bitter gas stream and (ii) an oxidizing gas as a separation liquor, where the oxidizing gas is mixed with the raw gas stream so as to cause a chemical reaction, so that the absorbent (i) releases the bitter gas stream, and (ii) releases an absorbent composed of water, hydrogen sulfide and the oxidizing gas; a flask for the separation of the liquid absorbent in (i) an upper vapor stream composed mainly of hydrocarbon gases and any water vapor transported; and (ii) a sulfur solution; a separation vessel for separating the water from the hydrocarbon gases and supplying the hydrocarbon gases back to the crude gas stream; a crystallizer to receive the sulfur solution, where the crystallizer sows the sulfur solution with sulfur crystals in a settlement zone in order to effect the precipitation of dissolved sulfur, where the crystallizer (i) releases a sulfur suspension from a portion bottom of the crystallizer, and (ii) directs a liquor from an upper portion of the crystallizer as the oxidizing gas, where a portion of the liquor is directed back to the absorbent; Y a filter to separate the suspension of sulfur in pure solid sulfur and a transparent liquor, where the transparent liquor is directed back to the crystallizer.

36. The system of claim 2, further comprising: a dehydration apparatus for receiving the crude gas stream before passing through the sulfur component removal system, and separating the crude gas stream in a stream of dehydrated crude gas and a stream composed mainly of an aqueous fluid; Y where the stream of raw gas received by the sulfur component removal system is the dehydrated crude gas stream.

37. A system for the removal of acid gases from a bitter gas stream, comprising: an acid gas removal system to receive the bitter gas stream, where the bitter gas stream comprises less than about 10% sulfurous components, where the acid gas removal system uses a cryogenic distillation tower that separates the sour gas stream into an upper gas stream composed mainly of methane, and a liquid lower acid gas stream composed mainly of carbon dioxide and sulfurous components; Y a downstream sulfur component removal system from the acid gas removal system, where the sulfur component removal system receives the lower acid gas stream and generally separates the lower acid gas stream into a carbon dioxide fluid stream and a stream of hydrogen sulfide.

38. The system of claim 37, wherein the acid gas removal system further comprises a heat exchanger for cooling the bitter gas stream before entering the distillation tower.

39. The system of claim 38, wherein the cryogenic distillation tower comprises: a lower distillation zone and an intermediate controlled freezing zone which receives a cold liquid spray composed mainly of methane, where the tower receives and then separates the bitter gas stream into a higher methane stream and a lower liquefied acid gas stream; Y cooling equipment downstream of the cryogenic distillation tower, for the cooling of the upper methane stream and the return of a portion of the higher methane stream to the cryogenic distillation tower as liquid reflux.

40. The system of claim 37, wherein the sulfur component removal system comprises: at least one solid adsorbent bed for substantially adsorbing hydrogen sulfide from the lower acid gas stream, where the hydrogen sulfide is released as the hydrogen sulphide stream when at least one of the solid adsorbent beds is regenerated; Y where at least one solid adsorbent bed passes substantially acidic gases comprising carbon dioxide as the carbon dioxide fluid stream.

41. The system of claim 40, wherein at least one solid adsorbent bed comprises at least one bed of kinetic adsorption separations.

42. The system of claim 37, wherein the sulfur component removal system comprises an extraction distillation system having at least two extraction distillation columns.

43. The system of claim 42, wherein the extraction distillation system comprises: a first extraction distillation column that serves as a propane recovery column, where the propane recovery column mixes a solvent with the acid gas stream to absorb acid gases, in order to get the solvent out of the column as a lower solvent stream while, separately, releases the carbon dioxide stream; a second extraction distillation column that serves as a C02 removal column, where the C02 elimination column manages the solvent and heavy hydrocarbons to leave the acid gas removal column as a second lower stream of solvent, while , separately, releases C02; Y a third extraction distillation column that serves as an additive recovery column, where the additive recovery column uses distillation principles to separate heavy hydrocarbon components, known as "liquids of natural gases", from solvent, so that it releases a lower solvent stream as a regenerated additive, while the natural gas liquids exit separately from the column at the top.

44. The system of claim 37, wherein the bitter gas stream comprises less than about 1% sulfur components.

45. The system of claim 37, wherein the bitter gas stream comprises between about 4 ppm and 100 ppm sulfur components.