Configurations and methods of acid gas removal

IS 2 365 474 T3

DESCRIPTION

Acid Gas Removal Procedures

Field of the invention

The field of the invention is the removal of acid gases from a feed gas, and in particular relates to the removal of acid gases from a feed gas high in carbon dioxide and hydrogen sulfide.

Background of the invention

Removal of acid gases from various gas streams and especially removal of carbon dioxide from natural gas streams becomes an increasingly important process as the content of acid gases from various gas sources is relatively high, or increases with time. . For example, various sources of natural gas in Alaska, continental North America, Norway, Southeast Asia, or the Gulf of Mexico contain carbon dioxide ranging from about 20% to about 75%. Additionally, sour gas from various gas fields also contains hydrogen sulfide in significant concentrations that typically needs to be removed to meet pipeline quality specifications.

For example, in a commonly employed process for acid gas removal, a chemical solvent (for example, an amine solvent) is used for acid gas removal, which typically requires additional processing of the isolated sour gas in a sulfur plant. to convert hydrogen sulfide from the regenerated solvent to sulfur as a by-product. Such acid gas removal and sulfur plant blends are generally energy intensive and expensive. Furthermore, in today's shrinking sulfur market the sulfur thus produced is of only little commercial value and is therefore discarded, which still further increases the costs of such operations.

Alternatively, membrane systems can be used to physically separate the sour gas from the gaseous feed stream. Membrane systems are often highly adaptable to accommodate the treatment of various gas volumes and product-gas specifications. Furthermore, membrane systems are relatively compact and generally free of moving parts, thus making such systems an especially viable option for near-shore gas treatment. However, all or almost all single phase membrane separators are relatively non-selective and therefore produce a carbon dioxide permeate stream with a relatively high content of methane and hydrocarbons (which are either purged, incinerated or are used as a low BTU fuel gas). Therefore, the relatively high losses of methane and hydrocarbons often make the use of this process undesirable and uneconomical. To reduce such losses, multiple phases of membrane separators with interphase recompression can be used. However, such systems are often energy intensive and expensive.

In yet another example, a physical solvent is employed for the removal of sour gas from a feed gas, which is particularly advantageous for treating gas with a high partial pressure of sour gas since the potential treatability of the physical solvent is increases with the partial pressure of acid gas (Henry's law). Using physical solvents the absorption of a particular acid gas depends on the particular solvent employed, and further depends on the pressure and temperature of the solvent. For example, methanol can be employed as a low-boiling organic physical solvent, as exemplified in US Patent No. 2,863,527 to Herbert et al. However, the requirement for refrigerant cooling to keep the solvent at cryogenic temperatures is relatively high, and the procedure often shows greater than the desired methane or ethane absorption, thus requiring a large amount of energy input for recompression and Recovery.

A typical physical solvent procedure is exemplified in Prior Art Figure 1, which is conceptually really simple and employs the use of a cold lean solvent to remove carbon dioxide from the feed gas. The solvent is regenerated by successive distillation at lower pressures and the distilled solvent is pumped into the absorber, where the solvent is re-cooled using external cooling (either in the rich solvent or lean solvent circuit). In most cases, a steam or fuel burner is required for solvent regeneration.

Physical solvent processes are generally advantageous for the removal of bulk acid gases (eg, the treated gas has 1 to 2% acid gas remaining). However, it is often difficult to remove acid gases, and particularly hydrogen sulfide, to levels that meet the quality of pipeline gas. Furthermore, typical conventional processes require regeneration of the solvent with heat or steam, which tends to be relatively energy intensive. Without the application of heat for solvent regeneration, currently known distillation regeneration procedures do not produce enough lean solvent flash for gas treatment to meet the pipeline specification for hydrogen sulfide.

Thus, although they are aware of various configurations and procedures for removing acid gases from a feed gas (see, for example, US 3,594,985, US 3,664,091, US 3,824,766, US 3,362,133, GB 2,142. 041 and US 4,568,364), all or almost all of them suffer one or more disadvantages. Among other things, hydrogen sulfide levels in treated gases are often unacceptably high by current standards, and without additional processing, the treated gas may often not meet pipeline specifications. Furthermore, known processes tend to require substantial amounts of energy to reduce the sour gas concentration to pipeline standards and incur significant hydrocarbon losses. Therefore, there is still a need to provide improved procedures and configurations for acid gas removal.

Summary of the invention

The present invention relates to configurations and processes for the removal of acid gases from a gas of

ES 2 365 474 T3 feed using a physical solvent, wherein the solvent is regenerated to an ultra lean solvent using a substantially free hydrogen sulfide gas distillation gas to the vacuum still.

Therefore, in a particularly preferred aspect of the subject matter of the invention, a plant will include a vacuum still that is configured to produce an ultra-poor physical solvent from a physical solvent containing hydrogen sulfide. The contemplated plants will further include a high pressure distillation vessel and / or a medium pressure distillation vessel that provide hydrogen sulfide free distillation gas to the vacuum still.

In addition, the plants contemplated include an absorber that works with an isothermal gradient or with a decreasing thermal gradient from top to bottom, and that receives a feed gas that comprises at least 10 mol% of carbon dioxide and at least 500 mg / kg ( ppm) hydrogen sulfide (typically at least partially dehydrated, and / or at a pressure of at least 6,895 mPa (1000 psig). With respect to the hydrogen sulfide content of solvents, it is generally contemplated that the hydrogen sulfide-containing lean solvent - comprises at least 100 mg / kg (ppm) of hydrogen sulfide, and that the ultra-lean physical solvent comprises less. of 100 mg / kg (ppm) (and most typically less than 10 mg / kg (ppm) of hydrogen sulfide. The substantially hydrogen sulfide-free distillation gas comprises at least 95 mole% carbon dioxide.

In further contemplated aspects of the subject matter of the invention, the plant may also include a stripper in which the acid gas is separated from a rich solvent, thereby producing the physical solvent containing poor hydrogen sulfide (in which the part of acid gas is compressed and injected into a formation). Additionally, the vacuum still can further produce sour gas which combines with the sour gas from the stripper.

Therefore, an ultra-lean physical solvent production process may include a step in which a substantially hydrogen sulfide-free distillation gas is separated from a physical solvent in at least one of a high pressure distillation vessel and a medium pressure distillation vessel. In another step, hydrogen sulfide is distilled from a physical solvent containing poor hydrogen sulfide in a vacuum still to form the ultra-poor physical solvent. With regard to the various settings and and other operating parameters, the same considerations as the application described above.

Various objects, features, aspects, and advantages of the present invention will become more apparent from the following detailed description of embodiments of the invention.

Brief description of the drawings

Figure 1 is a schematic prior art of acid gas removal using a physical solvent.

Figure 2 is a schematic example of a configuration of plants for the elimination of acid gases according to the subject matter of the invention.

Detailed description

The inventors have discovered that acid gases, and particularly carbon dioxide, are removed from the feed gas comprising carbon dioxide and hydrogen sulfide in configurations and processes where intermittent flaring gases from the feed gas are used to distill sulfide. of hydrogen from a poor physical solvent that is also used to remove carbon dioxide.

In particularly preferred configurations, it is contemplated that a still is operating under vacuum pressure (typically between about 6.895 and 68.95 kPa (1 to 10 psig)), where the distillation gas is supplied from the high pressure distillation. and medium pressure in the solvent regeneration process. Furthermore it is preferred that the high pressure and medium pressure distillation conditions and the amounts of the intermittent fired gases are preferably selected such that the intermittent fired gases contain most light hydrocarbons and some carbon dioxide, but are substantially free of ( that is, less than 1000 mg / kg (ppm), typically less than 100 mg / kg (ppm), and more typically less than 10 µl / l (ppmv) of hydrogen sulfide. Thus, it should be recognized that the vacuum still can produce a poor solvent that is depleted of hydrogen sulfide (i.e., less than 10 mg / kg (ppm)) and suitable for treating sour gas to a sulfur level. low hydrogen.

As used herein, the term isothermal gradient in conjunction with a physical solvent in an absorber means that the temperature of the physical solvent in an upper part of the absorber is substantially identical (i.e., absolute temperature deviation no more than 5.56 ° C (10 ° F)) with the temperature of the physical solvent in the middle and lower part of the absorber. Similarly, the term top-to-bottom thermal gradient as used herein means that the temperature of the physical solvent in an upper part of the absorber is greater than the temperature of the physical solvent in a middle and / or lower part of the absorber. absorber.

As further discussed herein, and with respect to a column or absorber, the terms "upper" and "lower" are to be understood in relation to each other. For example, withdrawal or addition of a stream from a top of a column or absorber means that the withdrawal or addition is in a higher position (relative to the bottom when the column or absorber is in operation) than a stream withdrawn from a region bottom of the same column or absorber. Viewed from another perspective, the term "upper" may thus refer to the upper half of a column or absorber, while the term "lower" may refer to the lower half of a column or absorber. Similarly, when the term intermediate is used, that an intermediate part of the column or absorber is intermediate between the upper part and a lower part. However, when upper, middle, and lower are used to refer to a column or absorber, it should not be understood that such a column is strictly divided into thirds by these terms.

IS 2 365 474 T3

As even further used herein, the term "about" when used in conjunction with numerical values ​​refers to an absolute deviation of less than or equal to 10% of the numerical value, unless stated otherwise. Thus, for example, the term "about 10 mol%" includes a range between 9 mol% (inclusive) and 11 mol% (inclusive).

In a preferred configuration as shown in Figure 2, an exemplary plant comprises a gas dehydration unit 101 (typically TEG or molecular sieve unit) that removes the water content of feed gas 1 a water dew point of approximately -40 ° C (-40 ° F) forming dry gas streams 2. It is particularly preferred that the treated feed gas stream 2 is further cooled (typically -23.33 ° C (-10 ° F) to -1.11 ° C (30 ° F)) in a heat exchanger 102 using steam on top of absorber 11 as a refrigerant to form cooled treated feed gas stream 5, which is separated in separator 103 into liquid stream 3 and vapor stream 7. Stream 3 contains most of the C5 + components that can also be recovered as NGL product that can be marketed Stream 7, depleted of C5 + components, mixes with the combined recycle stream 8 to form stream 9 which is further cooled in the heat exchanger. heat 104. In this configuration, heat exchanger 104 uses cooling supplied by depressurized rich solvent stream to atmospheric level 28 and further cools stream 9 to typically -26.11 ° C to -42.78 ° C (-15 ° F to -45 ° F ) thereby forming a cooled stream 10. The stream thus formed 10 enters absorber 105 at a lower part of the absorber.

It should be particularly appreciated that cooling the feed gas stream to a relatively low temperature (e.g., about -26 ° C to about -43 ° C (about -15 ° F to about -45 ° F will maintain the bottom temperature absorber at a particularly low level (for example, about -18 ° C to about -4 0 ° C (about 0 ° F to about -40 ° F)) which advantageously increases the acid gas loading of the rich solvent, and therefore reduces the circulation of solvent, methane, and / or hydrocarbon losses. Further preferred a secondary cooler 108 is employed to control and / or maintain the temperature of the lower section of absorber 105 at a predetermined absorption temperature. In such configurations, the rich solvent stream 13 (generated by absorption of acid gas in an upper part of the absorber) is pumped by secondary cooler pump 106 (via stream 14) and cooled in secondary cooler 108 using stream of distillate rich solvent 21 from a hydraulic turbine 111 as a coolant. The semi-rich solvent thus cooled 15, to typically -23.33 ° C to -4 0 ° C (-10 ° F to -40 ° F) is returned to the lower section of absorber 105. Furthermore, it is especially preferred that the Coolant for the secondary cooler 108 is provided by the distillate rich solvent stream 20 (depressurized rich solvent stream) via the hydraulic turbine 111. However, it should be recognized that cooling can be provided by various other refrigerants, and suitable refrigerants can be internal (ie, produced within the plant) or external (eg, propane refrigeration).

In this way, suitable secondary coolers can advantageously function to maintain an optimum absorption temperature for the absorption of acid gas. Therefore, it should be recognized that in such configurations the middle of the absorber preferably operates at a lower temperature than the top of the absorber, which is particularly desirable when charging the solvent with sour gas (the solvent will typically show a viscosity lower and lower surface tension).

Once the feed is in the absorber, the semi-rich solvent 15 will then absorb carbon dioxide from the feed gas, thereby forming the rich solvent 16 shown by the absorber by the first hydraulic turbine 107. The first hydraulic turbine 107 reduces the pressure of the lower parts of the absorber to typically about half the pressure of the feed gas, thereby cooling the rich solvent to about -21 ° C to -38 ° C (-5 ° C). F to -35 ° F) to form a depressurized rich solvent stream 17. It should be recognized that in such configurations the hydraulic turbine operates an energy efficient device as it generates cooling by cooling by expansion and distillation of the acid gas content while providing shaft work (for example, driving the circulating pump of solvent).

The rich solvent 17, after it has exchanged heat with the acid gas stream 41, is distilled to the fixer 110 which produces a first distillate vapor stream 19, which is divided into a recycle stream 47 and a distillation stream 48. The Stream 47 is compressed by recycle compressor 124 and recovered in absorber 105, while stream 48 is lowered under pressure and fed to vacuum still 118 as stream 52. With respect to the split ratio of streams 47 and 48, it is generally preferred that stream 48 is responsible for about 5% to about 30% of the total stream flow 19. The solvent stream thus distilled 20 is further expanded in hydraulic turbine 111 at a pressure reduced by half to form and expand the rich solvent stream 21 (typically at -28.89 ° C to -40 ° C (20 ° F to - 40 ° F)) that is used to cool semi-rich solvent stream 14 in heat exchanger 108. The heated rich solvent 22 from heat exchanger 108, typically at -12.22 ° C to -23.33 ° C (10 ° F to -10 ° F), separates in separator 112, which produces a second stream of hydrocarbon vapor 23 which is further divided into a recycle stream 49 and a distillation stream 50. Stream 49 is compressed by recycle compressor 124 and recovered in absorber 105, while stream 50 is pressurized and fed to vacuum still 118 as stream 51. Regarding the split ratio between the streams 49 and 50, it is generally preferred that stream 50 is responsible for typically about 10% to about 50% of the total flow of stream 23. Distillate liquid stream 24 from separator 112 is then lowered under pressure in a JT expansion valve 113 to typically one-half reduced pressure, thereby cooling the rich solvent to -15 ° C to -26.11 ° C ( -5 ° F to -15 ° F). The solvent thus distilled 25 is separated in separator 114 which produces a third distilled hydrocarbon vapor (third hydrocarbon recycle stream 26) to be recycled by recycle compressor 124. The power generated from the first and second hydraulic turbines 107 and 111 is preferably used to provide part of the power requirement of the lean solvent pump 119, vacuum pump 120, and / or for power generation.

The distillate liquid 27 from separator 114 is lowered under pressure in a JT expansion valve 115 at atmospheric pressure, thereby further cooling the rich solvent to -28.89 ° C to -42.78 ° C (-20 ° F at - 45 °) then use

ES 2 365 474 T3 to cool the feed gas in the heat exchanger 104. The heated rich solvent 29 of the heat exchanger 104, typically to -17.78 ° C to -40 ° C (0 ° F to -40 ° F), then separated in separator 116 at atmospheric pressure to produce a stream of distilled acid gas 30.

The solvent distilled at atmospheric pressure 31 is expanded through the JT valve 117 at vacuum pressure (typically between about 6.895 kPa to about 68.95 kPa (1 psig to about 10 psig)) to form stream 32, which is fed to the still at vacuum 118 producing an acid gas stream 33 and a stream lean solvent 34. The vacuum still preferably includes an upper section and a lower section that are supplied with distillation gas 51 from distillation drum 112 and distillation gas 52 supplied from distillation drum 110, respectively. It should be recognized that the number of distillation sections, the sources of distillation gas, and / or the amount of distillation gases can be varied depending on the feed gas compositions. In addition, when the feed gas has a relatively high hydrogen sulfide content, and a third distillation section can be added using a part of the distilled vapor stream 26 from separator 114. Alternatively, a single distillation section can be added. It can be performed with distillation gas supplied only from one of the distillation streams if the hydrogen sulfide concentration of the feed gas is relatively low. The ultra-lean solvent thus produced 34 is pumped by the lean solvent pump 119 at absorber pressure for absorption of acid gas by compressed ultra-lean solvent stream 35. The hydrogen sulfide-containing acid gas 33 can then be compressed by vacuum pump 120 to form compressed acid gas stream 37.

When enhanced oil recovery or sour gas injection is particularly desirable, it is preferred that the contemplated configurations include heat exchanger 109 which is used to cool sour gas stream 41 using depressurized rich solvent stream 17 from hydraulic turbine 107 . Furthermore, the distilled acid gas 33 is compressed in a vacuum pump 120 at atmospheric pressure, combined with stream 36 to form stream 38, and further compressed in compressor 121. Compressed acid gas stream 39 is cooled to its state. liquid (in stream 43) via heat exchangers 122, 123, and 109. An optional trim condenser 124 with external cooling (44) may be required for the supplemental cooling function required by acid gas condensation. The acid gas liquid 43 is then pumped by pump 125 into stream 46 for re-injection for recovery of enhanced oil, typically at 27.58 mPa (4000 psig).

Thus it should be especially recognized that the content of carbon dioxide in the feed gas will provide cooling of the solvent as well as the function of liquefaction of the carbon dioxide stream by expansion of the rich solvent with hydraulic turbines and JT valves. It should further be appreciated that if additional cooling is required (for example, at relatively low pressure), solvent cooling can be supplied by JT cooling with recycle gas compressor 124 which is compressed to higher pressure, cooled in heat exchanger 125 and lowered using JT valve 140 which forms a cooled stream 8, and is fed to the absorber. Especially suitable alternative gas processing plant configurations that can be modified to include contemplated configurations in accordance with the subject matter of the invention are described in the inventors' co-pending international patent application serial number PCT / US02 / 29810, filed September 17, 2002.

With regard to suitable feed gases, it is contemplated that numerous natural and synthetic feed gases are suitable. However, particularly preferred feed gases include natural gas, and especially natural gas with a carbon dioxide that is at least about 5 mol%, more typically at least about 10 mol%, and most typically at least 10 to 75 mol. %, ad with a hydrogen sulfide content that is at least at least 50 mg / kg (ppm), more typically at least 500 mg / kg (ppm), and most typically at least 1%. Therefore, especially suitable feed streams include natural gas feed streams from oil and gas fields such as Alaska, Norway, Southeast Asia and the Gulf of Mexico. Similarly, the sour gas content (and especially carbon dioxide content) of suitable feed gases and may vary predominantly will depend on the source of feed gas. In general it is preferred, however, that the acid gas content will be at least about 5 mole%, more typically at least about 10 mole%, and most typically at least 20 to 75 mole%. A typical feed gas composition is provided in Table 1 below:

IS 2 365 474 T3

Table 1

<td>COMPONENT</td><td>MOL%</td>

<td>N2</td><td> 0,88</td>

<td>Carbon dioxide</td><td> 19,14</td>

<td>Hydrogen sulfide</td><td> 0,01</td>

<td>C1</td><td> 72,69</td>

<td>C2</td><td> 5,29</td>

<td>C3</td><td> 1,40</td>

<td>C4</td><td> 0,22</td>

<td>NC4</td><td> 0,26</td>

<td>IC5</td><td> 0,02</td>

<td>NC5</td><td> 0,01</td>

<td>C6 +</td><td> 0,08</td>

Furthermore, it should be recognized that the pressure of contemplated feed gases can vary considerably, and suitable pressures will vary between atmospheric pressure and several thousand psig. However, it is particularly preferred that the feed gas has a pressure of at least 2.76 mPa (400 psig) more typically at least 6.895 mPa (1000 psig), even more typically at least 20.68 mPa (3000 psig), and most typically at least 34.47 mPa (5000 psig). Furthermore, while it is generally contemplated that at least a portion of the feed gas pressure is due to the gas pressure contained in the well, it should also be recognized that where appropriate, the pressure can also be increased using one or more compressors.

In still other aspects of the subject matter of the invention, the contemplated feed gases are preferably dried and cooled prior to entering the absorber, and it is especially preferred that the cooling of the feed gas is effected at least in part by the gas. of the product (i.e. the stream from the top of the absorber) into one or more heat exchangers. With regard to the degree of cooling, it is generally contemplated that the feed gas can be cooled to various temperatures. The cooled feed gas stream can be fed into a separator in which at least a portion of the C5 + components contained in the feed gas are removed from the cooled feed stream to form a partially depleted C5 + feed gas.

The partially dehydrated feed gas thus formed can then be further treated to remove larger hydrocarbons (eg C6 +) and then still further dehydrated in a dehydration unit (all suitable dehydration units are known for use). For example, proper dehydration can be accomplished using glycol or molecular sieves. Dehydration of the feed is particularly advantageous because the absorption process can be performed at a significantly lower temperature without freezing problems. In addition, the product gas and carbon dioxide are produced in a very dry state that eliminates any downstream dehydration of the product gases and minimizes hydrocarbon condensation.

Therefore, it should be particularly recognized that suitable absorbers will operate at relatively high pressure, and especially contemplated high pressures are at least 3.45 mPa (500 psi) typically at least 6.895 mPa (1000 psi) even more typically at least 20, 68 mPa (3000 psi) and most typically at least 34.47 mPa (5000 psi). Therefore, it should be recognized that contemplated absorbers can function in a supercritical gas phase region. The term "operates in a gas phase supercritical region" as used herein refers to the operation of the absorber under conditions where at least a portion of the feed gas, if not all of the feed gas, will be in a state supercritical. Furthermore, by operating the absorption process in the gas phase supercritical region, hydrocarbon condensation is typically avoided, which currently presents a significant problem in hitherto known processes. In still other aspects contemplated, the type of absorber need not be limited to a particular configuration and all absorber configurations are considered suitable for use herein. However, particularly preferred contact devices include a packed bed or tray configurations.

With regard to the solvent employed in contemplated absorbers, it should be recognized that all physical solvents and their mixtures are suitable. There are numerous physical solvents known in the art, and exemplary preferred physical solvents include propylene carbonate, tributyl phosphate, normal methyl pyrrolidone, polyethylene glycol dimethyl ether, and / or various polyethylene glycol dialkyl ethers. Alternatively, they may employ other solvents including enhanced tertiary amine (eg Piperazine) or another solvent or a mixture of solvents that have similar behavior to the physical solvent.

IS 2 365 474 T3

Therefore, the absorber will provide a product gas that is depleted of acid gases, and particularly depleted of carbon dioxide. In addition, it should be recognized that the absorber receives cooled and dehydrated feed gas, the product gas would typically conform to all or nearly all sales gas specifications and requirements for high pressure pipeline transportation. Furthermore, it should be especially appreciated that the rich solvent formed in the absorber can leave the bottom of the absorber at relatively high pressure (e.g., at least 3.45 mPa (500 psi) more typically between 6.895 and 20.68 mPa (1000 and 3000 psi)), and can thus be used to provide work (eg, for electrical power generation) and / or cooling of various streams in the separation process.

In especially preferred configurations, the rich solvent is lowered under pressure using a first hydraulic turbine to generate mechanical or electrical energy, and the depressurized rich solvent is then separated in a separator into a first recycle stream containing hydrocarbon and a first rich solvent. , which is subsequently employed (optionally) as a refrigerant to cool a carbon dioxide stream for the enhanced oil recovery application (in which carbon dioxide is produced from the feed gas). The first hydrocarbon-containing recycle stream is preferably recycled to the absorber, while the rich first solvent is further depressurized using a second hydraulic turbine to further generate mechanical or electrical energy. The rich solvent stream thus depressurized is then employed as a refrigerant in a heat exchanger (preferably secondary absorber cooler) which cools the semi-rich solvent in the absorber to maintain a desirable absorber temperature. After passing through the heat exchanger, the further depressurized rich solvent stream is then separated in a second separator into a second rich solvent and a second hydrocarbon-containing recycle stream that is recycled to the absorber. From the second separator, the rich solvent stream is further depressurized by a JT valve and then separated in a third separator into a third rich solvent and a third hydrocarbon-containing recycle stream that is recycled to the absorber. The depressurized third rich solvent is then further depressurized to atmospheric pressure, generating cooling to be used to cool the feed gas, maintaining the absorber at a desirable low bottom temperature.

With cooling mostly provided by rich solvent depressurization, cooling is not required in most cases (particularly in high feed pressure operation), but can be supplemented internally by JT cooling created from the recycle gas cooler. and JT valve, or by an external source using an exchanger with a refrigerant. Furthermore, the sequence of the particular heat exchanger may vary depending on the feed gas, solvent circulation, and the carbon dioxide liquefaction function requirements. For example, the first depressurized rich solvent can be used to cool the feed gas instead of the carbon dioxide stream, and the second depressurized rich solvent can be used for condensation of the carbon dioxide stream instead of the secondary cooler. , and third depressurized rich solvent refrigerant can be used as secondary cooler in the absorber instead. Therefore, in preferred configurations a poor solvent is formed at higher temperatures with desirable thermal physical properties that enhance the hydrodynamic behavior of the absorption process, and a rich solvent at the lowest possible temperature that maximizes the carbon dioxide holding capacity of the solvent. Therefore, the contemplated procedures will result in less solvent circulation, lower methane and hydrocarbon losses, and lower energy consumption than currently known acid gas removal procedures.

The distillation of the rich solvent can be performed in various configurations, and it is generally contemplated that all known configurations are suitable for use herein. However, it is typically preferred that the rich solvent (after providing operation and / or cooling) is further lowered under pressure to a pressure sufficient to release at least 70% (more typically at least 90%, and most typically at least 95%) of the dissolved carbon dioxide. The carbon dioxide thus produced is then separated in a stripper (typically operating at atmospheric and subatmospheric pressure) from the lean solvent. It will be especially appreciated that the carbon dioxide stream thus generated has a carbon dioxide content of greater than 90%, and more typically of at least 95%. Thus, the carbon dioxide stream thus formed is especially suitable for use in the improved oil recovery process.

In still further contemplated aspects of the subject matter of the invention, the stripper lean solvent is further lowered under pressure through the JT valve and fed into a vacuum stripper. Preferred vacuum separators operate at a pressure of between about 1 to 10 psig (6.895 to 68.95 kPa), which can be generated by a liquid seal vacuum pump. Residual carbon dioxide (typically at least 95% purity) from the lean solvent is removed in the vacuum stripper can also be used in improved oil recovery or sour gas injection. The physical solvent is regenerated in a deep vacuum still with distillation gas supplied from the distillation drums and recirculated to the absorber by a lean solvent pump. In particularly preferred configurations, the vacuum stripper can use a lean gas (eg, a part of the product gas) as a distillation gas to produce an ultra lean solvent. However, in alternative configurations, various gases including product gas are also suitable, as well as gases from other streams within the plant and even nitrogen or air. It should further be appreciated that the use of a vacuum still in such configurations produces a very lean solvent capable of producing a treated gas with a carbon dioxide concentration of typically less than 1000 µl / L (ppmv), and a sulfide concentration of hydrogen less than 4 mg / kg (ppm). Therefore, the term "ultra-lean solvent" as used herein refers to a solvent that contains no more than 10 mg / kg (ppm) of hydrogen sulfide, and most typically no more than 4 mg / kg ( ppm) of hydrogen sulfide.

Thus, the contemplated configurations will provide high-pressure pipeline gas quality and a liquid carbon dioxide stream, which can be used for enhanced oil recovery, in which cooling is generated from successive depressurization of rich solvents. In especially preferred configurations, contemplated acid gas removal plants can operate without external refrigeration, and at higher pressure, such configurations will produce refrigeration that can be used to condense carbon dioxide for further use in enhanced oil recovery. Also providing

ES 2 365 474 T3 refrigerant to remove absorption heat from the absorber, successive depressurization will return the distillation vapors containing methane and hydrocarbons to the absorber which are substantially recovered during the recycle process. In addition, the absorber product gas and solvent depressurized at atmospheric pressure are used to remove the feed gas to the absorber by maintaining the bottom of the absorber in a desirable low temperature range. Therefore it is contemplated that the heat range setting produces an absorber temperature profile with either very close to the isothermal profile or with a temperature decrease, which results in favorable physical properties that improve the hydrodynamic behavior of the column and absorption efficiency.

In particularly preferred configurations and when the feed gas comprises natural gas, it should be appreciated that the product gas comprises at least 90%, more typically at least 95%, and most typically at least 99% of the natural gas present in the gas. feeding. While not wishing to be bound by any particular theory or hypothesis, it is contemplated that such relatively high recovery of natural gas in the product gas is achieved by providing at least one, and more preferably three, hydrocarbon-containing recycle streams back to the absorber. , and / or through the operation of an absorber in an isothermal gradient or a descending thermal one from the top to the bottom. Suitable recycle gas compressors are all compressors that are capable of compressing the first and second hydrocarbon-containing recycle gas streams to a pressure equal to or approximately the pressure of the cooled and dehydrated feed gas. Similarly, it is contemplated that the lean solvent pump will provide a suitable solvent pressure for that of the lean solvent in the absorber.

Therefore, it is contemplated that configurations in accordance with subject matter of the invention will significantly reduce overall energy consumption and capital cost when compared to carbon dioxide removal processes at a partial pressure of carbon dioxide that use amine or other physical solvents or membranes. Furthermore, the contemplated configurations and procedures in general will not require an external heat source or cooling, thereby further reducing energy consumption. Still further, enhanced oil recovery projects will frequently find an increase in the concentration of carbon dioxide in the feed gas, typically from 10% to as high as 60%. Contemplated configurations and procedures can accommodate these changes with essentially the same solvent flow.

An additional advantage of the contemplated configurations is that the process is generally a non-corrosive process due to the low temperature operation and the absence of water in the physical solvent. In contrast, conventional carbon dioxide removal amine units are generally more complex to operate and maintain as such procedures tend to be corrosive and often require injections of antifoam and anti-corrosion during operation. Still further, another advantage of contemplated physical solvent processes is that, unlike amine processes, the solvent flow rate is less sensitive to increases in carbon dioxide partial pressure since carbon dioxide loading Carbon in the rich solvent only increases the increase in the carbon dioxide concentration in the feed gas. In an amine unit design, the amine circulation rate would need to increase linearly with increasing carbon dioxide content.

Still another advantage of the contemplated physical solvent processes is their simplicity and resistance to freezing compared to known amine treatment processes, thus requiring fewer external support locations and off-site systems, such as steam boilers. For example, contemplated configurations that operate on a carbon dioxide feed gas may not require any cooling service as distillation of carbon dioxide from the rich solvent will provide the necessary cooling and regeneration. The inventors further contemplate that operation of a distillation gas assisted vacuum regeneration plant can achieve very low carbon dioxide and residual hydrogen sulfide content.

Therefore, the contemplated plants will include a vacuum still which receives a poor physical solvent containing hydrogen sulfide and in which substantially the distillation gas without hydrogen sulfide is provided by at least one high pressure distillation vessel and a medium pressure distillation vessel. The term "hydrogen sulfide-containing lean physical solvent" as used herein refers to a physical solvent from which at least a part of the acid gas (typically carbon dioxide) contained in the physical solvent has been removed in a distillation process, and containing at least 100 mg / kg (ppm) of hydrogen sulfide, and more typically at least 200 mg / kg (ppm) of hydrogen sulfide. As further shown herein, the term "substantially hydrogen sulfide-free distillation gas" refers to a distillation gas that contains less than 1000 mg / kg (ppm), and more typically less than 10 mg / kg (ppm). hydrogen sulfide. It should further be recognized that when plant configurations employ only one distillation vessel, the distillation vessel may function as a high pressure distillation vessel or a medium pressure distillation vessel.

In especially preferred configurations, the hydrogen sulfide-containing physical lean solvent comprises at least 100 mg / kg (ppm) hydrogen sulfide, and the vacuum still produces an ultra-lean solvent from the hydrogen sulfide-containing physical lean solvent. comprising less than 100 mg / kg (ppm) hydrogen sulfide, and most preferably an ultra-lean solvent comprising less than 10 mg / kg (ppm) hydrogen sulfide. Although all physical solvents (and non-physical solvents that follow Henry's law) are generally contemplated suitable for use herein, especially preferred physical solvents include FLUOR SOLVENT ™ (propylene carbonate), NMP (normal methyl pyrrolidone) , SELEXOL ™ (polyethylene glycol dimethyl ether), and TBP (tributyl phosphate).

With respect to distillation gas, it is generally contemplated that the high pressure distillation vessel and / or a medium pressure distillation vessel operate at a temperature and / or pressure that will produce a portion of vapor in the vessel that is substantially free. hydrogen sulfide (i.e. contains less than 1000 mg / kg (ppm), and

ES 2 365 474 T3 more typically less than 10 mg / kg (ppm) hydrogen sulfide). Thus, in most configurations, the substantially hydrogen sulfide-free distillation gas comprises at least 95 mol% carbon dioxide. It should further be appreciated that the isolated acid gases can advantageously be re-injected into the formation for enhanced oil sequestration and / or recovery. Therefore, suitable plants 5 may comprise a separator in which the acid gas is separated from a rich solvent, thereby producing the poor physical solvent containing hydrogen sulfide, and in which part of the acid is compressed and injected. in a formation, and in which the vacuum still further produces a second sour gas that combines with the sour gas from the stripper.

Thus, specific embodiments and applications for the improved acid gas removal configurations and procedures have been described. However, it should be apparent to those skilled in the art that many more modifications in addition to those already described are possible without departing from the concepts of the invention herein. Furthermore, in interpreting both the specification and the claims, all terms should be interpreted as broadly as possible consistent with the context. In particular, the terms comprise and comprising should be interpreted as referring to elements, components, or stages in a non-exclusive way, indicating that the referenced elements, components, or stages may be present, or used or combined with other elements. , components, or steps that are not expressly referenced.