MIXED-REFLUX FOR HEAVIES REMOVAL IN LNG PROCESSING

FIELD OF THE INVENTION

The present invention relates generally to methods for liquefying natural gas. More particularly, but not by way of limitation, embodiments of the present invention include systems and methods for removing heavy hydrocarbons from natural gas using mixed-refluxed heavy removal columns.

BACKGROUND OF THE INVENTION

Natural gas is an important resource widely used as energy source or as industrial feedstock used in, for example, manufacture of plastics. Comprising primarily of methane, natural gas is a mixture of naturally occurring hydrocarbon gases and is typically found in deep underground natural rock formations or other hydrocarbon reservoirs. Exact composition of natural gas may vary from source to source. Typically, natural gas is transported from source to consumers through pipelines that physically connect a reservoir to a market. Because natural gas is sometimes found in remote areas devoid of necessary infrastructure (i.e., pipelines), alternative methods for transporting natural gas must be used. This situation commonly arises when the source of natural gas and the market are separated by great distances, for example a large body of water. Bringing this natural gas from remote areas to market can have significant commercial value if the cost of transporting natural gas is minimized.

One alternative method of transporting natural gas involves converting natural gas into a liquefied form through a liquefaction process. In its liquefied form, natural gas has a specific volume that is significantly lower than its specific volume in its gaseous form. Thus, the liquefaction process greatly increases the ease of transporting and storing natural gas, particularly in cases where pipelines are not available. For example, ocean liners carrying LNG tanks can effectively link a natural gas source with a distant market when the source and market are separated by large bodies of water. Converting natural gas to its liquefied form can have other economic benefits. For example, storing LNG can help balance out periodic fluctuations in natural gas supply and demand. In particular, LNG can be more easily “stockpiled” for later use when natural gas demand is low and/or supply is high. As a result, future demand peaks can be met with LNG from storage, which can be vaporized as demand requires.

Several methods exist for liquefying natural gas. Some methods produce a pressurized LNG (PLNG) product that is useful, but requires expensive pressure-containing vessels for storage and transportation. Other methods produce an LNG product having a pressure at or near atmospheric pressure. In general, these non-pressurized LNG production methods involve cooling a natural gas stream through indirect heat exchange with one or more refrigerants and then expanding the cooled natural gas stream to near atmospheric pressure. In addition, most LNG facilities employ one or more systems to remove contaminants (e.g., water, mercury and mercury components, acid gases, and nitrogen, as well as a portion of ethane and heavier components) from the natural gas stream at different points during the liquefaction process.

In order to store and transport natural gas in the liquid state, the natural gas is typically cooled to −240° F. to −260° F. at near-atmospheric vapor pressure. Liquefaction of natural gas can be achieved by sequentially passing the natural gas at an elevated pressure through a plurality of cooling stages whereupon the gas is cooled to successively lower temperatures until liquefaction temperature is reached. Cooling is generally accomplished by indirect heat exchange with one or more refrigerants such as propane, propylene, ethane, ethylene, methane, nitrogen, carbon dioxide, or combinations of the preceding refrigerants (e.g., mixed refrigerant systems).

Natural gas is primarily comprised of methane, but may also include small amounts of heavy hydrocarbon components. In some cases, the heavy hydrocarbon components may be utilized as natural gas liquid (“NGL”) that includes components such as, but not limited to, ethane, propane, normal butane and iso-butane. Heavier heavy hydrocarbon components will often require at least partial removal as they freeze in LNG streams if present in sufficiently high concentrations. Examples of heavier heavy hydrocarbon components may include, but are not limited to, benzene, cyclohexane, toluene, ethylbenzene, xylene isomers, and certain isomers of: pentane, hexane, heptane, octane, nonane, and decane, and the like.

Some conventional LNG facilities employ a refluxed heavies removal column in order to enhance heavies removal as compared to facilities employing non-refluxed heavies removal column. In general, hydrocarbon reflux must meet appropriate quality and quantity standards to achieve effective and efficient removal of heavy hydrocarbons. At least one cascade liquefaction process utilizes a debutanizer to provide reflux to the heavies removal column. Thus, “lean” natural gases sources lacking adequate amounts of C2-C4 hydrocarbons may not be compatible with certain cascade liquefaction processes requiring a refluxed heavies removal column because of difficulty of 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.

BRIEF SUMMARY OF THE DISCLOSURE

One example of a method for liquefying a natural gas stream comprises: (a) cooling at least a portion of the natural gas stream in an upstream refrigeration cycle of a liquefaction process to produce a cooled natural gas stream; (b) separating via a first distillation column the cooled natural gas stream into a first top fraction and a first bottom fraction, wherein the first distillation column is a heavies removal column and the top fraction does not freeze in a subsequent downstream step of the liquefaction process; (c) separating via a second distillation column the first bottom fraction into a second top fraction and a second bottom fraction; (d) separating via a third distillation column the second bottom fraction into a third top fraction and a third bottom fraction; (e) combining at least a portion of the second top fraction and a portion of the third top fraction to form a mixed-reflux stream; and (f) introducing the mixed-reflux stream into the first distillation column.

Another example of a method for liquefying a natural gas stream comprises: (a) cooling at least a portion of the natural gas stream in an upstream refrigeration cycle of a liquefaction process to produce a cooled natural gas stream; (b) separating via a first distillation column the cooled natural gas stream into a first top fraction and a first bottom fraction, wherein the first fraction does not freeze in a subsequent downstream step of the liquefaction process; (c) separating via a second distillation column the first bottom fraction into a second top fraction and a second bottom fraction, wherein the second top fraction at least a portion of a reflux stream; (d) optionally separating via a third distillation column the second bottom fraction into a third top fraction and a third bottom fraction, wherein the third top fraction forms a portion of the reflux stream; and (e) introducing the reflux stream into the first distillation column.

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:

FIG. 1 is a simplified flow diagram of a cascade refrigeration process for LNG production compatible with a mixed-reflux heavies removal system according to one or more embodiments.

FIG. 2 is a flow diagram of one aspect of the mixed-reflux heavies removal system compatible with the cascade refrigeration process shown FIG. 1.

DETAILED DESCRIPTION

Reference will now be made in detail to embodiments of the invention, one or more examples of which are illustrated in the accompanying drawings. Each example is provided by way of explanation of the invention, not as a limitation of the invention. It will be apparent to those skilled in the art that various modifications and variations can be made in the present invention without departing from the scope or spirit of the invention. For instance, features illustrated or described as part of one embodiment can be used on another embodiment to yield a still further embodiment. Thus, it is intended that the present invention cover such modifications and variations that come within the scope of the invention.

The present invention provides systems and methods related to heavy hydrocarbon removal during liquefaction of natural gas (“LNG process”). According to one or more embodiments, the present invention processes lean natural gas by generating a mixed-reflux stream for a heavies removal column. As used herein, “lean natural gas” is a natural gas comprising relatively low concentrations of C2-C4 components. For example, a natural gas stream may be considered lean if its concentration of C2-C4 is too low to provide sufficient reflux in some conventional reflux heavies removal columns. As used herein, a “mixed-reflux” is a process stream combined from multiple downstream locations which may be particularly useful, for example, when a reflux stream from a single downstream location does not meet certain desirable characteristics. These characteristics may include, but are not limited to, sufficient flow rates, suitable composition (due to the overall leanness of the feed natural gas), and the like. In some embodiments, the mixed-reflux may be obtained from a combination of overhead streams from downstream elements (e.g., debutanizer, condensate stabilizer, etc.). Moreover, feed streams to both the debutanizer and the condensate stabilizer may be originally sourced in a product stream from the heavies removal column itself.

The heavies removal system according to one or more embodiments integrates external heat and refrigerant sources contained within an LNG or gas plant to enhance thermal and separation efficiency as well as overall operating flexibility and stability. This design also allows independent adjustment of refrigerant and heat sources, which in turn, allows adjustments for wider variations in feed composition and promotes greater turn down capacity. Moreover, as compared to many conventional systems and methods, advantages of certain embodiments of liquefying natural gas methods and systems described herein include, but are not limited to, one or more of the following:

- may be implemented into existing LNG liquefaction processes and facilities without significant departure from known and/or previously-approved process designs or equipment design criteria for heavies removal,
- provides sufficient quantity of reflux of appropriate composition to heavies removal columns when lean feed gases are fed,
- extends operable range of heavies removal column to broader range of feed gas compositions of commercial interest.
  
  Other advantages will be apparent from the disclosure herein.

The present invention can be implemented in a facility used to cool natural gas to its liquefaction temperature to produce liquefied natural gas (LNG). The LNG facility generally employs one or more refrigerants to extract heat from the natural gas and reject to the environment. Numerous configurations of LNG systems exist and the present invention may be implemented in many different types of LNG systems.

In one embodiment, the present invention may be implemented in a mixed refrigerant LNG system. Examples of mixed refrigerant processes can include, but are not limited to, a single refrigeration system using a mixed refrigerant, a propane pre-cooled mixed refrigerant system, and a dual mixed refrigerant system.

In another embodiment, the present invention may be implemented in a cascade LNG system employing a cascade-type refrigeration process using one or more predominately pure component refrigerants. The refrigerants utilized in cascade-type refrigeration processes can have successively lower boiling points in order to facilitate heat removal from the natural gas stream being liquefied. Additionally, cascade-type refrigeration processes can include some level of heat integration. For example, a cascade-type refrigeration process can cool one or more refrigerants having a higher volatility through indirect heat exchange with one or more refrigerants having a lower volatility. In addition to cooling the natural gas stream through indirect heat exchange with one or more refrigerants, cascade and mixed-refrigerant LNG systems can employ one or more expansion cooling stages to simultaneously cool the LNG while reducing its pressure.

Cascade LNG Process

In one embodiment, 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 consider 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 3 different refrigerants in 3 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 embodiments of the present invention. Other variations to the cascade LNG process may also be contemplated. In another embodiment, the mixed-reflux heavies removal system of the present invention 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.

Referring first to FIG. 1, an example cascade LNG facility in accordance with the concept described herein is illustrated. The LNG facility depicted in FIG. 1 generally comprises a propane refrigeration cycle 30, an ethylene refrigeration cycle 50, and a methane refrigeration cycle 70 with an expansion section 80. FIG. 2 illustrates an embodiment of mixed-reflux heavies removal system capable of being integrated into the LNG facility depicted in FIG. 1 through conduits A-I. Those skilled in the art will recognize that FIGS. 1-2 are schematics only and, therefore, many items of equipment that would be needed in a commercial plant for successful operation have been omitted for sake of clarity. Such items 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 the like. These items would be provided in accordance with standard engineering practice.

While “propane,” “ethylene,” and “methane” are used to refer to respective first, second, and third refrigerants, it should be understood that the embodiment illustrated in FIG. 1 and described herein can apply to any combination of suitable refrigerants. 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.

The operation of the LNG facility illustrated in FIG. 1 will now be described in more detail, beginning with propane refrigeration cycle 30. Propane is compressed in 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 two or more separate units mechanically coupled to a single driver. Upon compression, the propane is passed through conduit 300 to propane cooler 32 where it is cooled and liquefied through indirect heat exchange with an external fluid (e.g., air or water). A portion of the stream from propane cooler 32 can then be passed through conduits 302 and 302A to a pressure reduction means, illustrated as expansion valve 36A, wherein the pressure of the liquefied propane is reduced, thereby evaporating or flashing a portion thereof. The resulting two-phase stream then flows through conduit 304a into high-stage propane chiller 33A where it can cool the natural gas stream 110 in indirect heat exchange means 38. High stage propane chiller 33A uses the flashed propane refrigerant to cool the incoming natural gas stream in conduit 110. Another portion of the stream from propane cooler 32 is routed through conduit 302B to another pressure reduction means, illustrated as expansion valve 36B, wherein the pressure of the liquefied propane is reduced in stream 304B.

The cooled natural gas stream from high-stage propane chiller 33A flows through conduit 114 to a separaion vessel, wherein water and in some cases a portion of propane and/or heavier components are removed, typically followed by a treatment system 40, in cases where not already completed in upstream processing, wherein moisture, mercury and mercury compounds, particulates, and other contaminants are removed to create a treated stream. The stream exits the treatment system 40 through conduit 116. Thereafter, a portion of the stream in conduit 116 can be routed through conduit A to a mixed-reflux heavies removal system illustrated in FIG. 2, which will be discussed in detail shortly. The stream 116 then enters intermediate-stage propane chiller 34, wherein the stream is cooled in indirect heat exchange means 41 through indirect heat exchange with a propane refrigerant stream. The resulting cooled stream in conduit 118 can then be recombined with a stream in conduit B exiting mixed-reflux heavies removal system illustrated in FIG. 2, and the combined stream can then be routed to low-stage propane chiller 35, wherein the stream can be further cooled through indirect heat exchange means 42. The resultant cooled stream can then exit low-stage propane chiller 35 through conduit 120. Subsequently, the cooled stream in conduit 120 can be routed to high-stage ethylene chiller 53.

A vaporized propane refrigerant stream exiting high-stage propane chillers 33A and 33B is returned to the high-stage inlet port of propane compressor 31 through conduit 306. An unvaporized propane refrigerant stream exits the high-stage propane chiller 33B via conduit 308 and is flashed via a pressure reduction means, illustrated here in FIG. 1 as expansion valve 43. The liquid propane refrigerant in high-stage propane chiller 33A provides refrigeration duty for the natural gas stream 110. Two-phase refrigerant stream can enter the intermediate-stage propane chiller 34 through conduit 310, thereby providing coolant for the natural gas stream (in conduit 116) and stream entering intermediate-stage propane chiller 34 through conduit 204. The vaporized portion of the propane refrigerant exits intermediate-stage propane chiller 34 through conduit 312 and enters the intermediate-stage inlet port of propane compressor 31. The liquefied portion of the propane refrigerant exits intermediate-stage propane chiller 34 through conduit 314 and is passed through a pressure-reduction means, illustrated here as expansion valve 44, whereupon the pressure of the liquefied propane refrigerant is reduced to flash or vaporize a portion thereof. The resulting vapor-liquid refrigerant stream can then be routed to low-stage propane chiller 35 through conduit 316 and where the refrigerant stream can cool the methane-rich stream and an ethylene refrigerant stream entering low-stage propane chiller 35 through conduits 118 and 206, respectively. The vaporized propane refrigerant stream then exits low-stage propane chiller 35 and is routed to the low-stage inlet port of propane compressor 31 through conduit 318 wherein it is compressed and recycled as previously described.

Still referring to FIG. 1, a stream of ethylene refrigerant in conduit 202 enters high-stage propane chiller 33B, wherein the ethylene stream is cooled through indirect heat exchange means 39. The resulting cooled ethylene stream can then be routed in conduit 204 from high-stage propane chiller 33B to intermediate-stage propane chiller 34. Upon entering intermediate-stage propane chiller 34, the ethylene refrigerant stream can be further cooled through indirect heat exchange means 45 in intermediate-stage propane chiller 34. The resulting cooled ethylene stream can then exit intermediate-stage propane chiller 34 and can be routed through conduit 206 to enter low-stage propane chiller 35. In low-stage propane chiller 35, the ethylene refrigerant stream can be at least partially condensed, or condensed in its entirety, through indirect heat exchange means 46. The resulting stream exits low-stage propane chiller 35 through conduit 208 and can subsequently be routed to a separation vessel 47, wherein a vapor portion of the stream, if present, can be removed through conduit 210, while a liquid portion of the ethylene refrigerant stream can exit separator 47 through conduit 212. The liquid portion of the ethylene refrigerant stream exiting separator 47 can have a representative temperature and pressure of about −24° F. (about −31° C.) and about 285 psia (about 1,965 kPa).

Turning now to the ethylene refrigeration cycle 50 in FIG. 1, liquefied ethylene refrigerant stream in conduit 212 can enter an ethylene economizer 56, wherein the stream can be further cooled by an indirect heat exchange means 57. The resulting cooled liquid ethylene stream in conduit 214 can then be routed through a pressure reduction means, illustrated here as expansion valve 58, whereupon the pressure of the cooled predominantly liquid ethylene stream is reduced to thereby flash or vaporize a portion thereof. The cooled, two-phase stream in conduit 215 can then enter high-stage ethylene chiller 53. In high-stage ethylene chiller 53, at least a portion of the ethylene refrigerant stream can vaporize to further cool the stream in conduit 121 entering an indirect heat exchange means 59. The vaporized and remaining liquefied ethylene refrigerant exits high-stage ethylene chiller 53 through conduits 216 and 220, respectively. The vaporized ethylene refrigerant in conduit 216 can re-enter ethylene economizer 56, wherein the stream can be warmed through an indirect heat exchange means 60 prior to entering the high-stage inlet port of ethylene compressor 51 through conduit 218. Ethylene is compressed in multi-stage (e.g., three-stage) ethylene compressor 51 driven by, for example, a gas turbine driver (not illustrated). The stages of compression may exist in a single unit or two or more separate units mechanically coupled to a single driver.

The cooled stream in conduit 120 exiting low-stage propane chiller 35 can thereafter be split into two portions, as shown in FIG. 1. At least a portion of the cooled natural gas stream can be routed through conduit E while a remaining portion of the cooled natural gas stream in conduit 121 can be routed to high-stage ethylene chiller 53, where it is cooled via indirect heat exchange means 59 of high-stage ethylene chiller 53. The cooled natural gas stream in conduit E may be routed to a mixed-reflux heavies removal system according to one or more embodiments (see FIG. 2) where the stream is flashed through a pressure reduction means, illustrated here as expansion valve 612, before it is fed into heavies removal column 610 (described in more detail later).

The remaining liquefied ethylene refrigerant exiting high-stage ethylene chiller 53 in conduit 220 can re-enter ethylene economizer 56 and undergo further sub-cooling by an indirect heat exchange means 61 in ethylene economizer 56. The resulting sub-cooled refrigerant stream exits ethylene economizer 56 through conduit 222 and subsequently passes a pressure reduction means, illustrated here as expansion valve 62, whereupon the pressure of the refrigerant stream is reduced to vaporize or flash a portion thereof. The resulting, cooled two-phase stream in conduit 224 enters low-stage ethylene chiller/condenser 55.

A portion of the cooled natural gas stream exiting high-stage ethylene chiller 53 can be routed through conduit C to the mixed-reflux heavies removal system in FIG. 2, while another portion of the cooled natural gas stream exiting high-stage ethylene chiller 53 can be routed through conduit 122 to enter indirect heat exchange means 63 of low-stage ethylene chiller/condenser 55. The cooled natural gas stream in conduit C may be routed to a mixed-reflux heavies removal system according to one or more embodiments (See FIG. 2) where the stream is flashed through a pressure reduction means, illustrated here as expansion valve 613, before combining with the stream in conduit E. The portion of the cooled natural gas stream in conduit 122 can then be combined the first column vapor stream exiting the mixed-reflux heavies removal system in conduit D and/or may be combined with a stream exiting methane refrigeration cycle 70 in conduit 168. The resulting composite stream can then enter indirect heat exchange means 63 in low-stage ethylene chiller/condenser 55.

In the low-stage ethylene chiller/condenser 55, cooled stream (which can include stream in conduit 122 and optionally streams in conduits D and 168) can be at least partially condensed and, often, subcooled through indirect heat exchange with the ethylene refrigerant entering low-stage ethylene chiller/condenser 55 through conduit 224. The vaporized ethylene refrigerant exits low-stage ethylene chiller/condenser 55 through conduit 226, which then enters ethylene economizer 56. In the ethylene economizer 56, vaporized ethylene refrigerant stream 226 can be warmed through an indirect heat exchange means 64 prior to being fed into the low-stage inlet port of ethylene compressor 51 through conduit 230. As shown in FIG. 1, a stream of compressed ethylene refrigerant exits ethylene compressor 51 through conduit 236 and subsequently enters ethylene cooler 52, wherein the compressed ethylene stream can be cooled through indirect heat exchange with an external fluid (e.g., water or air). The resulting cooled ethylene stream is introduced through conduit 202 into high-stage propane chiller 33B for additional cooling as previously described.

The condensed and, often, subcooled liquid natural gas stream exiting low-stage ethylene chiller/condenser 55 in conduit 124 can also be referred to as a “pressurized LNG-bearing stream.” This pressurized LNG-bearing stream exits low-stage ethylene chiller/condenser 55 through conduit 124 prior to entering main methane economizer 73. In the main methane economizer 73, methane-rich stream in conduit 124 can be further cooled in an indirect heat exchange means 75 through indirect heat exchange with one or more methane refrigerant streams (e.g., 76, 77, 78). The cooled, pressurized LNG-bearing stream exits main methane economizer 73 through conduit 134 and routes to expansion section 80 of methane refrigeration cycle 70. In the expansion section 80, the pressurized LNG-bearing stream first passes through 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 conduit 136 can then enter into high-stage methane flash drum 82, whereupon the vapor and liquid portions of the reduced-pressure stream can be separated. The vapor portion of the reduced-pressure stream (also called the high-stage flash gas) exits high-stage methane flash drum 82 through conduit 138 to then enter into main methane economizer 73, wherein at least a portion of the high-stage flash gas can be heated through indirect heat exchange means 76 of main methane economizer 73. The resulting warmed vapor stream exits main methane economizer 73 through conduit 138 and is then routed to the high-stage inlet port of methane compressor 71, as shown in FIG. 1.

The liquid portion of the reduced-pressure stream exits high-stage methane flash drum 82 through conduit 142 to then re-enter main methane economizer 73, wherein the liquid stream can be cooled through indirect heat exchange means 74 of main methane economizer 73. The resulting cooled stream exits main methane economizer 73 through conduit 144 and then routed to a second expansion stage, illustrated here as intermediate-stage expansion valve 83 and/or expander. Intermediate-stage expansion valve 83 further reduces the pressure of the cooled methane stream which reduces the stream's temperature by vaporizing or flashing a portion thereof. The resulting two-phase methane-rich stream in conduit 146 can then enter intermediate-stage methane flash drum 84, wherein the liquid and vapor portions of this stream can be separated and exits the intermediate-stage flash drum 84 through conduits 148 and 150, respectively. The vapor portion (also called the intermediate-stage flash gas) in conduit 150 can re-enter methane economizer 73, wherein the vapor portion can be heated through an indirect heat exchange means 77 of main methane economizer 73. The resulting warmed stream can then be routed through conduit 154 to the intermediate-stage inlet port of methane compressor 71, as shown in FIG. 1.

The liquid stream exiting intermediate-stage methane flash drum 84 through conduit 148 can then pass through a low-stage expansion valve 85 and/or expander, whereupon the pressure of the liquefied methane-rich stream can be further reduced to vaporize or flash a portion thereof. The resulting cooled, two-phase stream in conduit 156 can then enter low-stage methane flash drum 86, wherein the vapor and liquid phases are separated. The liquid stream exiting low-stage methane flash drum 86 through conduit 158 can comprise the liquefied natural gas (LNG) product at near atmospheric pressure. This LNG product can be routed downstream for subsequent storage, transportation, and/or use.

A vapor stream exiting low-stage methane flash drum (also called the low-stage methane flash gas) in conduit 160 can be routed to methane economizer 73, wherein the low-stage methane flash gas can be warmed through an indirect heat exchange means 78 of main methane economizer 73. The resulting stream can exit methane economizer 73 through conduit 164, whereafter the stream can be routed to the low-stage inlet port of methane compressor 71.

The methane compressor 71 can comprise one or more compression stages. In one embodiment, methane compressor 71 comprises three compression stages in a single module. In another embodiment, one or more of the compression modules can be separate but mechanically coupled to a common driver. Generally, one or more intercoolers (not shown) can be provided between subsequent compression stages.

As shown in FIG. 1, a compressed methane refrigerant stream exiting methane compressor 71 can be discharged into conduit 166. A portion of the compressed methane refrigerant stream exiting compressor 71 through conduit 166 can be routed through conduit F to the mixed-reflux heavies removal system in FIG. 2, while another portion of the compressed methane refrigerant can be routed to methane cooler 72, whereafter the stream can be cooled through indirect heat exchange with an external fluid (e.g., air or water) in methane cooler 72. The resulting cooled methane refrigerant stream exits methane cooler 72 through conduit 112, wherein a portion of the methane refrigerant can be routed through conduit H to the mixed-reflux heavies removal system in FIG. 2, while the remaining portion of the methane refrigerant stream can be directed to and further cooled in propane refrigeration cycle 30.

Upon cooling in the propane refrigeration cycle 30 through heat exchanger means 37, the methane refrigerant stream can be discharged into conduit 130 where it may be combined with methane-rich gas in conduit G from the mixed-reflux heavies removal system and subsequently routed to main methane economizer 73, wherein the stream can be further cooled through indirect heat exchange means 79. The resulting sub-cooled stream exits main methane economizer 73 through conduit 168 and then combined with stream in conduit 122 exiting high-stage ethylene chiller 53 and/or with stream in conduit D prior to entering low-stage ethylene chiller/condenser 55, as previously discussed.

The liquefaction process described herein may incorporate one of several types of cooling means including, but not limited to, (a) indirect heat exchange, (b) vaporization, and (c) expansion or pressure reduction. Indirect heat exchange, as used herein, refers to a process wherein a cooler stream cools the substance to be cooled without actual physical contact between the cooler stream and the substance to be cooled. Specific examples of indirect heat exchange means include 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.

Vaporization cooling refers to the cooling of a substance by evaporation or vaporization of a portion of the substance at a constant pressure. During vaporization, portion of the substance which evaporates absorbs heat from portion of the substance which remains in a liquid state and hence, cools the liquid portion. Finally, 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 embodiments, expansion means may be a Joule-Thomson expansion valve. In other embodiments, 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.

Mixed-Reflux Heavies Removal Column

Referring to FIG. 2, an example of mixed-reflux heavies removal system in accordance with the concepts described herein is illustrated. Some of the main distillation columns of the mixed-reflux heavies removal system include heavies removal column 610, nominal debutanizer 620, and condensate stabilizer 630. Other components of the mixed-reflux heavies removal system may include heavies removal column reboiler 606, debutanizer reboiler 625, stabilizer feed drum 640, stabilizer reboiler 637, mixed reflux drum 650, valves and/or expanders (e.g., 612, 613), pumps (e.g., 629, 677, 691, 692), various conduits (described in more detail later), and the like.

At least a portion of the natural gas stream withdrawn from conduit 116 in FIG. 1 can be routed to the mixed-reflux heavies removal system depicted in FIG. 2 through conduit A. Referring to FIG. 2, the natural gas stream in conduit A enters the warm fluid inlet of reboiler 606 to form a heating pass 607 and provide reboiler heat duty to the heavies removal column 610. Alternatively, some embodiments may utilize other known methods, such as a thermosyphon reboiler or direct heat through a stripping gas or heating gas introduced directly to the heavies removal column, to provide heat duty for the heavies removal column 610. One or more kettle, thermosyphon or pump around exchangers may be provided for the heavies removal column exchangers as well as one or more heating or stripping gas streams. Consequently, the reboiler 606 can produce heated vapor fraction in conduit 608A, heated liquid fraction in conduit 608B, and cooled and/or partially condensed natural gas stream (conduit B). Alternatively, some embodiments may utilize other known methods to provide for boilup vapor to the heavies removal column 610. The use of natural gas in conduit A as heating medium as described herein is one of a number of possible embodiments. The heavies removal column 610 contains a chimney or trap-out tray wherein lighter composition streams are directed to the upper regions of the distillation column while heavier composition streams are routed to the lower portions of the distillation column. The reboiler 606 supplies heat by a controlled slip stream of warm upstream feed gas (conduit A). This flow of warm feed gas is adjusted by a temperature controller on the reboiler heating inlet stream (conduit A). Once cooled and/or partially condensed, a portion of the natural gas stream is withdrawn from the warm side outlet of the reboiler 606 and routed back into the main liquefaction process (i.e., process illustrated in FIG. 1) through conduit B. A reboiler inlet stream exits the heavies removal column 610 at the chimney or trap-out tray and is routed through conduit 614 to the reboiler 606. A liquid bottoms product stream (or “liquid bottom stream”) in conduit 601 exits the heavies removal column 610. The liquid bottom stream is subjected to a pressure reduction means, illustrated here as expansion valve 699, to form a flashed or expanded two-phase stream 601A.

As shown in FIG. 1, a portion of a methane-rich stream exiting a high stage methane compressor through conduit 166 can be withdrawn through conduit F or H and routed to the mixed-reflux heavies removal system depicted in FIG. 2. In some embodiments, a portion of the methane-rich stream in conduit F or H may be a methane compressor discharge stream. As shown in FIG. 2, the methane-rich stream in conduit F or H can enter the warm fluid inlet of a cooling pass 605 of preheater 615 to provide heat duty to the preheater 615. The methane-rich stream in conduit F or H and the flashed or expanded two phase stream 601A undergo indirect heat exchange to produce a cooled portion of the methane-rich stream and a heated liquid stream in conduit 602. The resulting cooled portion of the methane-rich stream can be routed back to the main liquefaction process through conduit G to various possible destinations, such as stream 130, depending on the temperature and pressure of the gas in conduit G. The heated stream exiting preheater 615 is introduced as feed to the nominal debutanizer 620.

In the illustrated embodiment, a debutanizer overhead stream in conduit 603 provides nominal C4− recovery while a debutanizer bottom stream 604 provides nominal C5+ rejection. A portion of the C4− stream returns as part of the mixed-reflux to the heavies removal column 610. A non-condensed vapor portion of the C4− eventually returns to an appropriate compressor stage inlet of the methane compression loop of the main liquefaction process via conduit I. Alternatively, the stream in conduit I may be routed to fuel (not illustrated). The C5+ stream in conduit 604 is eventually removed from mixed-reflux heavies removal system as a byproduct condensate stream (conduit J).

Still referring to FIG. 2, prior to reaching mixed reflux drum 650, the debutanizer overhead vapor stream in conduit 603 is routed to a partial condenser 660, wherein the vapor is partially condensed (with air or water cooling). The partially-condensed stream in conduit 616 flows from partial condenser 660 to debutanizer reflux drum 628 from which liquid reflux is returned to the debutanizer in conduit 662 using reflux pump 629. Vapor from debutanizer reflux drum 628 flows in conduit 661 to combine with liquid in conduit 632 from the overhead of the condensate stabilizer 630. A condensate stabilizer 630 is installed downstream of the nominal debutanizer 620. A combined stream 671 of vapor stream from debutanizer overhead stream in conduit 661 and condensate stabilizer overhead stream in conduit 632 is eventually collected in the mixed-reflux drum 650. Prior to reaching mixed-reflux drum 650, the condensate stabilizer overhead stream in conduit 631 is routed to a condenser 635 where it is condensed (with air or water cooling) to form a condensed overhead stream 636. A portion of the liquid in conduit 636 is returned as reflux in conduit 634 using reflux pump 692 to the condensate stabilizer 630. Another portion of the liquid in conduit 636 is pumped by recycle pump 691 in conduit 632 to combine with the debutanizer reflux drum 628 overhead vapor in conduit 661 and with the resultant combined two-phase stream flowing in conduit 671. If the flow in conduit 671 is in excess then a portion of the liquid in conduit 632 may be optionally withdrawn in conduit 633 to a product storage of the LNG facility as shown in FIG. 2. Other strategies for control of inventory, or levels, in the heavies removal system may be added as needed but are not illustrated in this particular embodiment. As shown, the combined two-phase stream in conduit 671 is cooled and further condensed by a propane refrigerant (provided from the main liquefaction process but not illustrated in FIG. 1) in indirect heat exchangers 670 and 675 through cooling passes 672 and 673, respectively, to provide a cooled combined two-phase stream in conduit 674. A reflux drum bottom stream 676 exiting the mixed-reflux drum 650 is pumped to a mixed-reflux subcooler 680 via pump 677. The combined stream in conduit 676 is subcooled typically using high stage ethylene refrigerant (provided from the main liquefaction process but not illustrated in FIG. 1) in exchanger means 681 of the mixed-refluxed subcooler 680 prior to delivery to the heavies removal column 610 as mixed-reflux in conduit 611. As previously mentioned, this mixed-reflux rate provides both adequate volumetric flow for packing irrigation and molar flow/composition to sufficiently absorb the heavy components in the feed gas found in conduit 609 which is fed into the heavies removal column 610.

Heavies Removal Column

In the illustrated embodiment shown in FIG. 2, the heavies removal column 610 is a packed column with two or more sections of varying diameters. Above the main feed point C, the heavies removal column 610 is typically larger in diameter than below the main feed point C and consequently requires a relatively high reflux rate for proper irrigation of the packing For “lean” natural gas, the overhead flow 603 of the nominal debutanizer 620 may be of insufficient flow to support the irrigation requirements of the heavies removal column 610. As mentioned earlier, some feed gases may contain low concentrations of C2-C4 components which results in inadequate flow of the C4− overhead stream in conduit 603 from the nominal debutanizer 620. Without adequate flow, sufficient reflux to the heavies removal column 610 cannot be supplied. Generally, the heavies removal column 610 must have a reflux of sufficient quantity and of appropriate composition to: (1) remove (e.g., by absorption) enough C6+ heavies to prevent downstream freezing and (2) properly irrigate random packing in the heavies removal column 610. The latter aspect of proper irrigation supports the former aspect of proper reflux flow rate and composition. Performance of the heavies removal column 610 can depend greatly on the irrigation rate per unit cross sectional area of the packing In some embodiments, an irrigation rate typically between 0.5 to 1.5 gallons per minute per square foot of column cross sectional area may be required to ensure proper liquid distribution within the heavies removal column. The appropriate minimum irrigation rate may depend on a number of factors including, but not limited to, packing and column dimensions, internal vapor and liquid flow rates, and packing type of the heavies removal column. Therefore, a mixed-reflux stream 611 that includes a mixture of the overhead streams from nominal debutanizer 620 and condensate stabilizer 630 is used.

Feed temperature to the heavies removal column 610 and column pressure may be monitored and controlled to insure that vapor-to-liquid density ratios and other vapor/liquid behavior within the columns are appropriate. Temperature control may also be required to maintain relative constancy of the liquid fraction of the heavies removal column feed stream C. In some cases, the heavies removal column 610 may flood in the bottom section (if feed temperature too low) or go off specification in terms of heavies removal in the top section (if feed temperature is too high). In some embodiments, advanced regulatory control techniques may be employed to stabilize the feed temperature and other aspects of the column's operation (not illustrated). In some embodiments, the heavies removal column 610 may have multiple feeds based on the overall process optimization of the LNG plant and not just a single main feed as represented in FIG. 2. Additional feed nozzle(s) may be provided on the heavies removal column 610 to accommodate varying feed gas compositions such as, for example, a C8+ rich liquid stream which could be collected upstream as result of condensation from a feed gas with C8+ levels in excess of normal.

Debutanizer

In some embodiments, the nominal debutanizer 620 may be a frayed or packed or both. In the embodiment shown in FIG. 2, the feed stream in conduit 602 to the nominal debutanizer 620 is a two-phase stream in which the vapor and liquid phases may be fed to different trays if a feed separator (not illustrated) is included in the mixed-reflux heavies removal system. In some embodiments, the column pressure of nominal debutanizer 620 should be set as low as possible for separation efficiency but sufficiently high such that the vapor portion of the overhead product (which cannot be condensed against low-stage propane refrigerant) can be returned to the main liquefaction process for recompression. Heat duty is provided to the nominal debutanizer 620 by a debutanizer reboiler 625 that typically uses hot oil as the energy supply.

Still referring to FIG. 2, the nominal debutanizer 620 is typically operated with a sufficiently high pressure in the partial condenser 660 such that after condensation using two (or more) levels of propane refrigeration, a residual vapor stream in conduit I is typically returned in a controlled fashion to a high stage methane compressor. As mentioned earlier, the condensed debutanizer overhead stream is then routed to a debutanizer reflux drum 628, wherein the stream can be separated into a vapor stream in conduit 661 and a liquid stream in conduit 662. The liquid stream 662 is pumped back to the nominal debutanizer 620 via reflux pump 629 while the vapor stream 661 is combined with a portion of a condensed overhead stream in conduit 632 prior to being routed to a series of indirect heat exchangers (670 and 671). A portion of the condensed condensate stabilizer overhead stream in conduit 634 is routed back to the condensate stabilizer 630 as reflux while another portion of the condensed overhead stream in conduit 633 may be directed to product storage for inventory control within the heavies removal system. In some embodiments, the operating pressure may be selected sufficiently high to accommodate condensation of an adequate reflux flow rate by air cooling for the primary condensation in the partial condenser 660. The nominal debutanizer 620 may be designed with a specific reflux rate and reboiler duty for optimal number of trays and feed locations, such that desired specifications of debutanizer overhead stream in conduit 603 and debutanizer bottom stream in conduit 604 are achieved. In some embodiments, advanced regulatory control may also be provided for the debutanizer, including decoupled controllers for top pressure control and debutanizer reflux drum 628 level control. In some embodiments, hot oil flow to the debutanizer reboiler 625 may be used to stabilize a controlled temperature on a temperature-sensitive tray near the bottom of the column.

Condensate Stabilizer

In some embodiments, the condensate stabilizer 630 may be trayed or packed or both. The feed stream in conduit 604 to the condensate stabilizer 630 is two-phase. The vapor and liquid phases may be fed to different trays if a feed separator drum has been included. The condensate stabilizer 630 is designed with certain reflux rate and reboiler duty that are compatible with an optimal number of trays and feed location, such that desired specifications for the top and bottom products are achieved. Coupled to the condensate stabilizer 630 is a stabilizer reboiler 637 typically using hot oil as the energy supply. In some embodiments, advanced regulatory control may be provided for the condensate stabilizer 630, including feed forward of upstream flow to adjust both the reflux flow controller and bottom temperature controller.

While at least one embodiment described is a mixed-reflux heavies removal system comprising process streams resulting from a condensation of bottom stream of the heavies removal column, this is not intended to be limiting. In some embodiments, the present invention comprises a mixed-reflux comprising two or more mixed process streams one of which is resulting from a condensation of the overhead vapor stream of the heavies removal column.

Furthermore, in some embodiments, the reflux to the heavies removal column 610 may arise solely from the overhead stream of the nominal debutanizer, that is, from a single source. These embodiments may be particularly useful when the composition of the natural gas is such that the debutanizer can be operated to simultaneously achieve specifications of flow rate and composition for the reflux to the heavies removal column 610 while producing a debutanizer bottoms product (e.g., condensate product) with acceptable properties (e.g., Reid Vapor Pressure). In such embodiments, the condensate stabilizer 630 may not be required. The ultimately noncondensed vapor portion of the debutanizer (in conduit I) may be required to return to the main liquefaction process at a lower pressure stage of the methane compression.

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.

REFERENCES

All of the references cited herein are expressly incorporated by reference. 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 data after the priority date of this application. Incorporated references are listed again here for convenience:

1. U.S. Pat. No. 8,257,508

2. U.S. Pat. No. 7,600,395

3. US 2012/0118007

MIXED-REFLUX FOR HEAVIES REMOVAL IN LNG PROCESSING

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