Systems and methods for efficient heavy hydrocarbons removal

Abstract

Disclosed are systems and methods for processing liquefied natural gas (LNG). The method includes directing cooled natural gas to a first column, directing natural gas liquids from the first column into a second column, generating, by the second column, a reflux stream, and directing the reflux stream to a point upstream of the second column, wherein an introduction of the reflux stream enhances a removal of heavy hydrocarbons from a gas in the LNG facility. The method further includes directing an output of the second column to a third column, generating, by the third column, a solvent stream, and directing the solvent stream into an injection point, wherein the introduction of the solvent stream lowers a freezing point of a feed gas in the LNG facility.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] The present application claims priority to U.S. Provisional Patent Application No. 63 / 763,392 filed on Feb. 26, 2025, which is incorporated by reference in its entirety herein.TECHNICAL FIELD

[0002] Aspects of the present disclosure relate generally to systems and methods for heavy hydrocarbons removal in liquefied natural gas production and more particularly to optimizing the removal of heavy hydrocarbons during the liquefaction of natural gas.BACKGROUND

[0003] Natural gas is a commonly used resource comprised of a mixture of naturally occurring hydrocarbon gases typically found in deep underground natural rock formations or other hydrocarbon reservoirs. More particularly, natural gas is primarily comprised of methane and often includes other components, such as, ethane, propane, carbon dioxide, nitrogen, hydrogen sulfide, and / or the like.

[0004] Cryogenic liquefaction generally converts the natural gas into a convenient form for transportation and storage. More particularly, under standard atmospheric conditions, natural gas exists in vapor phase and is subjected to certain thermodynamic processes to produce liquefied natural gas (LNG). Liquefying natural gas greatly reduces its specific volume, such that large quantities of natural gas can be economically transported and stored in liquefied form.

[0005] Some of the thermodynamic processes generally utilized to produce LNG involve cooling the natural gas to a temperature that results in liquid near atmospheric vapor pressure. For example, a natural gas stream may be sequentially passed at an elevated pressure through multiple cooling stages that cool the gas to successively lower temperatures until the liquefaction temperature is reached. Stated differently, the natural gas stream is cooled through indirect heat exchange with one or more refrigerants, such as propane, propylene, ethane, ethylene, methane, nitrogen, carbon dioxide, and / or the like, and expanded to near atmospheric pressure.

[0006] In order to store and transport natural gas in the liquid state, the natural gas is preferably cooled to −150° C. to −162° C. where it possesses a near-atmospheric vapor pressure. Numerous systems exist in the prior art for the liquefaction of natural gas or the like in which the gas is liquefied by sequentially passing the gas at an elevated pressure through a plurality of cooling stages whereupon the gas is cooled to successively lower temperatures until the liquefaction temperature is reached. Cooling is generally accomplished by heat exchange with one or more refrigerants such as nitrogen, propane, propylene, ethane, ethylene, and methane or a combination of one or more of the preceding. In the art, the refrigerants are frequently arranged in a cascaded manner and each refrigerant is employed in a closed refrigeration cycle.

[0007] Further cooling of the liquid is possible by expanding the liquefied natural gas to atmospheric pressure in one or more expansion stages. In each stage, the liquefied gas is flashed to a lower pressure thereby producing a two-phase gas-liquid mixture at a significantly lower temperature. The liquid is recovered and may again be flashed. In this manner, the liquefied gas is further cooled to a storage or transport temperature suitable for liquefied gas storage at near-atmospheric pressure. In this expansion to near-atmospheric pressure, some additional volumes of liquefied gas are flashed. The flashed vapors from the expansion stages are generally collected and recycled for liquefaction or utilized as fuel gas for power generation.

[0008] It is common practice in the art of processing natural gas to subject the gas to cryogenic treatment to separate hydrocarbons having a molecular weight higher than methane (C2+) from the natural gas thereby producing a treated gas predominating in methane and a C2+ stream useful for other purposes.

[0009] During cooling of the processed natural gas stream, trace amounts of heavy hydrocarbon components (“heavy hydrocarbons”), typically C6 or heavier, often freeze in systems of an LNG plant, including heat exchangers. As these components freeze during the cooling process, deposits build up on internal surfaces of various systems of the LNG plant. Such fouling may result in a shutdown of one or more systems of the LNG plant to remove the deposits, resulting in a loss of production.

[0010] The removal of residual amounts of heavy hydrocarbons from the natural gas stream immediately prior to the liquefaction of a major portion of said stream is a major operational problem in the liquefaction of natural gas. The tendency of such components to precipitate and solidify thereby causes fouling and plugging of pipes and key process equipment. Although these heavier hydrocarbons are typically present at concentrations of less than 0.5 mol %, their presence can be problematic, because they can freeze within the devices used in a liquefaction process. If the heavy hydrocarbons freeze within a heat exchanger, such as a brazed-aluminum heat exchanger, or another part of the liquefaction process, an obstruction occurs, and the liquefaction process will have to be shut down. After shutting down, the location of the obstruction, i.e., frozen hydrocarbons, must be located, followed by removal of the obstruction. Processes used to remove the frozen heavy hydrocarbons can include physical removal and melting of the frozen hydrocarbons.

[0011] Stopping the liquefaction process to remove the frozen hydrocarbons can be expensive and time consuming and is preferably avoided. Accordingly, a process is desired for preventing the C6+ hydrocarbons from freezing during the liquefaction process and removal of any C6+ hydrocarbons that may be present in the liquefaction process.

[0012] One method of removing heavies can utilize natural gas liquids (NGLs) that are generated during the liquefaction process. Specifically, the NGLs dissolve the heavies present in the natural gas feed stream. In this method, the C2-C5 hydrocarbons present in the natural gas feed stream condense to form NGLs, which dissolve the heavies thereby preventing the heavies from solidifying. However, when insufficient amounts of C2-C5 hydrocarbons are present in the natural gas feed stream, the heavy hydrocarbons within the feed stream can freeze before the NGL solvents are generated, or the feed stream may never generate a sufficient amount of NGL to adequately remove the heavy compounds. As the heavy hydrocarbon content approaches the limits of naturally occurring NGL solubility, the heavy hydrocarbons may freeze thereby forming solids.

[0013] Further, there is the lack of a cost-effective means for recovering the higher molecular weight hydrocarbons from the gas stream prior to liquefaction of the stream in major portion or returning the remaining stream to a pipeline or other processing step. The recovered higher molecular weight hydrocarbons generally possess a greater value on a per unit mass basis than the remaining components in the gas stream. Additionally, the higher molecular weight hydrocarbons may need to be extracted from the natural gas feed stream in order to reduce the heating value of the LNG product below the product specification.

[0014] It is with these observations in mind, among others, that various aspects of the present disclosure were conceived and developed.SUMMARY

[0015] Implementations described and claimed herein address the foregoing problems by providing systems and methods for processing liquefied natural gas (LNG). In one implementation, a method for optimizing heavy hydrocarbon removal in a liquefied natural gas (LNG) facility, the method including directing cooled natural gas to a first column, directing natural gas liquids from the first column into a second column, generating, by the second column, a reflux stream, and directing the reflux stream to a point upstream of the second column, wherein an introduction of the reflux stream enhances a removal of heavy hydrocarbons from a liquified natural gas in the LNG facility. In some instances, the method further includes directing an output of the second column to a third column, generating, by the third column, a solvent stream, and directing the solvent stream into an injection point, wherein the introduction of the solvent stream lowers a freezing point of a feed gas entering into one or more chillers of a propane refrigeration cycle.

[0016] The present disclosure provides an integrated process for recovery of the components of a feed gas containing methane and heavier hydrocarbons while maximizing NGL recovery and minimizing capital expenditures and operating costs incurred with the LNG facility. The present invention is also intended to improve separation efficiency within the recovery column while maintaining column pressure as high as practically possible to achieve an efficient and economical utilization of mechanical refrigeration in the liquefaction process. This is achieved by the introduction of an enhanced liquid reflux specifically suitable for the purpose of the recovery column.

[0017] The present disclosure, in the broadest sense, provides an integrated process and apparatus for cryogenically recovering ethane, propane and heavier components during natural gas liquefaction processes via a distillation column, in which the reflux derived from various sources in the liquefaction process is essentially free of the components to be recovered. The provision of an enhanced liquid reflux, which is lean on the NGL components, to the distillation column permits a high recovery of NGL components even when the column is operated at a relatively high pressure. The process involves introducing a cooled gas / condensate feed into a first distillation column, e.g., a recovery column, at one or more feed trays. The gas / condensate feed is separated into a first liquid stream primarily comprising NGL components to be recovered and a methane-rich overhead stream essentially free of NGL components. The methane-rich overhead stream is further cooled to total liquefaction. Preferably the liquified methane-rich stream is further sub-cooled. This liquified, and preferably sub-cooled, methane-rich stream under pressure is subsequently flashed to near atmospheric pressure in one or more steps with the liquid collected in the final flash step being delivered to the LNG tank for storage. The flashed vapor after cold recovery is compressed to a higher pressure for delivery as fuel gas. Excess flashed vapor, if any, is recycled to the liquefaction process in which it is ultimately liquified as pressurized LNG or as liquid reflux to the recovery column. The first liquid stream is introduced into a second distillation column, at one or more feed trays. In the second column, the first liquid stream is separated into a C5+ stream from the bottom and a first vapor portion primarily comprising all the remaining lighter components from the overhead.

[0018] In one aspect of the present disclosure, the first vapor portion from the second column is compressed and cooled to substantial condensation and thereafter introduced to the top of the recovery column as a liquid reflux. This reflux stream will contain an extremely low concentration of the heavy components to be recovered in the NGL product. This stream enhances the recovery efficiency within the column and reduces the loss of NGL components in the methane-rich overhead stream to a minimum. A high NGL recovery is therefore achieved even with a relatively high operating pressure for the recovery column.

[0019] Implementations described and claimed herein generally relate to the liquefaction of natural gas. More particularly, but not by way of limitation, implementations of the present disclosure include systems and processes for removing heavies including, but not limited to, C6+ hydrocarbons, during the liquefaction of natural gas. As discussed above, processes and systems which are commonly used form natural gas liquids (NGLs) during the liquefaction of natural gas feed streams. However, in some instances the NGLs produced by the feed stream are not sufficient to remove the quantity of heavies present when the natural gas feed stream is low in C3+ hydrocarbons or when the natural gas contains an excess of C6+ hydrocarbons. Essentially, the composition of such feed streams will not naturally produce enough natural gas liquids (NGL) during the liquefaction process to dissolve the heavies present in the feed stream, causing the heavies to freeze during the liquefaction process. The processes and systems disclosed herein are designed to add self-generated and / or external natural gas liquid (NGL) to the natural gas feed stream to correct this discrepancy.

[0020] During the liquefaction process, the self-generated and / or external NGL can dissolve the heavies present in the natural gas feed stream and prevent them from freezing. The NGLs can then be removed and recycled to the beginning of the liquefaction process for reuse, which decreases overall costs and is environmentally friendly. The processes and systems described herein can be used where the natural gas feed streams are very rich, for example those containing less than 90% methane and nitrogen, and an excess of C6+ heavy hydrocarbons; lean natural gas, for example containing more than 95% methane and nitrogen; and very lean natural gas, containing over 98% methane and nitrogen and little, if any, NGL; among others. In such feed streams, if NGLs are not added to the natural gas feed stream the heavies present in the feed stream will freeze at the temperatures reached during the liquefaction process causing a buildup. As discussed above, the entire process must then be shut down in order to remove the buildup.

[0021] In another aspect, a heavies removal system with solvent recycle comprising a vessel configured to receive a natural gas feed stream and a solvent; one or more chillers for cooling the natural gas feed stream and the solvent to a temperature below about −59° C.; a first recovery column for separating out the gas stream from the liquid stream; a second column separating out the first liquid stream into a liquid stream and a gas stream that is cooled and condensed and sent as reflux to the recovery column; a third column separating out the second liquid stream into a gas stream and a liquid condensate product stream. The gas stream from the third column is cooled and condensed to become a liquid recycle stream which connects as solvent to the injection point. This liquid recycle stream is rich in pentanes and acts as a solvent in the natural gas feed stream, preventing the heavies from freezing during the liquefaction process.

[0022] Other implementations are also described and recited herein. Further, while multiple implementations are disclosed, still other implementations of the presently disclosed technology will become apparent to those skilled in the art from the following detailed description.BRIEF DESCRIPTION OF THE DRAWINGS

[0023] The foregoing summary, as well as the following detailed description, will be better understood when read in conjunction with the appended drawings. For the purpose of illustration, the drawings show certain examples of the presently disclosed technology. It should be understood, however, that the presently disclosed technology is not limited to the precise examples and features shown. The presently disclosed technology is capable of modifications in various aspects, all without departing from the spirit and scope of the presently disclosed technology. Accordingly, the drawings and detailed description are to be regarded as illustrative in nature and not limiting. The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate implementations of apparatuses consistent with the presently disclosed technology and, together with the description, serve to explain advantages and principles consistent with the presently disclosed technology, in which:

[0024] FIG. 1 illustrates an example LNG production system for removing heavy hydrocarbons throughout LNG production.

[0025] FIG. 2 illustrates an example method of heavy hydrocarbon removal involving the addition of a reflux stream.

[0026] FIG. 3 illustrates an example method of heavy hydrocarbon removal involving the addition of a solvent stream.DETAILED DESCRIPTION

[0027] The present disclosure involves systems and methods of heavy hydrocarbons removal for LNG production.

[0028] As discussed above, the freezing of heavy hydrocarbons in LNG processing systems can lead to build up within various system of the LNG processing system, leading to plugged valves, pipes, or heat exchangers, preventing optimal operation of the LNG processing system. To address this issue, and prevent the formation of solids, heavy hydrocarbons must be removed from the gas feed to the facility to levels below a minimum solubility limit at every stage within the liquefaction process. In some instances, the addition of a solvent to the gas feed to the facility can aid in preventing the heavy hydrocarbons from forming solids. In some instances, the solvent is further recovered and recirculated, which can reduce cost for solvent purchasing as well as reduced operating costs.

[0029] Accordingly, the presently disclosed technology reliably eliminates freezing in chilling and liquefaction areas of the LNG processing system by providing the required solvent purity and quantity while simultaneously providing a reflux stream to the recovery column. The reflux stream enhances the recovery efficiency within the recovery column and reduces the loss of NGL components in the methane-rich overhead stream to a minimum. A high NGL recovery is therefore achieved even with a relatively high operating pressure for the recovery column. Other advantages will be apparent from the present disclosure.I. Terminology

[0030] The liquefaction process described herein may incorporate one or more of several types of cooling systems and methods including, but not limited to, indirect heat exchange, and / or expansion or pressure reduction.

[0031] Indirect heat exchange, as used herein, refers to a process involving a cooler stream cooling a substance without actual physical contact between the cooler stream and the substance to be cooled. Specific examples of indirect heat exchange include, but are not limited to, heat exchange undergone in a shell-and-tube heat exchanger, a core-in-shell heat exchanger, and a brazed aluminum plate-fin heat exchanger. The specific physical state of the refrigerant and substance to be cooled can vary depending on demands of the refrigeration system and type of heat exchanger chosen.

[0032] Expansion or pressure reduction cooling refers to cooling which occurs when the pressure of a gas, liquid or a two-phase system is decreased by passing through a pressure reduction means. In some implementations, expansion means may be a Joule-Thomson expansion valve. In other implementations, the expansion means may be either a hydraulic or gas expander. Because expanders recover work energy from the expansion process, lower process stream temperatures are possible upon expansion.

[0033] As used herein, “natural gas” refers to a gas feed stream comprising methane along with ethane, propane, butane, and pentane, as well as other components. Traditionally, natural gas referred to a naturally occurring hydrocarbon gas mixture consisting primarily of methane, but commonly including varying amounts of other higher alkanes, and sometimes a small percentage of carbon dioxide, nitrogen, hydrogen sulfide, or helium. The term “natural gas” today may be used to describe mixtures and gases produced from a variety of sources to create a combustible mixture of methane and other hydrocarbons. Depending upon the sources and mixtures, natural gas may be considered rich or lean dependent upon concentrations of methane as compared to other hydrocarbons. For example, a “lean” natural gas typically contains 95% or greater methane; whereas a “very lean” natural gas typically contains greater than 98% methane. On the contrary, a rich natural gas contains less than 90% methane. The terms “rich” and “lean” do not describe the content of other natural gas components present. For example a mixture of 90% methane may have varying concentrations of other hydrocarbons dependent upon the source or sources of the natural gas.

[0034] As used herein, “natural gas liquid” or “NGL” refers to hydrocarbons—in the same family of molecules as natural gas and crude oil, composed exclusively of carbon and hydrogen. NGLs can include ethane (C2H6), propane (C3H8), butane (C4H10), isobutane (C4H10), and pentane (C5H12) in various concentrations. NGLs may be all one component or may contain mixtures of various components, dependent upon processing and sources.

[0035] As used herein, “heavies,”“heavy hydrocarbons,” and “C6+ hydrocarbons” may be used interchangeably to refer to heavy hydrocarbon contaminants that may be present in a natural gas. Typically, “heavies” refer to all hydrocarbons that contain six or more carbon atoms but may include any other hydrocarbon that have a normal boiling point that exceeds that of n-pentane.

[0036] As used herein, “reflux” refers to a portion of condensed overhead vapor from a distillation column that is sent to the same or another distillation column to enhance the separation process. The liquid reflux flows downwards, cooling and condensing the rising vapors, improving the efficiency of the separation.

[0037] As used herein, “solvent” refers to a substance, typically a liquid, that dissolves a solute, resulting in a solution. More specifically, in this application a pentane-rich solvent dissolves the heavies present in the natural gas feed stream, creating a heavies solution and preventing the heavies from freezing.

[0038] In the description, phraseology and terminology are employed for the purpose of description and should not be regarded as limiting. For example, the use of a singular term, such as “a”, is not intended as limiting of the number of items. Also, the use of relational terms such as, but not limited to, “down” and “up” or “downstream” and “upstream”, are used in the description for clarity in specific reference to the figures and are not intended to limit the scope of the presently disclosed technology or the appended claims. Further, any one of the features of the presently disclosed technology may be used separately or in combination with any other feature. For example, references to the term “implementation” means that the feature or features being referred to are included in at least one aspect of the presently disclosed technology. Separate references to the term “implementation” in this description do not necessarily refer to the same implementation and are also not mutually exclusive unless so stated and / or except as will be readily apparent to those skilled in the art from the description. For example, a feature, structure, process, step, action, or the like described in one implementation may also be included in other implementations but is not necessarily included. Thus, the presently disclosed technology may include a variety of combinations and / or integrations of the implementations described herein. Additionally, all aspects of the presently disclosed technology as described herein are not essential for its practice.

[0039] Lastly, the terms “or” and “and / or” as used herein are to be interpreted as inclusive or meaning any one or any combination. Therefore, “A, B or C” or “A, B and / or C” mean any of the following: “A”; “B”; “C”; “A and B”; “A and C”; “B and C”; or “A, B and C.” An exception to this definition will occur only when a combination of elements, functions, steps or acts are in some way inherently mutually exclusive.II. General Architecture and Operations

[0040] In order to liquefy a natural gas, the feed stream is cooled and condensed. During the process, heavies present in the natural gas feed stream can freeze, causing a buildup within the equipment used throughout the process. In at least one implementation, external and / or self-generated NGLs are introduced into the process and systems described herein and used as a solvent to prevent the buildup. Specifically, the NGLs can dissolve the heavies present in the natural gas feed stream, thus preventing the heavies from freezing during the liquefaction process. External NGLs that can be used in accordance with the processes and systems described herein can include C2-C5+ hydrocarbons. Specific examples of NGLs can include, but are not limited to, ethane, propane, butane, isobutane, pentane, isopentane and pentanes plus (also known as natural gasoline). In one implementation, the NGL comprises a C2-C6 alkane. In another implementation, the NGL comprises a C4 and / or C5 hydrocarbon. In one implementation, the NGL comprises ethane and / or propane. In another implementation, the NGL comprises pentane and / or isopentane. In the systems and processes disclosed herein, at least one NGL, and commonly a mixture of two or more NGLs, is combined with the natural gas feed stream. The natural gas feed stream is then further cooled and introduced to a recovery column, thereby removing additional heavies and other undesired components from the gas to be liquefied. In one implementation, the methane in the gas portion from the recovery column can contain heavies in an amount of parts per million or parts per billion levels. In another implementation, a reflux stream containing an extremely low concentration of the heavy components to be recovered in the NGL product, is introduced to the recovery column. This reflux stream enhances the recovery efficiency within the column and reduces the loss of NGL components in the methane-rich overhead stream to a minimum. A high NGL recovery is therefore achieved even with a relatively high operating pressure for the recovery column.

[0041] In at least one implementation, the present disclosure can be implemented in a facility used to cool natural gas to its liquefaction temperature, and thereby produce liquefied natural gas (LNG). The LNG facility can employ one or more refrigerants to extract heat from the natural gas and reject the heat to the environment. Numerous configurations of LNG systems exist and may be used in conjunction with the heavies removal systems and the processes of using the heavies removal systems disclosed herein.

[0042] In one implementation, the LNG process may employ a cascade-type refrigeration process that uses a plurality of multi-stage cooling cycles, each employing a different refrigerant composition, to sequentially cool the natural gas stream to lower and lower temperatures. For example, a first refrigerant may be used to cool a first refrigeration cycle. A second refrigerant may be used to cool a second refrigeration cycle. A third refrigerant may be used to cool a third refrigeration cycle. Each refrigeration cycle may include a closed cycle or an open cycle. The terms “first”, “second”, and “third” refer to the relative position of a refrigeration cycle. For example, the first refrigeration cycle is positioned just upstream of the second refrigeration cycle while the second refrigeration cycle is positioned upstream of the third refrigeration cycle and so forth. While at least one reference to a cascade LNG process comprising three different refrigerants in three separate refrigeration cycles is made, this is not intended to be limiting. It is recognized that a cascade LNG process involving any number of refrigerants and / or refrigeration cycles may be compatible with one or more implementations of the presently disclosed technology. Other variations to the cascade LNG process are also contemplated. It will also be appreciated that the presently disclosed technology may be utilized in non-cascade LNG processes. One example of a non-cascade LNG process involves a mixed refrigerant LNG process that employs a combination of two or more refrigerants to cool the natural gas stream in at least one cooling cycle.

[0043] As discussed above, the feed to the LNG facility may contain heavies which freeze, precipitate, and collect in the chillers or cooling components of the LNG facility. In one implementation, a heavy hydrocarbon removal system may be included within the LNG facility to help prevent this formation of solids due to heavy hydrocarbons. As such, the heavy hydrocarbons removal system reduces or eliminates accumulations of heavy component solids in the heat exchangers while causing little or no downtime for the heat exchangers. Reducing obstructions caused by freezing heavy components with solvent injections and heavies removal improves the operating efficiency of the LNG processing facility.

[0044] Turning to FIG. 1, an example LNG production system 100 with a heavy hydrocarbons removal system 102 is shown. The heavy hydrocarbons removal system 102 may be deployed in the LNG production system 100, for example, to prevent heavy hydrocarbon freezing in heat exchangers of the LNG production system 100 and / or other cooling or chilling components of the LNG production system 100.

[0045] In one implementation, the heavy hydrocarbons removal system 102 includes a triple-stage approach including a first column 110, a second column 112 and a third column 114. In some implementations, the first column 110 may be a recovery column. Referring to FIG. 1, the heavy hydrocarbons removal system 102 is implemented at the point where the natural gas feed enters the propane refrigeration cycle, however, the heavy hydrocarbons removal system 102 may be implanted at other locations throughout the LNG processing facility, particularly in any vessel or equipment in which the accumulation and freezing of heavy hydrocarbons is of concern.

[0046] In one example, natural gas liquids from the first column 110, may be fed into the second column 112 via conduit 120. The second column 112 may be a distillation column or flash drum used to separate and purify selected hydrocarbons from a mixture of hydrocarbons. For example, the second column 112 generates a C2-C4 rich reflux stream, which is then directed back to the first column 110, via conduit 122. The reflux stream allows for enhanced separation of heavy components from the lighter components (methane and ethane) in the first column 110. The provision of the reflux stream also prevents lighter hydrocarbons from circulating excessively within the solvent stream 128. Excessive circulation of lighter hydrocarbons can dilute the solvent, necessitating higher flow rates of solvent to achieve the depression of the freezing point of the feed gas.

[0047] In one example, the third column 114 is located downstream of the second column 112 and connected to the second column 112 via conduit 126. The third column 114 may be a distillation column or flash drum used to separate and remove pentane from even heavier hydrocarbons. The third column 114 generates a pentane rich solvent stream, which is directed back to an injection point 130 via conduit 128, which in the present example, is located at a point in conduit 140 at the entrance to the chillers in the propane refrigeration cycle. This pentane rich solvent stream lowers the freezing point of the feed gas entering the chillers in the propane refrigeration cycle, preventing freezing issues in any of the heat exchangers within the propane refrigeration cycle and downstream.

[0048] The integration of the heavy hydrocarbons removal system 102 ensures efficient heavy hydrocarbons removal and maintains solvent purity and optimizes the first column 110, enhancing the efficiency and reliability of the overall process. The triple-stage approach improves operational efficiency and reliability in managing heavy hydrocarbons and preventing freezing both upstream and downstream of the first column 110.

[0049] FIG. 2 illustrates example operations of a method 200 for heavy hydrocarbon removal involving the addition of a reflux stream, which may be performed by any of the systems discussed herein. In some instances, an operation 202 includes directing cooled natural gas to a first column, an operation 204 includes directing natural gas liquids from the first column to a second column. An operation 206 includes generating, by the second column, a reflux stream. The reflux stream contains C1-C4 hydrocarbons. An operation 208 includes directing the reflux stream at a point upstream of the second column, wherein an introduction of the reflux stream enhances a removal of heavy hydrocarbons from a liquefied natural gas in the liquified natural gas facility.

[0050] FIG. 3 illustrates example operations of a method 300 for heavy hydrocarbon removal involving the addition of a solvent stream to the feed gas which may be performed by any of the systems discussed herein. The method 300 may be executed in parallel with or simultaneously with method 200.

[0051] In some instances, an operation 302 involves directing an output of the second column to a third column. An operation 304 includes generating, by the third column, a solvent stream. The solvent stream may include a pentane-rich solvent. An operation 306 includes directing the solvent stream into an injection point, wherein the introduction of the solvent stream lowers the freezing point of a feed gas entering into one or more chillers of a propane refrigerant cycle.

[0052] It is to be understood that the specific order or hierarchy of steps in the methods depicted in FIGS. 2 and 3 are instances of example approaches and can be rearranged while remaining within the disclosed subject matter. For instance, any of the steps depicted in FIGS. 2 and 3 may be omitted, repeated, performed in parallel, performed in a different order, and / or combined with any other of the steps depicted in FIGS. 2 and 3. Any accompanying method claims thus present elements of the various steps in a sample order and are not necessarily meant to be limited to the specific order or hierarchy presented unless explicitly stated.

[0053] Moreover, it will be appreciated that the example LNG production system 100 is exemplary only and other systems or modifications to these systems may be used to eliminate or otherwise reduce fouling in one or more heat exchangers of the LNG facility in accordance with the presently disclosed technology.

[0054] While the present disclosure has been described with reference to various implementations, it will be understood that these implementations are illustrative and that the scope of the present disclosure is not limited to them. Many variations, modifications, additions, and improvements are possible. More generally, implementations in accordance with the present disclosure have been described in the context of particular implementations. Functionality may be separated or combined in blocks differently in various implementations of the disclosure or described with different terminology. These and other variations, modifications, additions, and improvements may fall within the scope of the disclosure as defined in the claims that follow.

Claims

1. A method for optimizing heavy hydrocarbon removal in a liquefied natural gas (LNG) facility, the method comprising:directing cooled natural gas feed to a first column;directing natural gas liquids from the first column into a second column;generating, by the second column, a reflux stream; anddirecting the reflux stream to a point upstream of the second column,wherein introduction of the reflux stream enhances removal of heavy hydrocarbons from a feed gas in the LNG facility.

2. The method of claim 1, wherein the reflux stream is rich in C1 to C3 hydrocarbons.

3. The method of claim 1, the method further comprising:directing an output of the second column to a third column;generating, by the third column, a solvent stream; anddirecting the solvent stream into an injection point,wherein introduction of the solvent stream lowers a freezing point of the feed gas in the LNG facility.

4. The method of claim 3, wherein the solvent stream comprises a pentane-rich solvent.

5. The method of claim 3, wherein the injection point for the solvent stream is located where the feed gas enters one or more chillers.

6. The method of claim 3, wherein the reflux stream and the solvent stream are introduced into the LNG facility simultaneously.

7. The method of claim 3, wherein introduction of the reflux stream prevents lighter hydrocarbons from circulating excessively within the LNG facility.

8. The method of claim 3, wherein introduction of the reflux stream reduces a solvent recirculation rate.

9. The method of claim 3, wherein introduction of the reflux stream lowers solvent losses.

10. A system for optimizing heavy hydrocarbon removal in a liquefied natural gas (LNG) process, the system comprising:a first column configured to receive cooled natural gas feed;a second column fluidly coupled to the first column and configured to receive natural gas liquids from the first column;wherein the second column is configured to generate a reflux stream; anda reflux conduit configured to direct the reflux stream to a point upstream of the second column, wherein introduction of the reflux stream upstream of the second column enhances removal of heavy hydrocarbons from a feed gas.

11. The system of claim 10, wherein the reflux stream is rich in C1 to C3 hydrocarbons.

12. The system of claim 10, the system further comprising:a third column fluidly coupled to the second column and configured to receive an output from the second column;wherein the third column is configured to generate a solvent stream; anda solvent conduit configured to direct the solvent stream to an injection point, wherein introduction of the solvent stream lowers a freezing point of the feed gas.

13. The system of claim 12, wherein the solvent stream comprises a pentane-rich solvent.

14. The system of claim 12, wherein the injection point is located at where the feed gas enters one or more chillers.

15. The system of claim 12, wherein the reflux conduit and the solvent conduit are configured to introduce the reflux stream and the solvent stream simultaneously.

16. The system of claim 12, wherein introduction of the reflux stream reduces circulation of lighter hydrocarbons within the system.

17. The system of claim 12, wherein introduction of the reflux stream reduces a solvent recirculation rate.

18. The system of claim 12, wherein introduction of the reflux stream lowers solvent losses.

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