US20220364005A1

US20220364005A1 - Lng process for variable pipeline gas composition

Info

Publication number: US20220364005A1
Application number: US17/815,178
Authority: US
Inventors: Attilio J. Praderio; Qi Ma; Wesley R. Qualls; Will T. JAMES; Michael J. Calderon; Paul R. Davies
Original assignee: ConocoPhillips Co
Current assignee: ConocoPhillips Co
Priority date: 2017-04-19
Filing date: 2022-07-26
Publication date: 2022-11-17

Abstract

The invention relates to a system, method and apparatus for processing natural gas in an LNG facility. A natural gas feed is introduced into a heavies removal unit. The heavies removal system includes a heavies removal column and a distillation column. The heavies removal column and the distillation column are connected via a purge/recovery line. One or more components of the natural gas feed is purged from the heavies removal column to the distillation column via the purge/recovery line to obtain a specified concentration or concentration range of heavy components feeding into the distillation column.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part application which claims benefit under 35 USC § 120 to U.S. application Ser. No. 15/954,771 filed Apr. 17, 2018, entitled “LNG Process for Variable Pipeline Gas Composition,” which claims benefit under 35 USC § 119(e) to U.S. Provisional Application Ser. No. 62/487,170 filed Apr. 19, 2017, entitled “LNG Process for Variable Pipeline Gas Composition” which is incorporated herein in its entirety.

FIELD OF THE INVENTION

The present invention relates generally to a method and apparatus for processing natural gas. In another aspect, methods and apparatus provide stable processing of liquefied natural gas (LNG) across a highly variable and wide range of feed compositions.

BACKGROUND OF THE INVENTION

Liquefied Natural Gas (LNG) liquefaction facilities accept feed gas (e.g., methane, ethane, propane, butane, carbon dioxide, nitrogen, etc.) which is converted into a liquefied form through various treatment processes (e.g., impurities removal, multi-stage cooling, etc.). These facilities are typically designed to accept feed gas compositions that fall within a specified range. Variability of the feed gas composition that exceeds a facility's capabilities can lead to frequent upsetting of the liquefaction process. This excessive variability may be particularly troublesome when liquefying pipeline feed gas.

BRIEF SUMMARY OF THE DISCLOSURE

The present invention relates generally to a method and apparatus for processing natural gas. In another aspect, methods and apparatus provide stable processing of liquefied natural gas (LNG) across a highly variable and wide range of feed compositions.
The invention more particularly relates to a system, method and apparatus for processing natural gas in an LNG facility. A natural gas feed is introduced into a heavies removal unit, wherein the heavies removal system includes a heavies removal column and a distillation column, wherein the heavies removal column and the distillation column are fluidly connected. One or more components of the natural gas feed is purged from the heavies removal column to a methane recycle stream via the purge/recovery line to obtain a specified concentration or concentration range of heavy components feeding into the distillation column.
The invention more particularly relates to a system, method and apparatus for processing natural gas feed during natural gas liquefaction. The natural gas feed is introduced into a heavies removal unit, wherein the heavies removal system includes a heavies removal column and a demethanizer, wherein the heavies removal column and the demethanizer are fluidly connected. The heavies removal column is downstream of the demethanizer. The composition of the natural gas feed is determined before it is introduced into the demethanizer. One or more heavy components of the natural gas feed is purged from the heavies removal column to a methane recycle stream via the purge/recovery line to reduce or increase concentration of heavy components feeding into the demethanizer.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the present invention and benefits thereof may be acquired by referring to the follow description taken in conjunction with the accompanying drawings in which:

FIGS. 1A-1B illustrate sample variability in feed gas composition from pipeline. FIG. 1A shows methane mole % during a 3 week window. FIG. 1B shows ethane mole % during the same 3 week window.

FIG. 2 illustrates a heavies removal unit in accordance with an embodiment of the present invention.

FIG. 3 illustrates an example simplified flow diagram of a cascade refrigeration process with a two-stage heavies removal for LNG production.

DETAILED DESCRIPTION

Turning now to the detailed description of the preferred arrangement or arrangements of the present invention, it should be understood that the inventive features and concepts may be manifested in other arrangements and that the scope of the invention is not limited to the embodiments described or illustrated. The scope of the invention is intended only to be limited by the scope of the claims that follow.
The following examples of certain embodiments of the invention are given. Each example is provided by way of explanation of the invention, one of many embodiments of the invention, and the following examples should not be read to limit, or define, the scope of the invention.
Recent LNG projects have introduced pipelines as the source of feed gas in an LNG Optimized Cascade Process (OCP). The Optimized Cascade Process is based on three multi-staged, cascading refrigerants circuits using pure refrigerants, brazed aluminum heat exchangers and insulated cold box modules. Pure refrigerants of propane (or propylene), ethylene, and methane are utilized.
The Optimized Cascade Process may use a heavies removal distillation column (heavies removal unit or HRU) to eliminate C6+ hydrocarbons (i.e. heavy components) from the natural gas prior to condensing the gas to LNG. In the usual case gas has already been amine treated and dehydrated prior to heavies removal. Heavies removal is done to prevent freezing from occurring in the liquefaction heat exchangers and to moderate the heating value of the LNG. It also prevents LNG from going off spec due to increased levels of heavy components.
One major technical problem with the LNG projects involving pipeline feed gas is that the gas feed encompasses a wider range of compositions than normally anticipated and/or designed to process. In other words, heavies removal units typically require hydrocarbon reflux meeting appropriate quality and quantity standards to achieve effective and efficient removal of heavy hydrocarbons. Lean natural gas sources lacking adequate amounts of C2-C4 hydrocarbons may not be suitable for refluxed heavies removal units because of the difficulty in generating sufficient quantities of reflux stream with satisfactory composition. Still, lean natural gases may contain significant amounts of C6+ hydrocarbons that can freeze and/or deposit in downstream cryogenic liquefaction equipment. FIGS. 1A-1B illustrate an example of variability in methane and ethane composition of natural gas feed in an LNG liquefaction facility during a 3 week period.
In a typical OCP setup, a first column (demethanizer) within a Heavies Removal Unit may be used to reflux relatively heavy components originating from downstream column overheads. When there is high variability of feed gas compositions, refluxing with heavier components from downstream column overheads is not possible for all feed compositions.
Alternatively, lean methane reflux unit may be used. However, the lean reflux unit is also less than ideal for used at all times (this unit is typically designed for startup) for all feed gas compositions. Equipment for the lean methane reflux as well as the demethanizer are typically not sized for operation at full feed rates but rather at reduced rates until sufficient heavies are cycled up to create a heavies reflux during startup.
With the inability to reflux with heavy components, a startup/offtest line recycling heavy components from the downstream two column overhead streams tends may be installed. In this setup, recycling the heavy components back to the feed line tends to cycle up propane and heavier components, which eventually must be either fueled or flared. Continual adjustments of operating setpoints are required to process the highly variable gas leading to frequent upsets.
The present invention provides a method for purging undesirable components present in a gas feed stream to the methane recycle system where the components can be recovered as valuable product. This purge can be accomplished using a purge/recovery line. The rate of purging from the heavies removal system may be adjusted to absorb the compositional variations of the feed gas. Once the heavier components enter the methane recycle stream, the combined stream becomes easier to condense which conserves refrigeration horsepower. Thus, the purge/recovery line makes the overall LNG plant stable and more efficient across a wide range of pipeline compositions with high compositional variability.
According to an embodiment, the present invention provides a method for purging undesirable problematic gas components that would otherwise cycle up to the recycle stream. Instead, the purged gas components can be recovered in the LNG stream without concern of freezing. Flow through the purge/recovery line may be adjusted to fix the flow rate recycle to the high pressure demethanizer feed. Since approximately 50% of the liquid in the bottom portion of the high pressure demethanizer are recycled liquids, this greatly stabilizes the high pressure demethanizer operation. The addition of this purge/recovery line also reduces the cycle up of components that otherwise must be fueled and/or flared. By controlling the rate through the purge/recovery line, a fixed set of operating setpoints for all columns are possible for over about 80% of the feed range without operating intervention or setpoint changes. Thus, the invention provides very stable operation across a highly variable and wide range of feed compositions with minimal operator intervention.
As alluded to earlier, one of the advantages of the present invention is that the purged problematic components can be efficiently recovered as LNG. In one embodiment, the purged components from the heavies removal unit are routed to a methane recycle stream that is condensed with ethylene refrigeration in the optimized cascade process. The introduction of heavier components within the methane recycle makes condensing with ethylene easier which in turn conserves ethylene turbine horsepower requirements. Adjusting the rate of the purge/recovery line allows one to fix a major portion of the heavy components recycled to the high pressure demethanizer feed, thus greatly helping to stabilize the feed across a wide range of compositions. Fixing the portion of overhead from the second column returned to the system and allowing remaining flow to continuously purge to a system where it can be efficiently recovered as valuable LNG product, provides a means to continuously adjust to variable pipeline compositions with minimal operator intervention. The present invention purge/recover line acts as a compositional shock absorber for variable pipeline gas. The invention eliminates the need to route cycled up pentanes and heavier components to fuel, which is less economical than recovering as product. The pentanes and heavier are also problematic in the fuel gas system. The present invention allows a single set of operating conditions over 80% or more of the pipeline rates, compositional variations, allowing minimal operator intervention. The present invention offers the ability to process a wider range of compositions and higher pipeline compositional variations than other current technology available with minimal operator intervention.
Referring to FIG. 2, natural gas feed is introduced into the heavies removal unit 2010 (perforated box) via inlet 2020. The natural gas feed is then routed to the heavies removal column 2030 within the heavies removal unit 2010 where it is then separated into light and heavy components. The light components are routed to a demethanizer 2100 via a line 2050 that connects a top portion of the heavies removal column 2030 to a mid/top portion of the demethanizer 2100. The heavy components are routed to the demethanizer 2100 via a line 2060 that connects a bottom portion of the heavies removal column to a mid/bottom portion of the demethanizer 2100. A purge/recovery line 2040 that removes heavies (C6+) to methane recycle stream is shown.
As shown in FIG. 2, the demethanizer 2100 is a distillation column. The top portion 2110 of the demethanizer 2100 is for heavy reflux at full feed rates (but also works acceptably with lean reflux) and may include a condenser, reflux drum, pump, and the like. The bottom portion of the demethanizer 2120 is reboiler and may include a reboiler, steam condensate, and the like. As shown, lean reflux is needed for normal operation of the demethanizer 2100. Demethanizer bottoms 2130 contains the removed pentanes and heavier components. The demethanizer bottoms control valve 2160 controls the flow rate into the condensate stabilizer feed pre-heater 2170 before feeding into the condensate stabilizer 2200. The condensate stabilizer 2200 lower is fed to the condensate stabilizer bottom system 2220 which includes a reboiler, and it may contain a bottom cooler, bottom pump, and the like. The condensate stabilizer heating medium is fed to the condensate stabilizer reboiler 2230. The condensate stabilizer bottoms 2240 contains the removed heavies, and is ultimately sent to storage. The condensate stabilizer 2200 top is fed to the condensate stabilizer overhead system 2210, which may contain condensers, reflux drum, reflux pumps, and the like. The condensate stabilizer net overhead 2250 stream light components. The condensate stabilizer net overhead 2250 stream is fed to the demethanizer reflux chillers 2260 which may use a refrigerant medium of either propane or propylene. The chilled condensate stabilizer net overhead 250 stream is fed to the demethanizer heavies reflux drum 2300, which may be a vertical or horizontal drum. The demethanizer heavies reflux drum net vapor 2310 contains the recovered lights and is devoid of heavies for all practical purposes. This light stream may be returned back into the process. The demethanizer heavies reflux pump 2320 and demethanizer heavies reflux control valve 2330 controls flow and pressure into the demethanizer heavies reflux chiller 2340 which sub-cools the stream that is sent as reflux to the demethanizer 2030. An optional recycle block 2350 may be used to store heavies for other uses.
To begin a detailed description of an example cascade LNG facility 100 in accordance with the implementations described herein, reference is made to FIG. 3. The LNG facility 100 generally comprises a first refrigeration cycle 30 (e.g., a propane refrigeration cycle), aa second refrigeration cycle 50 (e.g., an ethylene refrigeration cycle), and a third refrigeration cycle 70 (e.g., a methane refrigeration cycle) with an expansion section 80.
In one implementation, the main components of propane refrigeration cycle 30 include a propane compressor 31, a propane cooler/condenser 32, high-stage propane chillers 33A and 33B, an intermediate-stage propane chiller 34, and a low-stage propane chiller 35. The main components of ethylene refrigeration cycle 50 include an ethylene compressor 51, an ethylene cooler 52, a high-stage ethylene chiller 53, a low-stage ethylene chiller/condenser 55, and an ethylene economizer 56. The main components of methane refrigeration cycle 70 include a methane compressor 71, a methane cooler 72, and a methane economizer 73. The main components of expansion section 80 include a high-stage methane expansion valve and/or expander 81, a high-stage methane flash drum 82, an intermediate-stage methane expansion valve and/or expander 83, an intermediate-stage methane flash drum 84, a low-stage methane expansion valve and/or expander 85, and a low-stage methane flash drum 86. While “propane,” “ethylene,” and “methane” are used to refer to respective first, second, and third refrigerants, it should be understood that these are examples only, and the presently disclosed technology may involve any combination of suitable refrigerants.
Referring to FIG. 3, in one implementation, operation of the LNG facility 100 begins with the propane refrigeration cycle 30. Propane is compressed in a multi-stage (e.g., three-stage) propane compressor 31 driven by, for example, a gas turbine driver (not illustrated). The stages of compression may exist in a single unit or a plurality of separate units mechanically coupled to a single driver. Upon compression, the propane is passed through a conduit 300 to a propane cooler 32 where the propane is cooled and liquefied through indirect heat exchange with an external fluid (e.g., air or water). A portion of the stream from the propane cooler 32 can then be passed through conduits 302 and 302A to a pressure reduction system 36A, for example, an expansion valve, as illustrated in FIG. 3. At the pressure reduction system 36A, the pressure of the liquefied propane is reduced, thereby evaporating or flashing a portion of the liquefied propane. A resulting two-phase stream then flows through a conduit 304A into a high-stage propane chiller 33A, which cools the natural gas stream in indirect heat exchange 38. A high stage propane chiller 33A uses the flashed propane refrigerant to cool the incoming natural gas stream in a conduit 110. Another portion of the stream from the propane cooler 32 is routed through a conduit 302B to another pressure reduction system 36B, illustrated, for example, in FIG. 3 as an expansion valve. At the pressure reduction system 36B, the pressure of the liquefied propane is reduced in a stream 304B.
The cooled natural gas stream from the high-stage propane chiller 33A flows through a conduit 114 to a separation vessel. At the separation vessel, water and in some cases a portion of the propane and/or heavier components are removed. In some cases where removal is not completed in upstream processing, a treatment system 40 may follow the separation vessel. The treatment system 40 removes moisture, mercury and mercury compounds, particulates, and other contaminants to create a treated stream. The stream exits the treatment system 40 through a conduit 116. The stream 116 then enters the intermediate-stage propane chiller 34. At the intermediate-stage propane chiller 34, the stream is cooled in indirect heat exchange 41 via indirect heat exchange with a propane refrigerant stream. The resulting cooled stream output into a conduit 118 is routed to the low-stage propane chiller 35, where the stream can be further cooled through indirect heat exchange means 42. The resultant cooled stream exits the low-stage propane chiller 35 through a conduit 120. Subsequently, the cooled stream in the conduit 120 is routed to the high-stage ethylene chiller 53.
A vaporized propane refrigerant stream exiting the high-stage propane chillers 33A and 33B is returned to a high-stage inlet port of the propane compressor 31 through a conduit 306. An unvaporized propane refrigerant stream exits the high-stage propane chiller 33B via a conduit 308 and is flashed via a pressure reduction system 43, illustrated in FIG. 3 as an expansion valve, for example. The liquid propane refrigerant in the high-stage propane chiller 33A provides refrigeration duty for the natural gas stream. A two-phase refrigerant stream enters the intermediate-stage propane chiller 34 through a conduit 310, thereby providing coolant for the natural gas stream (in conduit 116) and the stream entering the intermediate-stage propane chiller 34 through a conduit 204. The vaporized portion of the propane refrigerant exits the intermediate-stage propane chiller 34 through a conduit 312 and enters an intermediate-stage inlet port of the propane compressor 31. The liquefied portion of the propane refrigerant exits the intermediate-stage propane chiller 34 through a conduit 314 and is passed through a pressure-reduction system 44, for example an expansion valve, whereupon the pressure of the liquefied propane refrigerant is reduced to flash or vaporize a portion of the liquefied propane. The resulting vapor-liquid refrigerant stream is routed to the low-stage propane chiller 35 through a conduit 316. At the low-stage propane chiller 35, the refrigerant stream cools the methane-rich stream and an ethylene refrigerant stream entering the low-stage propane chiller 35 through the conduits 118 and 206, respectively. The vaporized propane refrigerant stream exits the low-stage propane chiller 35 and is routed to a low-stage inlet port of the propane compressor 31 through a conduit 318. The vaporized propane refrigerant stream is compressed and recycled at the propane compressor 31 as previously described.
In one implementation, a stream of ethylene refrigerant in a conduit 202 enters the high-stage propane chiller 33B. At the high-stage propane chiller 33B, the ethylene stream is cooled through indirect heat exchange 39. The resulting cooled ethylene stream is routed in the conduit 204 from the high-stage propane chiller 33B to the intermediate-stage propane chiller 34. Upon entering the intermediate-stage propane chiller 34, the ethylene refrigerant stream may be further cooled through indirect heat exchange 45 in the intermediate-stage propane chiller 34. The resulting cooled ethylene stream exits the intermediate-stage propane chiller 34 and is routed through a conduit 206 to enter the low-stage propane chiller 35. In the low-stage propane chiller 35, the ethylene refrigerant stream is at least partially condensed, or condensed in its entirety, through indirect heat exchange 46. The resulting stream exits the low-stage propane chiller 35 through a conduit 208 and may be routed to a separation vessel 47. At the separation vessel 47, a vapor portion of the stream, if present, is removed through a conduit 210, while a liquid portion of the ethylene refrigerant stream exits the separator 47 through a conduit 212. The liquid portion of the ethylene refrigerant stream exiting the separator 47 may have a representative temperature and pressure of about −24° F. (≈−31° C.) and about 285 psig (≈1,965 kPa and 20 bar). However, other temperatures and pressures are contemplated.
Turning now to the ethylene refrigeration cycle 50 in the LNG facility 100, in one implementation, the liquefied ethylene refrigerant stream in the conduit 212 enters an ethylene economizer 56, and the stream is further cooled by an indirect heat exchange 57 at the ethylene economizer 56. The resulting cooled liquid ethylene stream is output into a conduit 214 and routed through a pressure reduction system 58, such as an expansion valve. The pressure reduction system 58 reduces the pressure of the cooled predominantly liquid ethylene stream to flash or vaporize a portion of the stream. The cooled, two-phase stream in a conduit 215 enters the high-stage ethylene chiller 53. In the high-stage ethylene chiller 53, at least a portion of the ethylene refrigerant stream vaporizes to further cool the stream in the conduit 120 entering an indirect heat exchange 59. The vaporized and remaining liquefied ethylene refrigerant exits the high-stage ethylene chiller 53 through conduits 216 and 220, respectively. The vaporized ethylene refrigerant in the conduit 216 may re-enter the ethylene economizer 56, and the ethylene economizer 56 warms the stream through an indirect heat exchange 60 prior to entering a high-stage inlet port of the ethylene compressor 51 through a conduit 218. Ethylene is compressed in multi-stages (e.g., three-stage) at the ethylene compressor 51 driven by, for example, a gas turbine driver (not illustrated). The stages of compression may exist in a single unit or a plurality of separate units mechanically coupled to a single driver.
The cooled stream in the conduit 120 exiting the low-stage propane chiller 35 is routed to the high-stage ethylene chiller 53, where it is cooled via the indirect heat exchange 59 of the high-stage ethylene chiller 53. The remaining liquefied ethylene refrigerant exiting the high-stage ethylene chiller 53 in a conduit 220 may re-enter the ethylene economizer 56 and undergo further sub-cooling by an indirect heat exchange 61 in the ethylene economizer 56. The resulting sub-cooled refrigerant stream exits the ethylene economizer 56 through a conduit 222 and passes a pressure reduction system 62, such as an expansion valve, whereupon the pressure of the refrigerant stream is reduced to vaporize or flash a portion of the refrigerant stream. The resulting, cooled two-phase stream in a conduit 224 enters the low-stage ethylene chiller/condenser 55.
A portion of the cooled natural gas stream exiting the high-stage ethylene chiller 53 is routed through conduit a 122 to enter an indirect heat exchange 63 of the low-stage ethylene chiller/condenser 55. In the low-stage ethylene chiller/condenser 55, the cooled stream is at least partially condensed and, often, subcooled through indirect heat exchange with the ethylene refrigerant entering the low-stage ethylene chiller/condenser 55 through the conduit 224. The vaporized ethylene refrigerant exits the low-stage ethylene chiller/condenser 55 through a conduit 226, which then enters the ethylene economizer 56. In the ethylene economizer 56, vaporized ethylene refrigerant stream is warmed through an indirect heat exchange 64 prior to being fed into a low-stage inlet port of the ethylene compressor 51 through a conduit 230. As shown in FIG. 3, a stream of compressed ethylene refrigerant exits the ethylene compressor 51 through a conduit 236 and subsequently enters the ethylene cooler 52. At the ethylene cooler 52, the compressed ethylene stream is cooled through indirect heat exchange with an external fluid (e.g., water or air). The resulting cooled ethylene stream may be introduced through the conduit 202 into high-stage propane chiller 33B for additional cooling, as previously described.
The condensed and, often, sub-cooled liquid natural gas stream exiting the low-stage ethylene chiller/condenser 55 in a conduit 124 can also be referred to as a “pressurized LNG-bearing stream.” This pressurized LNG-bearing stream exits the low-stage ethylene chiller/condenser 55 through the conduit 124 prior to entering a main methane economizer 73. In the main methane economizer 73, methane-rich stream in the conduit 124 may be further cooled in an indirect heat exchange 75 through indirect heat exchange with one or more methane refrigerant streams (e.g., 76, 77, 78). The cooled, pressurized LNG-bearing stream exits the main methane economizer 73 through a conduit 134 and is routed to the expansion section 80 of the methane refrigeration cycle 70. In the expansion section 80, the pressurized LNG-bearing stream first passes through a high-stage methane expansion valve or expander 81, whereupon the pressure of this stream is reduced to vaporize or flash a portion thereof. The resulting two-phase methane-rich stream in a conduit 136 enters into a high-stage methane flash drum 82. In the high-stage methane flash drum 82, the vapor and liquid portions of the reduced-pressure stream are separated. The vapor portion of the reduced-pressure stream (also called the high-stage flash gas) exits the high-stage methane flash drum 82 through a conduit 138 and enters into the main methane economizer 73. At the main methane economizer 73, at least a portion of the high-stage flash gas is heated through the indirect heat exchange means 76 of the main methane economizer 73. The resulting warmed vapor stream exits the main methane economizer 73 through the conduit 138 and is routed to a high-stage inlet port of the methane compressor 71, as shown in FIG. 3.
The liquid portion of the reduced-pressure stream exits the high-stage methane flash drum 82 through a conduit 142 and re-enters the main methane economizer 73. The main methane economizer 73 cools the liquid stream through indirect heat exchange 74 of the main methane economizer 73. The resulting cooled stream exits the main methane economizer 73 through a conduit 144 and is routed to a second expansion stage, illustrated in FIG. 3 as intermediate-stage expansion valve 83 and/or expander, as an example. The intermediate-stage expansion valve 83 further reduces the pressure of the cooled methane stream, which reduces a temperature of the stream by vaporizing or flashing a portion of the stream. The resulting two-phase methane-rich stream output in a conduit 146 enters an intermediate-stage methane flash drum 84. Liquid and vapor portions of the stream are separated in the intermediate-stage flash drum 84 and output through conduits 148 and 150, respectively. The vapor portion (also called the intermediate-stage flash gas) in the conduit 150 re-enters the methane economizer 73, wherein the vapor portion is heated through an indirect heat exchange 77 of the main methane economizer 73. The resulting warmed stream is routed through a conduit 154 to the intermediate-stage inlet port of methane compressor 71.
The liquid stream exiting the intermediate-stage methane flash drum 84 through the conduit 148 passes through a low-stage expansion valve 85 and/or expander, whereupon the pressure of the liquefied methane-rich stream is further reduced to vaporize or flash a portion of the stream. The resulting cooled two-phase stream is output in a conduit 156 and enters a low-stage methane flash drum 86, which separates the vapor and liquid phases. The liquid stream exiting the low-stage methane flash drum 86 through a conduit 158 comprises the liquefied natural gas (LNG) product at near atmospheric pressure. This LNG product may be routed downstream for subsequent storage, transportation, and/or use.
A vapor stream exiting the low-stage methane flash drum 86 (also called the low-stage methane flash gas) in a conduit 160 is routed to the methane economizer 73. The methane economizer 73 warms the low-stage methane flash gas through an indirect heat exchange 78 of the main methane economizer 73. The resulting stream exits the methane economizer 73 through a conduit 164. The stream is then routed to a low-stage inlet port of the methane compressor 71.
The methane compressor 71 comprises one or more compression stages. In one implementation, the methane compressor 71 comprises three compression stages in a single module. In another implementation, one or more of the compression modules are separate but mechanically coupled to a common driver. Generally, one or more intercoolers (not shown) are provided between subsequent compression stages.
As shown in FIG. 3, a compressed methane refrigerant stream exiting the methane compressor 71 is discharged into a conduit 166. The compressed methane refrigerant is routed to the methane cooler 72, and the stream is cooled through indirect heat exchange with an external fluid (e.g., air or water) in the methane cooler 72. The resulting cooled methane refrigerant stream exits the methane cooler 72 through a conduit 112 and is directed to and further cooled in the propane refrigeration cycle 30. Upon cooling in the propane refrigeration cycle 30 through a heat exchanger 37, the methane refrigerant stream is discharged into s conduit 130 and subsequently routed to the main methane economizer 73, and the stream is further cooled through indirect heat exchange 79. The resulting sub-cooled stream exits the main methane economizer 73 through a conduit 168 and then combined with the stream in the conduit 122 exiting the high-stage ethylene chiller 53 prior to entering the low-stage ethylene chiller/condenser 55, as previously discussed.
The heavies removal unit is relatively simple and easy to operate. It is able to handle a wide range of feed compositions with minimal operator interaction. The unit is also able to operate with minimal, if any, flaring. Those skilled in the art will recognize that FIGS. 2 & 3 are schematics only and, therefore, various equipment, apparatuses, or systems that would be needed in a commercial plant for successful operation have been omitted for clarity. Such components might include, for example, compressor controls, flow and level measurements and corresponding controllers, temperature and pressure controls, pumps, motors, filters, additional heat exchangers, valves, and/or the like. Those skilled in the art will recognize such components and how they are integrated into the systems and methods disclosed herein.
In closing, it should be noted that the discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. At the same time, each and every claim below is hereby incorporated into this detailed description or specification as a additional embodiments of the present invention.
Although the systems and processes described herein have been described in detail, it should be understood that various changes, substitutions, and alterations can be made without departing from the spirit and scope of the invention as defined by the following claims. Those skilled in the art may be able to study the preferred embodiments and identify other ways to practice the invention that are not exactly as described herein. It is the intent of the inventors that variations and equivalents of the invention are within the scope of the claims while the description, abstract and drawings are not to be used to limit the scope of the invention. The invention is specifically intended to be as broad as the claims below and their equivalents.

Claims

1. A method for processing natural gas in an LNG facility comprising:

introducing a natural gas feed to a heavies removal unit, wherein the heavies removal system includes a heavies removal column and a distillation column, wherein the heavies removal column and the distillation column are fluidly connected; and

purging one or more components of the natural gas feed from the heavies removal column to a methane recycle stream via the purge/recovery line to obtain a specified concentration or concentration range of heavy components feeding into the distillation column.

2. The method of claim 1, wherein the distillation column is a high pressure demethanizer.

3. The method of claim 1, further comprising:

adjusting rate of the purging based in order to adjust flow rate to the distillation column.

4. The method of claim 1, wherein the LNG facility is configured for a cascade liquefaction process.

5. The method of claim 1, wherein the heavies removal column is downstream of the distillation column.

6. The method of claim 1, wherein the purging removes hydrocarbons having 6 or more carbons.

7. A method for processing natural gas feed during natural gas liquefaction comprising:

introducing the natural gas feed into a heavies removal unit, wherein the heavies removal system includes a heavies removal column and a demethanizer, wherein the heavies removal column and the demethanizer are fluidly connected and wherein the heavies removal column is downstream of the demethanizer;

determining composition of the natural gas feed before it is introduced into the demethanizer; and

purging one or more heavy components of the natural gas feed from the heavies removal column to a methane recycle stream via the purge/recovery line to reduce or increase concentration of heavy components feeding into the demethanizer.

8. The method of claim 7, further comprising:

adjusting rate of the purging in order to adjust flow rate to the distillation column.

9. The method of claim 7, wherein the natural gas liquefaction is a cascade liquefaction process.

10. The method of claim 7, wherein at least three pure refrigerants are used in the cascade liquefaction process.

11. The method of claim 10, wherein the pure refrigerants include methane, ethane, ethylene, propane, or propylene.

12. The method of claim 7, wherein the heavy components comprise carbon molecules having 6 or more carbon atoms.