Pretreatment of natural gas before liquefaction

Abstract

Methods and systems for removing high freezing point components from natural gas are provided. The feed gas is cooled and separated in a heat exchanger into a first vapor portion and a first liquid portion. The first liquid portion is reheated using a heat exchanger and separated into a high freezing point component stream and a non-freezing component stream. A portion of the non-solidifying component stream may be at least partially liquefied and received by the absorption column. The first vapor portion may be cooled and received by the absorber. The absorption column is used to produce an overhead vapor product substantially free of high freezing point solidification components and a bottoms product liquid stream comprising solidification components and non-solidification components.

Description

[0001] This application is a divisional application of Chinese invention application No. 201780067756.X (International Application No. PCT / US2017 / 026464), filed on April 6, 2017, entitled "Pretreatment of Natural Gas Before Liquefaction". Invention Field

[0002] This disclosure relates to systems, methods, and processes for pretreating natural gas streams before liquefaction, and more specifically, to removing heavy or high-pour-point hydrocarbons from natural gas streams. Background Technology

[0003] It is generally desirable to remove components such as sour gases (e.g., H2S and CO2), water, and heavy or high-pour-point hydrocarbons from the natural gas stream before liquefying it, as these components can solidify in the liquefied natural gas (LNG) stream. High-pour-point hydrocarbons include all components (C5+) that are as heavy as or heavier than isopentane and aromatics, especially benzene, which has a very high pour point.

[0004] The source of the natural gas to be liquefied can be from pipelines or from specific oil fields. Pipeline gas transmission is typically carried out at pressures between 800 psia and 1200 psia. Therefore, pretreatment methods should preferably be able to operate well at inlet pressures of 800 psia or higher.

[0005] An exemplary specification of feed gas to a liquefaction plant contains less than parts per million by volume (ppmv) of benzene and less than 0.05 mol% of pentane and heavier (C5+) components. High-pour-point hydrocarbon removal facilities are typically located downstream of pretreatment facilities that remove mercury, acid gases, and water.

[0006] A simple and common system for pre-treating LNG feed gas to remove high-pour-point hydrocarbons involves an inlet gas cooler, a first separator for removing condensate, an expander (or Joule-Thompson (JT) valve or refrigeration unit) for further cooling the vapor from the first separator, a second separator for removing additional condensate, and a reheater for heating the cold vapor from the second separator. The reheater and inlet gas cooler typically constitute a single heat exchanger. The liquid streams from the first and second separators will contain benzene and C5+ components from the feed gas, as well as some lighter hydrocarbons that have also been condensed in the feed gas. These liquid streams can be reheated through heat exchange with the inlet gas. These liquid streams can also be further separated to concentrate high-pour-point components from those that can be transported to the LNG plant without condensation.

[0007] If the feed gas destined for an existing LNG plant contains more benzene than expected, the high-pour-point hydrocarbon removal unit will be unable to meet the required benzene removal to prevent solidification in the liquefaction unit. Furthermore, specific locations within the high-pour-point component removal unit may solidify due to the increased benzene concentration. The LNG facility may have to reduce production due to no longer accepting gas sources with higher benzene concentrations, or cease production entirely if the benzene concentration cannot be reduced.

[0008] Furthermore, while feed gas pressure may vary over time, there is a limit to the minimum system pressure available in existing methods for removing heavy hydrocarbons. Above this pressure, the physical properties of the vapor and liquid will not allow for effective separation. Conventional systems must reduce the pressure significantly more than just to meet these physical property requirements, and this pressure reduction comes at the cost of energy efficiency.

[0009] There is a need in the art to provide systems and methods for improving the removal of high-pour-point hydrocarbons from natural gas streams. There is also a need in the art to remove high-pour-point hydrocarbons from natural gas streams more efficiently. This disclosure provides solutions to these needs. Summary of the Invention

[0010] A method for removing high-freezing-point components from natural gas includes cooling a feed gas in a heat exchanger. The feed gas is separated into a first vapor portion and a first liquid portion in a separation vessel. The first liquid portion is reheated using a heat exchanger. The pressure of the first liquid portion may be reduced before entering the heat exchanger, after exiting the heat exchanger, or both before entering and after exiting the heat exchanger. The reheated first liquid portion may be supplied to a distillation column, distillation tower, or debutanizer. The reheated first liquid portion is separated into a high-freezing-point component stream and a non-freezing component stream. A portion of the non-freezing component stream is at least partially liquefied. In some embodiments, partial liquefaction can be achieved by cooling and reducing the pressure using a heat exchanger. In some embodiments, the pressure of the non-freezing component stream is increased (e.g., by using a compressor) before such cooling and depressurization. The cooled and depressurized non-freezing component stream is received by an absorber. The absorber may include one or more mass transfer stages. The first vapor portion of the separated feed gas may be cooled and depressurized and received by the absorber. An absorber is used to generate an overhead vapor product substantially free of high-freezing-point solidifying components and a bottom product liquid stream containing both solidifying and non-solidifying components. The overhead vapor product from the absorber can be reheated using a heat exchanger. The bottom product liquid stream from the absorber can be pressurized and reheated, and at least a portion of the reheated bottom product liquid stream can be mixed with feed gas before entering the heat exchanger. The method may also include using an expander-compressor to compress the reheated overhead vapor product to generate a compressed gas stream. This compressed gas stream can be further compressed to generate a higher-pressure residual gas stream. This higher-pressure residual gas stream can be sent to a natural gas liquefaction facility.

[0011] In some embodiments, the pressure of the overhead stream from a distillation column, distillation tower, or butane dehydrogenator can be increased (e.g., by using a compressor). In some embodiments, a portion of the compressed overhead stream can be mixed with a portion of the high-pressure residual gas stream, and the resulting combined stream can be cooled in a heat exchanger and used as the overhead feed to an absorber. In some embodiments, the stream received at the top feed point of the absorber can be introduced via a spray.

[0012] In some implementations, a portion of the non-condensable component stream from a distillation column, distillation column, or butane dehydrogenator may be pressurized and transported through a heat exchanger, wherein the non-condensable component stream is partially liquefied by cooling with reheated overhead vapor products, and the cooled portion of the non-condensable component stream may be transported to the side inlet of an absorption column.

[0013] A portion of the higher-pressure residual gas stream can be cooled, depressurized in a heat exchanger, and transported as the top feed of the absorber. A portion of the bottom product liquid stream from the absorber can be transported to one or more additional columns, including a demethanizer, a deethaner, a depropanizer, and a debutanizer.

[0014] The operating pressure of the absorber can be from approximately 300 psia to approximately 850 psia. For example, above one of 400 psia, 600 psia, 700 psia, and 800 psia. As another example, 400-750 psia, 500-700 psia, and 600-700 psia. As yet another example, 600-625 psia, 625-650 psia, 650-675 psia, and 675-700 psia. The operating pressure of the absorber can also be approximately 100-400 psia lower than the inlet gas pressure. For example, 200-300 psia lower than the inlet gas pressure. As another example, 200-225 psia, 225-250 psia, 250-275 psia, and 275-300 psia lower than the inlet gas pressure.

[0015] A system for removing high-freezing-point components from natural gas includes a heat exchanger for cooling the feed gas; a separation vessel for separating the feed gas into a first vapor portion and a first liquid portion, wherein the first liquid portion is reheated in the heat exchanger; a second separation vessel for separating the reheated first liquid portion into a high-freezing-point component stream and a non-freezing component stream; and an absorption tower for receiving the cooled and depressurized non-freezing component stream and the cooled and depressurized first vapor portion. The overhead vapor product from the absorption tower can be reheated using the heat exchanger, and the overhead vapor product is substantially free of high-freezing-point components. The bottom product liquid stream from the absorption tower contains both high-freezing-point components and non-freezing components. In some embodiments, the bottom product liquid stream from the absorption tower can be pressurized and reheated, and at least a portion of the reheated bottom product liquid stream can be mixed with the feed gas before entering the heat exchanger.

[0016] These and other features of the systems and methods of this disclosure will become more apparent to those skilled in the art from the following detailed description of preferred embodiments taken in conjunction with the accompanying drawings. Attached Figure Description

[0017] Therefore, those skilled in the art to which this disclosure pertains will readily understand how to implement and use the apparatus and methods of this disclosure without extensive experimentation. Preferred embodiments thereof will now be described in detail with reference to certain accompanying drawings.

[0018] Figure 1 This is a schematic diagram of an exemplary system and process for removing high-freezing-point hydrocarbons from a mixed hydrocarbon gas stream according to one embodiment of this document; Figure 2 To illustrate Figure 1 A schematic diagram illustrating exemplary concentrations of benzene and mixed butane at various points in the gas stream during the process; Figure 3 This is a schematic diagram of an exemplary system and process for removing high-freezing-point hydrocarbons from a mixed hydrocarbon gas stream according to a second embodiment of this document; Figure 4 This is a schematic diagram of an exemplary system and process for removing high-freezing-point hydrocarbons from a mixed hydrocarbon gas stream according to a third embodiment of this document; Figure 5 This is a schematic diagram of an exemplary system and process for removing high-freezing-point hydrocarbons from a mixed hydrocarbon gas stream according to the fourth embodiment of this document; Figure 6 This is a schematic diagram of an exemplary system and process for removing high-freezing-point hydrocarbons from a mixed hydrocarbon gas stream according to the fifth embodiment of this document; Figure 7 This is a schematic diagram of an exemplary system and process for removing high-freezing-point hydrocarbons from a mixed hydrocarbon gas stream according to the sixth embodiment of this document; and Figure 8 This is a schematic diagram of an exemplary system and process for removing high-freezing-point hydrocarbons from a mixed hydrocarbon gas stream according to the seventh embodiment of this document.

[0019] These and other aspects of this disclosure will become more apparent to those skilled in the art from the following detailed description of the invention, taken in conjunction with the accompanying drawings. Detailed Implementation

[0020] The following reference will be made to the accompanying drawings, wherein the same reference numerals denote similar structural features or aspects of this disclosure.

[0021] This article describes a novel cryogenic process for extracting solidified components (heavy hydrocarbons, including but not limited to benzene, toluene, ethylbenzene, xylene (BTEX), and cyclohexane) from pretreated natural gas streams prior to liquefaction.

[0022] The initial feed gas is treated to remove solidified components such as CO2, water, and heavy hydrocarbons before liquefaction. CO2 and water removal is achieved through several industrially available processes. However, the removal of solidified hydrocarbon components via cryogenic processes depends on the type and amount of the components to be removed. For feed gases with low C2, C3, and C4 content but containing hydrocarbons that will solidify during liquefaction, the separation of solidified components will be more challenging.

[0023] definition As used herein, the term "high freezing point hydrocarbon" refers to cyclohexane, benzene, toluene, ethylbenzene, xylene, and other compounds, including most hydrocarbons having at least five carbon atoms. As used herein, the term "benzene compound" refers to benzene, and also to toluene, ethylbenzene, xylene, and / or other substituted benzene compounds. As used herein, the term "methane-rich gas stream" refers to a gas stream containing more than 50% methane by volume. As used herein, the term "pressurization device" refers to a component that increases the pressure of a gas or liquid stream, including compressors and / or pumps. As used herein, "C4" refers to butane and lighter components such as propane, ethane, and methane.

[0024] Table 1: Properties of heavier hydrocarbons (e.g., freezing points of selected hydrocarbons) See Table 1, which shows the properties (e.g., freezing points) of some of the heavier hydrocarbons that may be in the feed stream. Benzene has a similar boiling point and vapor pressure to n-hexane and n-heptane. However, benzene has a higher freezing point of approximately 175°F. Among these, n-octane, p-xylene, and o-xylene also possess physical properties that cause them to solidify at temperatures higher than those of other components commonly found in natural gas, which are not yet substantially condensed into liquids.

[0025] In the embodiments described herein, the process typically has a mixed hydrocarbon feed stream with a high pour point hydrocarbon content in the range of 100 to 20,000 mol ppm C5+ or 10 to 500 mol ppm benzene and a methane content in the range of 80 to 98 mol% or 90 to 98 mol%. The methane-rich product stream typically has a high pour point hydrocarbon content in the range of 0 to 500 mol ppm C5+ or 0 to 1 mol ppm benzene and a methane content in the range of 85 to 98 mol% or 95 to 98 mol%.

[0026] In embodiments, the process described herein can use temperatures and pressures in the range of -90 to 50°F and 500 to 1200 psia in a first separation vessel; or -90 to 10°F and 500 to 1000 psia. For example, -65 to 10°F and 800 to 1000 psia. In embodiments, the process described herein can use temperatures and pressures in the range of -170 to -10°F and 400 to 810 psia in a second separation vessel (e.g., an absorption column or distillation column). For example, -150 to -80°F and 600 to 800 psia.

[0027] Typical specifications for the inlet gas of a liquefaction unit are benzene <1 mol ppm and pentane and heavier components <500 mol ppm. Tables 3 and 6 illustrate the composition of typical feed gas streams that may require pretreatment before liquefaction. Separation of solidified components is difficult because, during the cooling process, there is not a sufficient amount of C2, C3, or C4 in the liquid stream to dilute the concentration of solidified components and prevent them from solidifying. This problem is significantly amplified during the start-up of this process, in the absence of any C2 to C4 components, when the first component to be condensed from the gas is a heavy fraction. To overcome this problem, processes and systems have been developed that will eliminate solidification problems during start-up and normal operation.

[0028] For purposes of explanation and illustration rather than limitation, Figure 1 Partial views of exemplary embodiments of methods, processes, and systems for heavy hydrocarbon removal according to this disclosure are shown and generally designated by reference numeral 100. As will be described, Figure 2-8 Other embodiments or aspects thereof of the systems and methods according to this disclosure are provided herein. The systems and methods described herein can be used to remove heavy hydrocarbons from natural gas streams, for example, to remove benzene from lean natural gas streams.

[0029] As mentioned earlier, natural gas typically requires pretreatment before liquefaction to prevent high-pour-point hydrocarbons from solidifying in the LNG unit. Among the high-pour-point hydrocarbon components to be removed, benzene is often the most difficult. Benzene has a very high condensation temperature and a high freezing point. Typical liquefied hydrocarbon inlet gas purity specifications are less than one part per million (ppmv) of benzene and a combined concentration of less than 0.05% for all pentane and heavier components.

[0030] Furthermore, gas liquefaction units are typically designed for operation at inlet pressures of 800 psia or higher. Pretreatment units often operate at inlet pressures of 800 psia or higher and outlet pressures of 800 psia or higher towards liquefaction. This utilizes the available gas pressure. Liquefaction units can also operate at lower inlet gas pressures, but with lower capacity and efficiency. However, fully utilizing the energy in the 600-900 psia inlet pressure range is challenging.

[0031] Moreover, the gaseous composition used as the base case presents additional challenges because the benzene concentration is high (500 ppm or higher) and the gas is lean, containing approximately 97% methane. Therefore, there are very few heavier hydrocarbons that can be condensed to dilute the condensed benzene, thus increasing the likelihood of benzene condensation.

[0032] Typically, it is desirable to operate at the highest possible pressure to reduce gas recompression requirements. Minimizing pressure drop is also desirable to reduce recompression capital and operating costs. Operation near the inlet high pressure will limit the amount of energy extracted by the expander (or pressure reducing valve). However, the combination of higher operating pressures and colder operating temperatures can result in operation closer to the hydrocarbon's critical conditions; a smaller density difference between vapor and liquid compared to operation at lower pressures; lower liquid surface tension; and smaller differences in the relative volatility of the components.

[0033] Conventional systems and processes involve multiple cooling and separation steps to prevent benzene from solidifying, and operation at low pressures to achieve final separation, even at high inlet pressures. Furthermore, these systems are complex and require significant power for recompression.

[0034] The embodiments described herein provide a simplified apparatus for processing gases containing high concentrations and quantities of benzene. Furthermore, the embodiments described herein process high-benzene-content gases at high inlet pressures, minimizing recompression power requirements by minimizing the pressure drop required to allow the system to operate without condensing benzene or other condensable components contained in the inlet gas, and maintaining physical properties such as density and surface tension in the high-pressure system that will allow for reliable separation operations.

[0035] The embodiments described herein also provide systems and processes that allow inlet gas pressures above 600 psia (e.g., 900 psia) at the inlet of a high freezing point removal process. The pressure delivered by this process can also be at high pressure (e.g., 900 psia). Gas pressure can be reduced during the solidification component removal process. Minimizing decompression is advantageous because it requires less recompression capital and operating costs. Furthermore, the embodiments described herein minimize the number of devices and costs required to achieve the desired separation without generating waste products such as fuel gas streams. In the various embodiments described herein, only two products are generated: feed gas destined for a liquefaction unit; and low vapor pressure C5+ with benzene liquid products. Moreover, the embodiments described herein provide a process that operates without solidification.

[0036] See attached diagram. Figure 1 A schematic diagram of an exemplary system 100 for removing high-freezing-point hydrocarbons from a mixed hydrocarbon gas stream, according to one embodiment of this document, is shown. As shown, a feed gas stream 2 containing benzene (e.g., 40 mol / hr or 500 ppmv) is provided to system 100, mixed with stream 28 to become stream 4, and provided to exchanger 6, where it is cooled to form a partially condensed stream 8, which enters cold separator 10. Stream 12, which is vapor from cold separator 10, enters pressure reducing device 14 (e.g., expander or JT valve), which reduces pressure and temperature and extracts energy from stream 12. The cooled stream 16 leaving pressure reducing device 14 has been partially condensed and is conveyed to a column (e.g., absorption column) 70. Column 70 includes internal components (e.g., trays and / or packing) for one or more mass transfer stages. Heat and mass transfer occur in column 70 as the vapor from stream 16 rises and comes into contact with the substantially C5+-free, benzene-absorbing precipitating liquid phase from stream 52. The vapor stream 54 from tower 70 is reheated in exchanger 6 to provide cooling for stream 4 and exits as stream 56. Stream 56 is supplied to expander-compressor 58, where the pressure is increased and it exits as stream 60. Stream 60 is directed to residue compressor 62 and exits as stream 64. In some embodiments, stream 64 is fed to an LNG liquefaction facility. In some embodiments, as will be discussed in more detail below, a portion of stream 64 may be diverted as stream 80 for further processing or use. Stream 64 conforms to specifications for benzene and C5+ hydrocarbons entering the liquefaction unit. Typical liquefaction unit specifications are benzene 1 ppmv or less and C5+ 0.05 mol% or less.

[0037] Liquid stream 18 originating from the bottom of tower 70 is pressurized in pump 20 and exits as stream 22. Stream 22 passes through level control valve 24 and exits as stream 26. This partially vaporized and automatically cooled stream 26 is reheated in exchanger 6 and exits as stream 28, mixed with feed gas 2, and further cooled as part of mixed feed gas flow 4. These exchanger routes are necessary because stream 2 would solidify as it cools without increasing the recirculated liquid stream 4. For energy balance, it is necessary to reheat the stream exiting from the bottom of the absorber tower.

[0038] The cold recirculated stream, originating from the cold separator 10, is depressurized at the level control valve 32 and exits as stream 34. This partially vaporized and automatically cooled stream 34 is reheated by exchanging heat with the feed stream 2 in the exchanger 6 and exits as stream 36. In some embodiments, the pressure of the liquid stream 30 may be reduced before, after, or both before and after heat exchange. Stream 36 is separated in the butanizer 38 or in a distillation column, distillation tower, or any suitable component separation method. A portion exits as stream 40, containing the removed high-freezing-point hydrocarbons (e.g., benzene and other C5+ components). A portion of the butanized stream exits the butanizer 38 as the butanizer overhead stream 47 and passes through the compressor 44 and cooler 48 to become the compressed butanizer overhead product stream 50. A portion of the compressed butanizer overhead product stream 50 is cooled in the exchanger 6 before entering the absorber 70. The reheat and recooling routes of this loop are also necessary for energy balance.

[0039] The compressed butane debutanizer overhead stream 50 meets the purity requirements for transporting it to the product gas for liquefaction. However, a portion of the compressed butane debutanizer overhead stream 50 must be transported to the top of the absorber 70. This portion of the compressed butane debutanizer overhead stream 50 is returned via exchanger 6, where it is partially liquefied and exits as stream 55, then depressurized through valve 53 and enters the upper feed point at the top of column 70. That is, stream 52 is transported above one or more equilibrium stages, and expander outlet stream 16 enters below the mass transfer stage of the overhead vapor stream 54 of column 70 to meet the processing requirements of benzene concentrations below 1 ppmw. Therefore, column 70 receives streams 52 and 16 as feed.

[0040] It is worth noting that Stream 64, destined for LNG, contains only 0.0024 ppm of benzene, while typical specifications are below 1.0 ppm. It is virtually "absent" from benzene and undetectable. This excellent performance provides a very large margin of safety and makes it difficult to be "non-compliant." Therefore, this process can be expected to operate in the tower at higher pressures and temperatures while still meeting the required benzene purity of the vapor products.

[0041] The power requirement for residual gas compressor 62 is estimated at 7300 HP, and the power required for the butanizer overhead compressor is estimated at 973 HP. Based on the inlet gas processed in millions of standard cubic feet of gas per day (MMscfd), (7300+973) HP / 728.5MMscfd equals 11.36 HP / MMscfd. The butanizer overhead condenser may also require refrigeration compression. Alternatively, the butanizer overhead condensation load can be incorporated into the main heat exchanger 6. Another alternative is to recycle a portion of the liquid generated when the compressed butanizer overhead stream is cooled to serve as reflux for the absorber.

[0042] Figure 2 For use above Figure 1 The diagram illustrates exemplary concentrations of benzene and mixed butane in a gas stream during the process of removing high-freezing-point hydrocarbons using System 100 described herein. As shown, the benzene molar ratio at key points of the process is provided to aid in understanding System 100. The butane molar ratio is also provided as an indication of the dilution amount provided to prevent benzene freezing. Table 2 below shows the concentrations of benzene and mixed butane in the gas stream. Figure 2 The corresponding concentrations of benzene and butane at various points.

[0043] Table 2 below illustrates how recirculation in this process reduces the concentration of benzene in the non-condensable liquid (containing C4), and also shows how all inlet benzene is removed in separator 10. The benzene at the top of separator 10 is only the benzene recirculated back to the cold separator 10 from column 70. The reheat absorber bottom stream 18 and its feed back into feed gas 2 ensure that almost all condensable components in feed gas 2 are contained in the liquid outlet stream of the separator 10. The second loop, represented by recirculation 2, contains virtually no measurable benzene.

[0044] Table 2: Figure 2 The concentrations of benzene and mixed butane at representative points in the process shown. Figure 3 This is a schematic diagram of an exemplary system 300 for removing high-freezing-point hydrocarbons from a mixed hydrocarbon gas stream according to a second embodiment of this document. System 300 is similar to the one described above. Figure 1 Similar to system 100 described in the context of this paper. System 300 includes an additional step in which a portion (stream 80) of the compressed residual gas stream exiting the residual compressor 62 is removed for further processing. Stream 80 is mixed with the compressed debutanizer overhead stream 50, this combined stream is cooled in exchanger 6, and the combined portion of the condensate stream is used as overhead feed to absorber 70.

[0045] Feed gas composition and conditions Figure 1The same applies to system 100, and the inlet pressure and pressure at column 70 remain constant. In this case, for example, 1100 mol / hr of DeC4 overhead distillate is recirculated, and 7800 mol / hr of residual gas is recirculated. The result is that the benzene concentration in the process gas heading to the LNG unit is below 0.01 ppm and C5+ is below 0.002%. In this process, the temperature difference closest to benzene solidification at any point in the process is greater than 10°C. The total power of the residual compression and the debutanizer overhead compression is approximately 12.5 HP / MMscfd of inlet gas.

[0046] A key benefit of this arrangement in this embodiment is that it demonstrates an increased rate of excess C4 solvent transported to the LNG unit in stream 51. This higher excess C4 rate is caused by the additional reflux rate provided by recirculation stream 80, as more excess solvent is available. This demonstrates that C2 and C3 recovery is possible for refrigerant replenishment used in the LNG unit's refrigeration system. The recovery of any C2 and C3 components used for refrigeration replenishment is achieved through… Figure 3 The system 300 indicates that additional distillation columns should be added in addition to the single DeC4 of the debutanizer 38. The estimated refrigerant replenishment requirements for C2 and C3 of the LNG unit can be addressed by installing additional distillation columns to handle the overhead distillate from the debutanizer or by installing additional columns upstream of the debutanizer for recovery.

[0047] Figure 4 This is a schematic diagram of an exemplary system 400 for removing high-pour-point hydrocarbons from a mixed hydrocarbon gas stream according to a third embodiment of this document. This exemplary embodiment illustrates some operational difficulties if the butanizer overhead stream 50 is no longer recycled. Without this recirculation, there is a possibility of solidification, as simply using the residual gas recirculation stream 80 to return to the expander outlet column may not be sufficient.

[0048] A portion of the compressed residual gas stream 64 is taken out as stream 80, then cooled in exchanger 6 to reduce the pressure of the cooled stream, and then transported as the overhead stream to absorber 70. The feed gas composition and conditions are the same as... Figure 1 and 3 The embodiment shown and described above is identical, with the operating pressure remaining constant and the liquid recirculation maintained at 1100 mol / hr. The top flow of the butanizer 50 is transmitted via... Figure 4All of pipeline 51 in the pipeline is supplied with LNG. In this case, feed gas 2 is combined with recirculation 28 to form stream 4 and solidifies at a temperature of 1°C to 2°C when cooled in exchanger 6. Solidification is also possible during the initial cooling in expander 14. The treated gas has a benzene content of 0.56 ppm and a C5+ content of 0.0056%, which meets the LNG feed requirements. This arrangement may be feasible for feed gases containing less benzene or more propane and butane. However, the operation of tower 70 may also be more difficult due to the significantly reduced liquid flow rate. HP / MMscfd is approximately 12.75.

[0049] Figure 5 This is a schematic diagram of an exemplary system 500 for removing high-freezing-point hydrocarbons from a mixed hydrocarbon gas stream according to a fourth embodiment of this document. In this embodiment, the overhead liquid feed to tower 70 is introduced by spraying, which may be advantageous for simplification or as a retrofit of existing facilities.

[0050] At least one balancing stage is used in column 70 to meet the benzene specification of less than 1 ppmv in the purified gas. Without this stage, the purified gas would contain 2 ppm of benzene, compared to 0.25 ppm of benzene with this stage. Figure 5 The arrangement shown introduces the overhead liquid feed into column 70 via spray, and column 70 is configured without any mass transfer equipment such as trays or packing. This creates a single-stage contact. The feed gas composition, rate, and operating pressure remain unchanged compared to the previously described embodiment. Using this arrangement, the purified gas destined for the LNG unit contains 0.25 ppm benzene and 0.005% pentane+, meeting specifications. The total power required for the recompression plus DeC4 overhead compressor is 11.8 HP / MMscfd / process. The liquid rate to the sprayer is 1100 mol / hr. Note that if the expander outlet stream is simply mixed with the recompressed DeC4 overhead stream and conveyed to the expander outlet separator, the purified gas destined for LNG will not meet benzene specifications.

[0051] Optionally, an existing separator can be modified to add at least a partial mass transfer stage to the existing expander outlet separator using a jet stream, allowing it to operate as a simple short tower. In this case, a simplified version of this embodiment can be implemented in an existing facility by adding a sprayer and an additional heat exchanger.

[0052] Figure 6 This is a schematic diagram of an exemplary system 600 for removing high-freezing-point hydrocarbons from a mixed hydrocarbon gas stream according to the fifth embodiment of this document. Figure 6 The reflux arrangement shown can generate more C2 and C3 for LNG refrigerant replenishment than conventional systems or some embodiments previously described herein.

[0053] like Figure 6 As shown, a portion of stream 12 is taken out, conveyed through heat exchanger 17, and cooled using overhead gas flow 54 to partially liquefy it. The cooled portion of stream 12 is then conveyed through valve 19 to the side inlet of absorber 70. The DeC4 top-to-top column feed is 1100 mol / hr, as in the other embodiments described above. The new side feed is 7800 mol / hr (compared to...). Figure 1 (The residual reflux rate is the same). The inlet gas rate and composition are the same as in the previous embodiment. The total power required for the recompression plus DeC4 overhead compressor is 12.1 HP / MMscfd processed. The gas going to the LNG facility contains less than 0.0003 ppm benzene and less than 0.0002% C5+. Moreover, keeping the two streams 52 and 16 that are combined to form reflux separate and going to tower 70 through separate feed points will result in improved benzene recovery.

[0054] Figure 7 This is a schematic diagram of an exemplary system 700 for removing high-freezing-point hydrocarbons from a mixed hydrocarbon gas stream according to the sixth embodiment of this document. Figure 7 The embodiment shown provides multiple refluxes, which improves the purity of the residual gas stream. A portion of the residual gas is returned as stream 80, cooled in heat exchanger 6, and passed through valve 82 before entering column 70 at the top feed point. It should be noted that in other embodiments, this step can be performed in a separate exchanger. Reflux stream 52 is used as an intermediate stream entering column 70 at a side inlet. The residual gas is used as the top reflux stream, and the DeC4 top distillate as an intermediate stream produces a very pure product stream 64, along with a significant amount of C2 and C3 that can be fractionated for refrigerant replenishment. This arrangement recovers a propane to ethane ratio in column 70 of [missing information]. Figure 1 The illustrated embodiment achieves significantly higher yields. The HP / MMscfd is 13.8. The closest temperature difference to solidification is 5.5°C. Using the residue reflux as a separate stream produces very high solidified component recovery rates and higher than typical C2 and C3 recovery rates. However, the column load in the top section is low, where only residue reflux is present. While achieving higher liquid loads with higher reflux rates increases horsepower, this type of arrangement may be preferred in certain situations depending on the application.

[0055] Figure 8This is a schematic diagram of an exemplary system 800 for removing high-freezing-point hydrocarbons from a mixed hydrocarbon gas stream according to a seventh embodiment of this document. In this embodiment, additional towers are used. As shown, a portion of stream 28 is sent as stream 29 to a vapor / liquid separator 90, and the separated liquid exits as stream 91. Stream 91 enters one or more additional towers indicated in region 92, which may include a demethanizer, a deethaner, a depropanizer, and / or a debutanizer. The deethaner can be used to supply refrigerant-grade ethane to the LNG plant as stream 93, and the depropanizer can be used to supply refrigerant-grade propane to the LNG plant as stream 94. In some embodiments, a portion of the top stream from the deethaner and / or depropanizer, as shown in stream 95, may be transported to provide refrigerant replenishment to the liquefaction unit, to other refrigeration service facilities, or for sale. Methane, ethane, propane, and butane not required by other service facilities may be transported back as stream 95 to be combined with a bypass portion of stream 28 and transported to meet stream 2.

[0056] In some embodiments, a pressure reducing valve may be used instead of the expander 14 in any of the embodiments described herein. In some embodiments, a compressor may be used to increase the pressure of the gas entering the device, thereby allowing for new, efficient designs.

[0057] In various implementations, the pressure at the top of the absorber is above 400 psia, for example, 675 psia. In all cases, reducing the absorber pressure will result in higher C2 and C3 recoveries and a higher excess of butanizer overhead distillate. If necessary, reducing the absorber pressure will increase the amount of C2 and C3 available for refrigerant system replenishment. Note that a portion of the residual gas can be cooled, partially condensed, and depressurized before being used for heat exchange at the top of the absorber, rather than as reflux.

[0058] Tables 3 and 6 below are the above... Figure 1 The exemplary total material balance plus recirculation flow of the implementation described in the context of the above. Table 3 provides flow information for system 100, where the feed pressure is 900 psia, the feed contains 500 ppm benzene, and the pressure of tower 70 is 675 psia; also referred to as the “base case”.

[0059] Table 3: Material Balance Flow Favorable physical properties ensure the ability to separate vapor and liquid. In one or more of the above embodiments, the absorber 70 may use four theoretical stages. Table 4 below shows exemplary vapor and liquid properties in an absorber 70 using four stages.

[0060] Table 4: Properties of vapor and liquid in the absorption tower These data indicate very good separation conditions. This is likely due to the multiple recycling rates, composition, and especially the routes of the embodiments described herein. These properties are surprisingly good for operation of light hydrocarbons at 675 psia.

[0061] Table 5: Temperature proximity to benzene solidification during the process As shown in Table 5 above, due to the removal of upstream benzene and the high dilution rate of butane and other components, the system in the above embodiment solidifies at 40°C and 90°C in the coldest section of the unit, namely the expander outlet and the tower distance, respectively.

[0062] Table 6 below provides material balance flow information for a "high-pressure condition" with an inlet pressure of 1000 psia and an absorber pressure of 800 psia, where the feed contains 400 ppm benzene. The minimum pressure in the main process loop is 800 psia. The minimum liquid surface temperature is 2.86 dynes / cm. Vapor and liquid densities remain acceptable, although they are close to reasonable limits. This condition represents the feasibility of operation at very high pressures. The process flow diagram is consistent with... Figure 1 The process is the same as in the previous embodiment. In this case, recompressing the residual gas to 1000 psia, plus the horsepower required for the DeC4 overhead compression, is 7573 HP, or 10.4 HP / MMscfd. The temperature difference closest to the solidification of benzene at any point in the process is 5°C.

[0063] Table 6: Material Balance Flow For the various embodiments described herein, the physical properties are well-suited for separation in the separator and column, and excess liquid exists in the new overlapping recirculation, which is removed and sent to the LNG unit. Thus, the embodiments described herein can operate at even higher pressures while further reducing recompression requirements. As pressure increases, the excess liquid rate decreases due to changes in volatility and because a higher liquid rate is required to maintain recovery at a smaller available pressure drop.

[0064] For example, using a feed gas of 900 psia and increasing the pressure at the top of absorber 70 from 675 psia to 700 psia, using all available excess solvent, and with the cold separator temperature decreasing by 2°F, the temperature difference closest to solidification during inlet heat exchange becomes 5.2°C. The physical properties for separation remain good, with the closest point at the top of column 70, and a surface tension of 5.4 dynes / cm. 2 The vapor density is 5.3 lbs / ft. 3 The liquid density is 26 lbs / ft 3In this embodiment, the inlet gas still contains 500 ppm of benzene, while the solvent recirculation rate remains unchanged.

[0065] As another example, operation at 725 psia is also possible, but with a benzene content of 400 ppm instead of 500 ppm in the feed gas. The physical properties remain acceptable for separation. In the inlet heat exchange, the temperature difference closest to condensation becomes 5 °C. Furthermore, operation at 750 psia is also possible with a benzene content of 300 ppm in the feed gas.

[0066] In the aforementioned case where the absorber operating pressure increases, the feed gas pressure remains at 900 psia. As the absorber pressure increases while the feed and process gas pressures remain constant at 900 psia, the power requirements for recompression and butane depressurization at the top of the tower decrease significantly. In these cases where the absorber top pressure changes from 675 psia to 750 psia, the total compression power per MMscfd of inlet gas decreases from 11.36 to 8.04 HP / MMscfd.

[0067] Reducing the pressure required for separation significantly impacts the unit's compression power requirements. It's worth noting that the favorable physical properties for mass transfer and separation at these higher pressures are a result of the large amounts of butane and other components recycled, which produce a richer stream of higher molecular weight molecules with better physical properties for separation, while simultaneously providing dilution of benzene in the liquid phase, thus preventing solidification—a crucial point. As shown in Table 5 above, tower 70 (the coldest section in the designed unit) is furthest from solidification.

[0068] Table 7 below summarizes the changes in physical properties between two illustrative case studies. The baseline case is where the system has a pressure of 900 psia at the inlet and 675 psia at the absorber. The high-pressure case is where the system has a pressure of 1000 psia at the inlet and 800 psia at the absorber.

[0069] Table 7: Changes in physical properties between the two illustrative cases In other implementations with tower operating pressures slightly higher than 800 psia, such as 805 psia, product specifications are met and even power requirements are further reduced. However, a richer feed gas or higher recirculation should be used to ensure good physical properties.

[0070] Prior to adding a stage to absorber 70, the base case feed could not achieve benzene product specifications. However, the embodiment described herein, using DeC4 overhead distillate recirculation and adding a stage to absorber 70, achieves benzene specifications with a very wide margin, as seen in the high-pressure case above. The base case becomes so robust that the high-pressure case becomes possible. The relative volatility (K-value) of the components in the high-pressure case ranges from 155% to 369% of that in the base case. This measure indicates that it is much more difficult to keep the components in the liquid phase and available for benzene absorption rather than loss into the product gas. However, the embodiment described herein is designed to allow for the recovery of benzene as needed. Due to the high pressure, the physical properties of the vapor and liquid are also less favorable. However, they are still within industrially acceptable limits to allow for good vapor / liquid separation and proper operation of the absorber. The recirculation arrangement provides measures to maintain sufficient quantities of butane and lighter liquids with suitable physical properties to operate the absorber and recover benzene and pentane, as well as heavier components.

[0071] Therefore, the embodiments described herein produce a system with two loops that overlap in a unique manner to retain and recycle the liquid, while purifying the product gas and also improving the physical properties in the coldest section of the device to achieve reliable separation under high pressure, thereby reducing power requirements (e.g., by 10%-30%; or 30-50%; or 10-50%), while also handling gases containing high concentrations of benzene. The embodiments described herein can: - Remove solidified components under very high pressure; - Use only the minimum voltage drop; - Avoid solidification; - Operate with reasonable fluid physics properties; - Minimize the number of devices; and - Even with compressor shutdown, the LNG facility can operate with a very low inlet pressure drop.

[0072] This high-pressure inlet application uses an HP / MMscfd similar to any earlier case and provides purified gas at the highest pressure. The ability to process gas at the highest inlet pressure with minimal pressure drop is the most efficient operation.

[0073] The methods and systems of this disclosure, as described above and in the accompanying drawings, provide for the removal of high-freezing-point hydrocarbons at pressures higher than those of conventional systems. While the apparatus and methods of this disclosure have been shown and described in conjunction with preferred embodiments, it will be readily understood by those skilled in the art that changes and / or modifications may be made thereto without departing from the scope of this disclosure.

Claims

1. A method of removing high freezing point components from natural gas, the method comprising: cooling a feed gas in a heat exchanger; separating the feed gas into a first vapor portion and a first liquid portion in a separation vessel; reheating the first liquid portion using the heat exchanger; separating the reheated first liquid portion into a high freezing point component stream and a non-freezing component stream; at least partially liquefying the non-freezing component stream; receiving the at least partially liquefied non-freezing component stream at an upper feed point of an absorber column; receiving the first vapor portion of the separated feed gas that has been cooled at a lower feed point of the absorber column; using the absorber column to produce an overhead vapor product that is substantially free of high freezing point freezing components and a bottoms product liquid stream that includes freezing components and non-freezing components; and reheating the overhead vapor product from the absorber column using the heat exchanger.

2. The method of claim 1, wherein the absorber column includes one or more mass transfer stages.

3. The method of claim 1 or claim 2, further comprising compressing the reheated overhead vapor product using an expander-compressor to produce a compressed gas stream.

4. The method of claim 3, further comprising compressing the compressed gas stream to produce a higher pressure residue gas stream.

5. The method of claim 4, further comprising sending the higher pressure residue gas stream to a natural gas liquefaction facility.

6. The method of claim 4 or claim 5, wherein separating the reheated first liquid portion includes using a distillation column, a distillation tower, or a debutanizer.

7. The method of claim 6, further comprising merging a portion of the higher pressure residue gas stream with the non-freezing component stream, cooling the merged stream in a heat exchanger, and using the merged stream as the overhead feed to the absorber column.

8. The method of any one of claims 1-7, wherein at least partially liquefying the non-freezing component stream includes cooling and depressurizing at least a portion of the non-freezing component stream at a heat exchanger.

9. The method of claim 8, wherein the pressure of the non-freezing component stream is increased at a compressor prior to being partially liquefied.

10. The method of any one of claims 1-9, wherein the stream received at the upper feed point of the absorber column is introduced as a spray.

11. The method of any one of claims 1-10, further comprising routing a portion of the non-freezing component stream through a heat exchanger, wherein the reheated overhead vapor product is used for cooling to partially liquefy the non-freezing component stream, and further routing the cooled portion of the non-freezing vapor stream to a side inlet of the absorber column.

12. The method of any one of claims 1-11, further comprising routing a portion of the higher pressure residue gas stream through a heat exchanger and a valve to the absorber column.

13. The method of any one of claims 1-12, further comprising routing a portion of the bottoms product liquid stream from the absorber column to one or more additional columns selected from a demethanizer, a deethanizer, a depropanizer, and a debutanizer. ​ 14. The method of any of claims 1-13, wherein the absorber operates at a pressure higher than one of 400 psia, 600 psia, 700 psia, and 800 psia.

15. The method of any of claims 1-14, wherein the absorber operates at a pressure within one of 400 psia, 250 psia, 225 psia, and 150 psia of the inlet gas pressure.

16. The method of any of claims 1-15, wherein the removal of the high freezing point components from the natural gas is conducted without freezing of the high freezing point components.

17. A system for removing high freezing point components from natural gas, the system comprising: a heat exchanger for cooling the feed gas; a separation vessel for separating the feed gas into a first vapor portion and a first liquid portion, wherein the first liquid portion is re-heated in the heat exchanger; a second separation vessel for separating the re-heated first liquid portion into a high freezing point component stream and a non-freezing component stream; and an absorber for receiving the cooled and pressure-reduced non-freezing component stream and the cooled and pressure-reduced first vapor portion; wherein the overhead vapor product from the absorber is re-heated with the heat exchanger, the overhead vapor product being substantially free of high freezing point components; and wherein the bottoms product liquid stream from the absorber comprises high freezing point components and non-freezing components.

18. The system of claim 17, wherein the absorber comprises one or more mass transfer stages.

19. The system of claim 17 or claim 18, further comprising an expander-compressor to compress the re-heated overhead vapor product to produce a compressed gas stream, and a compressor to compress the compressed gas stream to produce a higher pressure residue gas stream.

20. The system of any of claims 17-19, wherein the second separation vessel is a distillation column, a distillation tower, or a debutanizer.

21. The system of any of claims 17-20, further comprising a sparger to introduce the stream to an upper feed point of the absorber.

22. The system of any of claims 17-21, further comprising one or more additional columns to receive a portion of the bottoms product liquid stream from the absorber, the one or more additional columns selected from a demethanizer, a deethanizer, a depropanizer, and a debutanizer.

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