NO309397B1 - Methods for removing aromatic and / or heavier hydrocarbon components from a methane-based gas stream by condensation and stripping, and apparatus for performing the same - Google Patents

Description

The invention relates to a method and associated apparatus for removing benzene, other aromatics and/or heavier hydrocarbon components from a methane-based gas stream by a unique condensation and stripping process.

Cryogenic liquefaction of normally gaseous materials is used for the purposes of component separation, purification, storage and for transporting the components in a more economical and suitable form. Most such aircraft propulsion systems have many operations in common, regardless of the gases involved, and thus have many of the same problems. A problem that is usually encountered in fly tending processes, especially when aromatics are present, is the precipitation and subsequent solidification of these species in the process equipment, which thereby results in reduced process efficiency and reliability. Another common problem is the removal of small amounts of the more valuable, higher molecular weight chemical species from the gas stream immediately prior to flight tending the gas stream to a significant proportion. Accordingly, the present invention will be described with specific reference to the processing of natural gas, but is applicable to the processing of gas in other systems where similar problems are encountered.

It is common practice in the natural gas processing field to subject the gas to cryogenic treatment to separate hydrocarbons having a molecular weight higher than methane (C2+) from the natural gas to produce a methane-predominant pipeline gas and a useful C2+ stream for other purposes. Often, the C2+ stream will be separated into individual component streams, e.g. C2, C3, C4 and C5<+.>

It is also common practice to cryogenically treat natural gas to liquefy it for transport and storage. The main reason for the liquefaction of natural gas is that liquefaction results in a volume reduction of approx. 1/600, which thereby makes it possible to store and transport the liquefied gas in containers of a more economical and practical design. E.g. when gas is transported by pipeline from the supply source to a distant market, it is desirable to operate the pipeline under a significantly constant and high load factor. Often the pipeline's delivery capability or capacity will exceed demand, while at other times demand will exceed the pipeline's delivery capability. In order to cut off peaks when demand exceeds supply, it is desirable to store the excess gas in such a way that it can be delivered when supply exceeds demand, thereby enabling future peaks in demand to be met with material from storage. A practical way to do this is to convert the gas into a liquid state for storage and then vaporize the liquid when there is a demand for it.

Natural gas liquefaction is of even greater importance in making it possible to transport a gas from a supply source to a market when the source and market are separated by large distances and a pipeline is not available or is not practical. This is especially the case when transport has to be done by ocean-going vessels. Ship transport in the gaseous state is generally not practical because significant pressurization is required to significantly reduce the specific volume of the gas which in turn requires the use of more expensive storage containers.

To store and transport natural gas in a liquid state, the natural gas is preferably cooled to -151°C to -162°C where it has a near-atmospheric vapor pressure. A number of systems are known for liquefaction of natural gas or the like where the gas is liquefied by sequentially passing the gas at an elevated pressure through a large number of cooling stages whereupon the gas is cooled to successively lower temperatures until the liquefaction temperature is reached. Cooling is generally achieved by heat exchange with one or more refrigerants such as propane, propylene, ethane, ethylene and methane or a combination of one or more of the foregoing. In the field, the refrigerants are often arranged in a cascade and each refrigerant is used in a closed cooling cycle. 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 to thereby produce a two-phase gas-liquid mixture at a significantly lower temperature. The liquid is recovered and can be flashed again. In this way, 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 used as fuel gas for power generation.

As previously known, a major operational problem in the liquefaction of natural gas is the removal of residual amounts of benzene and other aromatic compounds from the natural gas stream immediately prior to liquefaction of a significant proportion of the stream and the tendency for such components to separate and solidify, thereby causing fouling and potential plugging of pipelines and key process equipment. As an example, such fouling can significantly reduce the heat transfer efficiency and throughput of heat exchangers, particularly plate-fin heat exchangers.

For technical and economic reasons, it is not necessary to completely remove impurities such as benzene. However, it is desirable to reduce its concentration. Removal of contaminants from natural gas can be carried out by the same type of cooling that is used in the liquefaction processes where the contaminants condense according to their respective condensation temperature. Except for the fact that the gas must be cooled to a lower temperature for liquefaction, as opposed to separating the benzene contaminant, the basic cooling techniques are the same for liquefaction and separation. Consequently, with respect to residual benzene, it is only necessary to cool the natural gas to a temperature whereby a proportion of the feed gas is condensed. This can be carried out in a cryogenic separation column introduced at an appropriate point in the LNG recovery process to separate the condensed benzene from the main gas stream.

For an efficient operation of the cryogenic separation column, it is desirable to use the condensed liquid at cryogenic temperatures, which must be extracted from the column, for heat exchange with a hot dry gas stream supplied to the cryogenic separation column. However, this heat exchange system presents a problem resulting from the large temperature difference of the two streams supplied to the heat exchanger. Since the real temperature difference should not exceed 37°C, the thermal shock to the heat exchanger could destroy or shorten the useful life of the heat exchanger constructed of ordinary materials.

Another consideration related to efficient operation of a cryogenic separation column is to obtain a heat exchanger controller that allows automatic start-up of the column.

Another problem for the processing of methane-rich gas streams is the lack of a cost-effective way of extracting the higher molecular weight hydrocarbons from the gas stream prior to liquefying the stream in a significant proportion or returning the remaining stream to a pipeline or other process step. The recovered higher molecular weight hydrocarbons generally have a greater value on a per unit mass basis than the remaining components of the stream.

It is a purpose of the invention to remove residual amounts of benzene and other aromatics from a methane-based gas stream which is to be liquefied in a significant proportion.

It is another purpose of the invention to remove the higher molecular weight hydrocarbons from a methane-based gas stream.

It is a further purpose of the invention to remove the higher molecular weight hydrocarbons from a methane-based gas stream which is to be liquefied in a significant proportion.

It is a further purpose of the invention to remove benzene, other aromatics and/or the higher molecular weight hydrocarbons from methane-based gas flow in an energy-efficient manner.

It is a further purpose of the invention that the process used for the removal of benzene, other aromatics and/or higher molecular weight hydrocarbons should be compatible with and integrated into technology that is routinely used in gas plants.

It is a further purpose of the invention that the process and apparatus used for benzene, other aromatics and/or the removal of high molecular weight hydrocarbons from a methane-based gas stream should be relatively simple, compact and cost-effective.

It is a further purpose of the invention that the process used for the removal of benzene, other aromatics and/or higher molecular weight hydrocarbons from a methane-based gas stream that is to be liquefied in a significant proportion should be compatible with and integrated into technology that is routinely used in plants that produce liquid natural gas.

A further object of the invention is to provide a heat exchanger controller which overcomes the above and other associated problems for treating low temperature fluids.

Another purpose of the invention is to provide an improved regulation method that reduces equipment temperature requirements in the start-up phase, and costs for heat exchange apparatus.

A more specific purpose is to regulate heat exchanger temperatures to allow cooling of a hot fluid stream against a low temperature fluid stream without subjecting the heat exchanger to thermal shock.

A further purpose of the invention is to regulate the heat exchanger to make the automatic start-up of a cryogenic separation column easier.

In one embodiment of this invention, there is provided a process for removing and concentrating higher molecular weight hydrocarbons from a methane-based gas stream, which is characterized in that it comprises the steps of: (a) condensing a minor portion of the methane-based gas stream to thereby produce a two-phase stream ; (b) feeding the two-phase stream to the upper section of a column; (c) removing from the upper section of the column a heavy-residue-reduced gas stream; (d) removing from the lower section of the column a heavy-residue-rich liquid stream; (e) contact treatment via indirect heat exchange of the heavy-residue-rich liquid stream with a methane-rich stripping gas stream to thereby produce a heated heavy-residue-rich stream and a cooled methane-rich stripping gas stream; (f) feeding the cooled methane-rich stripping gas stream to the lower

the section of the column; and

(g) contacting the two-phase stream and the cooled methane-rich strip gas stream in the column to thereby produce the heavy-residue-reduced gas stream and the heavy-residue-rich liquid stream.

In another embodiment of this invention, a method is provided for removing benzene and other aromatics from a methane-based gas stream,

which is characterized by the fact that it consists of the steps:

(a) condensing a minor portion of the methane-based gas stream to thereby produce a two-phase stream; (b) feeding the two-phase stream to the upper section of a column; (c) removing from the upper section of the column a benzene/aromatic reduced gas stream; (d) removing from the lower section of the column a benzene/aromatic liquid stream; (e) contacting via indirect heat exchange of the benzene/aromatic liquid stream with a methane-rich stripping gas stream to thereby produce a heated benzene/aromatic stream and a cooled methane-rich stripping gas stream; (f) feeding the cooled methane-rich stripping gas stream to the lower

the section of the column; and

(g) contacting the two-phase stream and the cooled methane-rich strip gas stream in the column to thereby produce the benzene/aromatic reduced gas stream and the benzene/aromatic liquid stream.

In yet another embodiment of the invention, an apparatus is provided for carrying out the method according to claim 1 or 19,

which is characterized by the fact that it includes:

(a) a capacitor (54); (b) a column (60); (c) a heat exchanger (62) providing indirect heat exchange between two fluids; (d) a conduit (118,458) between the condenser (54) and the upper section of the column (60) for the flow of a two-phase current to the column (60); (e) a second conduit (120) connected to the upper section of the column (60) for the removal of a vapor stream from the column (60);

(f) a pipeline (109,405) between the column (60) and the heat exchanger (62)

for flowing a cooled gas stream from the heat exchanger (62);

(g) a pipeline (114,117) between the column (60) and the heat exchanger (62)

for flowing a liquid stream from the column (60);

(h) a conduit (119) connected to the heat exchanger (62) for flow

of a heated fluid stream from the heat exchanger (62); and

(i) a conduit (108,400,403,404) connected to the heat exchanger (62) for flow of a gas stream to the heat exchanger (62); and optionally a pressure reduction device (97) located in the pipeline (g) (114,117).

In a further embodiment of the invention, an apparatus is provided for carrying out the method according to claim 1 or 19,

which is characterized by the fact that it includes:

(a) a cryogenic separation column (60) for partial condensation of a feed gas stream in an LNG recovery process; (b) means (114,117) for withdrawing a liquid condensate stream from the cryogenic separation column (60); (c) a heat exchanger (62) associated with the cryogenic separation column (60); (d) means for guiding the liquid condensate flow through the heat exchanger; (e) means for passing a hot dry gas stream through the heat exchanger (62) and then to the cryogenic separation column (60), where the hot dry gas stream is cooled by indirect heat exchange with the liquid condensate stream in the heat exchanger; (f) a bypass conduit (718) having a first control valve (534) operatively located therein for bypassing the hot dry gas stream around the heat exchanger (62); (g) means (702) for establishing a first signal (706) representative of the actual temperature of the hot dry gas stream exiting the heat exchanger (62); (h) means (704) for establishing a second signal (708) representative of the actual temperature of the liquid condensate stream entering the heat exchanger (62); (i) means (700) for dividing the first signal (706) by the second signal (708) to establish a third signal (710) which is representative of the relationship between the first signal (706) and the second signal (708) );

(j) means for establishing a fourth signal (714) which is representative of a desired value for the ratio represented by the third signal

(710);

(k) means (712) for comparing the third signal (710) and the fourth signal (714) and establishing a fifth signal (716) which is responsive to the difference between the third signal (710) and the fourth signal ( 714), wherein the fifth signal (716) is scaled to be representative of the position of the first control valve (534) necessary to maintain the actual ratio represented by the third signal (710) substantially equal to the desired ratio represented by the fourth signal (714); and (m) means for manipulating the first control valve (534) in the bypass pipeline (718) in response to the fifth signal (716).

In yet another embodiment of the invention, a method is provided for regulating the temperature of a heat exchanger equipped with a bypass pipeline having a first control valve operatively connected therein, which heat exchanger is associated with a cryogenic separation column which removes a benzene contaminant from a feed stream in a LNG recovery process, characterized in that it comprises: withdrawing a liquid condensate stream at a cryogenic temperature from the cryogenic separation column; routing the liquid condensate flow through the heat exchanger; passing a hot dry gas stream through the heat exchanger and then introducing the hot dry gas stream into the cryogenic separation column, where the hot dry gas stream is cooled by indirect heat exchange with the liquid condensate stream in the heat exchanger; establishing a first signal representative of the actual temperature of the hot dry gas stream exiting the heat exchanger; establishing a second signal representative of the actual temperature of the liquid condensate stream entering the heat exchanger; dividing the first signal by the second signal to establish a third signal representative of the ratio of the first signal to the second signal; establishing a fourth signal representative of the desired value of the third signal; comparing the third signal and the fourth signal and establishing a fifth signal responsive to the difference between the third signal and the fourth signal, the fifth signal being scaled to be representative of the position of the first control valve necessary to maintaining the actual ratio represented by the third signal to be substantially similar to the desired ratio represented by the fourth signal; and regulating the first control valve in the bypass pipeline in response to the fifth signal. Figure 1 is a simplified flowchart of a cryogenic LNG production process illustrating the methodology and apparatus of the present invention for the removal of benzene, other aromatics and/or higher molecular weight hydrocarbon species from a methane-based gas stream. Figure 2 is a simplified flowchart illustrating in more detail the methodology and apparatus illustrated in Figure 1. Figure 3 is a schematic illustration of a cryogenic separation column and the associated control system for the present invention for maintaining a desired temperature ratio for the heat exchange fluids. Figure 4 is a schematic illustration similar to Figure 3 for temporarily selecting a temperature that will allow automatic start-up of the cryogenic separation column.

While the present invention in the preferred embodiments is applicable to (1) the removal of benzene and/or other aromatics from a methane-based gas stream to be condensed in significant proportion and (2) the removal of the more valuable, higher molecular weight hydrocarbon species from a methane-based gas stream to is condensed in a significant proportion, the technology is also applicable for the generic recovery of such species from methane-based streams (e.g. removal of natural gas liquids from natural gas). Benzene and other aromatics present a unique problem because of their relatively high melting point temperatures. As an example, benzene containing 6 carbon atoms has a melting point of 5.5°C and a boiling point of 80.1°C. Hexane, which also contains 6 carbon atoms, has a melting point of -95°C and a boiling point of 68.95°C. Therefore, when compared to other hydrocarbons of equal molecular weight, benzene and other aromatic compounds present a much greater problem with respect to fouling and/or clogging of process equipment and pipelines. Aromatic compounds used here are those compounds characterized by the presence of at least one benzene ring. As used herein, higher molecular weight hydrocarbon species are those hydrocarbon species having molecular weights greater than ethane, and this term will be used interchangeably with heavy hydrocarbons.

For the purposes of simplicity and clarity, the following description will be limited to the application of the inventive processes and associated apparatus in the cryogenic cooling of a natural gas stream to produce liquefied natural gas. More specifically, the following description will focus on the removal of benzene and/or other aromatic species and/or higher molecular weight hydrocarbons (heavy hydrocarbons) in a liquefaction system where cascade refrigeration cycles are used. However, the applicability of the inventive processes and associated apparatus described herein is not limited to liquid systems that employ cascade refrigeration cycles or that exclusively process natural gas streams. The processes and associated apparatus are applicable to any refrigeration system where (a) benzene and/or heavier aromatics exist in a methane-based gas stream at concentrations that can foul or clog process equipment, particularly the heat exchangers used for condensing the stream, or (b) it is desirable to any reason to remove or recover higher molecular weight hydrocarbons from a methane-based gas stream.

Liquefaction of natural gas flow

Cryogenic facilities come in a large number of forms; the most effective and efficient is a cascade-type operation and this type in combination with expansion-type cooling. Also, since methods for the production of liquefied natural gas (LNG) include the separation of hydrocarbons of molecular weight greater than methane as a first part thereof, a description of a plant for the cryogenic production of LNG effectively describes a similar plant for the removal of C2+ hydrocarbons from a natural gas flow.

In the preferred embodiment using a cascade cooling system, the invention relates to the sequential cooling of a natural gas stream at elevated pressure, e.g. about. 650 psia, by sequentially cooling the gas stream by passage through a multi-stage propane cycle, a multi-stage ethane or ethylene cycle and either (a) a closed methane cycle followed by a single or a multi-stage expansion cycle to further cool the same and reduce the pressure to nearly -atmospheric or (b) an open-ended methane cycle utilizing a portion of the feed gas as a methane source and comprising therein a multi-stage expansion cycle to further cool the same and depressurize it to near-atmospheric pressure. In the refrigeration cycle sequence, the refrigerant with the highest boiling point is used first followed by a refrigerant that has an intermediate boiling point and finally a refrigerant that has the lowest boiling point.

Pretreatment trihn provides a way to remove unwanted components such as acid gases, mercaptans, mercury and moisture from the natural gas feed stream delivered to the plant. The composition of this gas stream can vary significantly. As used herein, a natural gas stream is any stream that principally comprises methane originating in significant proportion from a natural gas feed stream, such feed stream e.g. containing at least 85% by volume of methane, with the remainder made up of ethane, higher hydrocarbons, nitrogen, carbon dioxide and a smaller amount of other pollutants such as mercury, hydrogen sulphide, mercaptans. The pretreatment step may be separate steps located either upstream of the cooling cycles or located downstream of one of the earlier cooling steps in the initial cycle. The following is a non-exhaustive list of some of the available means readily available to those skilled in the art. Acid gases and, to a lesser extent, mercaptans are routinely removed via a sorption process that uses an aqueous amine-bearing solution. This treatment step is generally performed upstream of the cooling step used in the initial cycle. A significant proportion of the water is routinely removed as a liquid via two-phase gas-liquid separation followed by gas compression and cooling upstream of the initial cooling cycle and also downstream of the first cooling stage of the initial cooling cycle. Mercury is routinely removed via a mercury sorbent layer. Residual amounts of water and acid gases are routinely removed via the use of suitably selected sorbent sieves such as regenerable molecular sieves. Processes using sorbent beds are generally located downstream of the first cooling stage in the initial cooling cycle.

The resulting natural gas stream is generally delivered to the liquefaction process at an elevated pressure or compressed to an elevated pressure, which is a pressure greater than 500 psia, preferably 500-900 psia, even more preferably 550-675 psia and even more preferably 575 - 650 psia, and most preferably approx. 600 psia. The flow temperature is typically close to ambient and slightly above ambient. A representative temperature is in the range 16-49°C.

As previously known, the natural gas stream is cooled at this point in a large number of multi-stage (eg three) cycles or stages by indirect heat exchange with a large number of refrigerants, preferably three. The overall cooling efficiency for a given cycle improves as the number of stages is increased, but this increase in efficiency is accompanied by corresponding increases in net capital cost and process complexity. The feed gas is preferably passed through an effective number of cooling stages, nominally two, preferably two to four, and more preferably three stages, in the first closed cooling cycle a relatively high-boiling coolant is used. Such a refrigerant preferably consists in a significant proportion of propane, propylene or mixtures thereof, more preferably propane, and most preferably the refrigerant essentially consists of propane. The processed feed gas then flows through an effective number of stages, nominally two, preferably two to four, more preferably two or three, in a second closed cooling cycle in heat exchange with a refrigerant having a lower boiling point. Such a refrigerant preferably consists in a significant proportion of ethane, ethylene or mixtures thereof, more preferably ethylene, and most preferably the refrigerant essentially consists of ethylene. Each of the above cooling stages for each refrigerant comprises a separate cooling zone.

In general, the natural gas feed stream will contain such amounts of C2+ components as to result in the formation of a C2+-rich liquid in one or more of the cooling stages. This liquid is removed via gas-liquid separation devices, preferably one or more common gas-liquid separators. In general, the sequential cooling of the natural gas in each stage is regulated to remove as much as possible of C2 and higher molecular weight hydrocarbons from the gas to produce a first gas stream mainly of methane and a second liquid stream containing significant amounts of ethane and heavier components. An effective number of gas/liquid separation devices are located at strategic locations downstream of the cooling zone for the removal of liquid streams rich in C2+ components. The exact locations and number of gas/liquid separators will depend on a number of operating parameters, such as the C2+ composition of the natural gas feed stream, the desired BTU content of the final product, the value of the C2+ components for other applications, and other factors routinely evaluated by those skilled in the art for LNG plant and gas plant operation. The C2+ hydrocarbon stream or streams may be demethanized via a single-stage flash or a fractionating column. In the former case, the methane-rich stream can be pressurized again and recycled or can be used as fuel gas. For the latter case, the methane-rich stream can be returned directly by pressure to the liquefaction process. The C2+ hydrocarbon stream or streams or the demethanized C2+ hydrocarbon stream may be used as fuel or may be further processed such as by fractionation in one or more fractionation zones to produce individual streams rich in specific chemical constituents (e.g. C2, C3, C4 and C2+). In the last step of the second cooling cycle, the gas stream which is mainly methane (ie liquefied) is condensed in a significant proportion, preferably in its entirety. In one of the preferred embodiments to be discussed in more detail in a later section, it is by its location in the process that the inventive process and associated apparatus for benzene, other aromatics and/or heavier hydrocarbon removal can be used. The process pressure at this location is only slightly lower than the feed gas pressure of the first stage of the first cycle.

The liquefied natural gas stream is then further cooled in a third stage, or cycle, by one of two designs. In one embodiment, the liquefied natural gas stream is further cooled by indirect heat exchange with a third closed cooling cycle where the condensed gas stream is subcooled via passage through an effective number of stages, nominally 2; preferably 2-4; and most preferably 3, where cooling is provided via a third refrigerant having a lower boiling point than the refrigerant used in the second cycle. This refrigerant preferably consists of a significant proportion of methane and, more preferably, it is mainly methane. In the second and preferred embodiment using an open methane refrigeration cycle, the liquefied natural gas stream is subcooled via contact with flash gases in a main methane preheater in a manner to be described later.

In the fourth cycle, or stage, the liquefied gas is further cooled by expansion and separation of the flash gas from the cooled liquid. In a manner to be described, nitrogen removal from the system and the condensed product is performed either as part of this step or in a separate subsequent step. A key factor in distinguishing the closed cycle from the open cycle is the initial temperature of the liquefied stream before flashing to near-atmospheric pressure, the relative amounts of flashed vapor generated in the flashing, and the arrangement of the flashed vapors. While the main part of the flash steam is recycled to the methane compressors in the open cycle system, the flashed steam in a closed cycle system is generally used as a fuel.

In the fourth cycle or step in either the open- or closed-cycle methane systems, the liquefied product is cooled via at least one, preferably two to four, and even more preferably three expansions where each expansion employs either Joule-Thomson expansion valves or hydraulic expander followed by a separation of the gas-liquid product with a separator. When a hydraulic expander is used and properly operated, the greater efficiencies associated with the recovery of power, a greater reduction in stream temperature, and the production of less vapor during the flash stage will often be cost-effective even in light of the increased capital and operating costs associated with the expander. In an embodiment used in the open-cycle system, further cooling of high-pressure liquefied product prior to flashing is made possible by first flashing a portion of this stream via one or more hydraulic expanders and then via indirect heat exchange devices that use the flashed stream to cool it high-pressure liquefied the current before flashing. The flashed product is then recycled via return to an appropriate location, based on temperature and pressure considerations, in the open methane cycle.

When the liquid product enters the fourth cycle, it is at the preferred pressure of approx. 600 psia, representative flash pressures for a three-stage flash process are 190, 61, and 14.7 psia. In the open-cycle system, steam flashed or fractionated in the nitrogen separation stage, to be described, and that flashed in the expansion flash stage, are used as refrigerants in the third stage or cycle previously mentioned. In the closed-cycle system, the steam from the flash stage can also be used as a coolant before either recycling or use as fuel. In either the open- or closed-cycle system, flashing the liquefied stream to near-atmospheric pressure will produce an LNG product having a temperature of -151°C to -162°C.

To maintain the BTU content of the liquefied product at an acceptable limit when significant nitrogen exists in the feed stream, nitrogen must be concentrated and removed somewhere in the process. Various techniques for this purpose are available to those skilled in the art. The following are examples. When an open methane cycle is used and the nitrogen concentration in the feed is low, typically less than approx. 1.0% by volume, nitrogen removal is generally achieved by removing small side streams at the high pressure inlet or outlet of the methane compressor. For a closed cycle at nitrogen concentrations up to 1.5% by volume in the feed gas, the liquefied stream is generally flashed from process conditions to near-atmospheric pressure in a single step, usually via a flash vessel. The nitrogen-bearing flash vapors are then generally used as fuel gas for the gas turbines that drive the compressors. The LNG product, which is now at near-atmospheric pressure, is carried on for storage. When the nitrogen concentration in the inlet feed gas is approx. 1.0 to approx. 1.5% by volume and an open cycle is used, nitrogen can be removed by subjecting the liquefied gas stream from the third cooling cycle to a flash stage prior to the fourth cooling stage. The flashed steam will contain a significant concentration of nitrogen and can then be used as a fuel gas. A typical flash pressure for nitrogen removal at these concentrations is approx. 400 psia. When the feed stream contains a nitrogen concentration of greater than approx. 1.5% by volume and open or closed cycle is used, the flash step cannot provide sufficient nitrogen removal. In such a case, a nitrogen reaction column will be used, from which a nitrogen-rich vapor stream and a liquid stream are produced. In a preferred embodiment using a nitrogen reaction column, the liquefied methane stream is split at high pressure to the methane preheater into a first and a second portion. The first part is flashed to approx. 400 psia and the two-phase mixture is fed as a feed stream to the nitrogen reaction column. The other portion of the high pressure liquefied methane stream is further cooled by flow through a methane preheater to be described later and is flashed to 400 psia and the resulting two-phase mixture or liquid portion thereof is fed to the upper section of the column where it acts as a reflux . The nitrogen-rich vapor stream produced from the top of the nitrogen reaction column will generally be used as fuel. The liquid stream produced from the bottom of the column is then fed to the first stage of methane expansion.

Phase cooling for liquefaction of natural gas

Critical to the liquefaction of natural gas in a cascade process is the use of one or more refrigerants to transfer heat energy from the natural gas stream to the refrigerant and finally transfer the heat energy to the environment. Actually, the cooling system works like a heat pump by removing heat energy from the natural gas stream while the stream is progressively cooled to lower and lower temperatures.

The liquefaction process employs several types of cooling including, but not limited to, (a) indirect heat exchange, (b) evaporation, and (c) expansion or depressurization. Indirect heat exchange, as used herein, refers to a process where the phase-changed refrigerant or refrigerant cools the substance to be cooled without actual physical contact between the refrigerant and the substance to be cooled. Specific examples include heat exchange experienced in a tube heat exchanger, a core-in-boiler heat exchanger, and a brazed aluminum plate fin heat exchanger. The physical state of the refrigerant and the substance to be cooled can vary depending on the demands of the system and the type of heat exchanger selected. In the inventive process, a tube heat exchanger will thus typically be used where the refrigerant is in a liquid state and the substance to be cooled is in a liquid or gaseous state, while a plate-fin heat exchanger will typically be used when the refrigerant is in a gaseous state and the substance to be cooled is cooled in a liquid state. Finally, the core-in-boiler heat exchanger will typically be used where the substance to be cooled is liquid or gas and the refrigerant undergoes a phase change from a liquid state to a gaseous state during the heat exchange.

Evaporative cooling refers to the cooling of a substance by the evaporation or vaporization of a portion of the substance with the system maintained at a constant pressure. Thus, in the course of evaporation, the portion of the substance that evaporates absorbs heat from the portion of the substance that remains in a liquid state and thus cools the liquid portion.

Finally, expansion or decompression refrigeration refers to refrigeration that

occurs when the pressure in a gas, liquid or two-phase system is lowered by passing through a pressure reducing device. In one embodiment, this expansion means a Joule-Thomson expansion valve. In another embodiment, the expansion means a hydraulic or gas expander. Because expanders extract work energy from the expansion process, lower process stream temperatures are possible in expansion.

In the discussion and figures that follow, the discussions or figures may depict the expansion of a refrigerant upon flow through a throttle valve followed by a subsequent separation of gas and liquid portions in the refrigerant coolers or condensers, which may be the case where indirect heat exchange also occurs. While this simplified scheme is feasible and sometimes preferred for reasons of cost and simplicity, it may be more efficient to perform expansion and separation and then partial evaporation as separate steps, e.g. a combination of throttle valves and flash containers before indirect heat exchange in the coolers or condensers. In another feasible embodiment, the throttle or expansion valve may not be a separate device, but an integral part of the refrigerant cooler or

- the capacitor (i.e. the flash occurs when the liquid is introduced

the refrigerant into the cooler). In a similar manner, the cooling of multiple streams for a given cooling stage may occur within a single vessel (ie cooler) or within multiple vessels. The former is generally preferred from a capital equipment cost perspective.

In the first refrigeration cycle, refrigeration is obtained by the compression of a higher boiling point gaseous refrigerant, preferably propane, to a pressure where it can be liquefied by indirect heat transfer by a heat transfer medium that ultimately uses the environment as a coolant, the coolant generally being the atmosphere, a fresh water source, a salt water source, the earth or two or more of the foregoing. The condensed refrigerant then undergoes one or more stages of expansion cooling via suitable expansion devices to thereby produce two-phase mixtures that have a significantly lower temperature. In one embodiment, the main stream is split into at least two separate streams, preferably two to four streams, and most preferably three streams where each stream is separately expanded to a designed pressure. Each stream then provides evaporative cooling via indirect heat transfer with one or more selected streams, one such stream being the natural gas stream to be liquefied. The number of separate refrigerant streams will correspond to the number of refrigerant compression stages. The vaporized refrigerant from each respective stream is then returned to the appropriate stage of the refrigerant compressor (eg two separate streams would correspond to a two-stage compressor). In a more preferred embodiment, all liquid refrigerant is expanded to a predetermined pressure, and this flow is then used to provide evaporative cooling via indirect heat exchange with one or more selected flows, one such flow being the natural gas flow to be liquefied. A portion of the liquefied refrigerant is then removed from the indirect heat transfer devices, expansion cooled by expanding to a lower pressure and correspondingly lower temperature where it provides evaporative cooling via indirect heat transfer devices with one or more designated streams, one such stream being the natural gas stream that must liquid gj is eared. Formally, this embodiment will use two such expansion cooling evaporative cooling stages, preferably two to four, and most preferably three. Similar to the first embodiment, the refrigerant vapor of each stage is returned to the appropriate inlet opening at the stage compressor.

In the preferred cascade embodiment, most of the cooling for liquefaction of the lower boiling point refrigerants (ie, the refrigerants used in the second and third cycles) is made possible by cooling these streams via indirect heat exchange with selected higher boiling refrigerant streams. This way of cooling is referred to as "cascade cooling". Actually, higher boiling refrigerants act as heaters for the lower boiling refrigerants or stated in another way, heat energy from the natural gas stream to be liquefied is pumped to a lower boiling refrigerant and then pumped (ie transferred) to one or more higher boiling refrigerants before being transferred to the environment via an ambient heat body (e.g. fresh water, salt water, atmosphere). As in the first cycle, refrigerant used in the second and third cycles is compressed via multistage compressors to preselected pressures. When possible and economically feasible, the compressed refrigerant vapor is first cooled via indirect heat exchange with one or more refrigerants (e.g. air, salt water, fresh water) directly connected to ambient heaters. This cooling can be via intermediate cooling between compression stages and/or cooling of the compressed product. The compressed stream is then further cooled via indirect heat exchange with one or more of the previously specified cooling stages for the higher-boiling refrigerants.

The second cycle refrigerant, preferably ethylene, is first cooled preferably via indirect heat exchange with one or more refrigerants directly connected to an ambient heater (i.e. intermediate stage and/or aftercooling following compression) and then further cooled and finally liquefied via sequential contact with the first or second or first, second and third cooling stages for the highest boiling refrigerant used in the first cycle. The preferred second and first cycle refrigerants are ethylene and propane, respectively.

When a three-refrigerant cascade closed-cycle system is used, the refrigerant is compressed in the third cycle in a stepwise manner, preferably optionally cooled via indirect heat transfer to an ambient heater (ie, interstage and/or aftercooling followed by compression) and then cooled via indirect heat exchange with either all or selected cooling stages in the first and second cooling cycles which preferably use propane and ethylene as respective cooling agents. Preferably, this stream is contacted in a sequential manner with each progressively colder cooling stage in the first and second cooling cycles, respectively.

In an open-cycle cascade refrigeration system as illustrated in Figure 1, they are operated

the first and second cycles in a manner analogous to that proposed for the closed cycle. However, the open methane cycle system is easily distinguished from the conventional closed refrigeration cycles. As previously stated in the discussion of the fourth cycle or fourth stage, a significant proportion of the liquefied natural gas stream originally present at elevated pressure is cooled to approx. -162°C by expansion cooling in a stepwise manner to near-atmospheric pressure. In each stage, significant quantities of methane-rich steam are produced at a given pressure. Each vapor stream preferably undergoes significant heat transfer in methane preheaters and is preferably returned to the inlet port of a compressor stage at near ambient temperature. In the flow through the methane preheaters, the flashed vapors are brought into contact with hotter streams in countercurrent and in a sequence designed

maximizing the cooling of the hot streams. The pressure selected for each stage of expansion cooling is such that for each stage the volume of gas generated plus the compressed volume of vapor from adjacent lower stages results in efficient overall operation of the multistage compressor. Intermediate cooling and cooling of the finally compressed gas is preferred and preferably carried out via indirect heat exchange with one or more cooling means directly connected to an ambient heating element. The compressed methane-rich stream is then further cooled via indirect heat exchange with refrigerant in the first and second cycles, preferably all stages associated with the refrigerant used in the first cycle, more preferably the first two stages and most preferably only the first stage. The cooled methane-rich stream is further cooled via indirect heat exchange with flash steam in the main methane preheater and is then combined with the natural gas feed stream at a point in the liquefaction process where the natural gas feed stream and the cooled methane-rich stream are at equal conditions with regard to pressure and temperature, preferably before introduction into one of the steps of ethylene cooling, more preferably immediately before the ethylene cooling step where a significant proportion of methane is liquefied (i.e. the ethylene condenser).

Optimization via interstage and intercluster heat transfer

In the more preferred embodiments, steps are taken to further optimize process efficiency by directing the refrigerant gas streams returning to the inlet port of the respective compressors at or near ambient temperature. Not only will this step improve overall efficiencies, but difficulties associated with the exposure of compressor components to cryogenic conditions are greatly reduced. This is achieved via the use of preheaters where streams containing a significant proportion of liquid and prior to flashing are first cooled by indirect heat exchange with one or more steam streams generated in a downstream expansion stage (i.e. stage) or the stages in the same or a downstream cycle. In a closed system, preheaters are preferably used to achieve additional cooling from the flashed vapors in the second and third cycles. When an open methane cycle system is used, flashed vapors from the fourth stage are preferably returned to one or more preheaters where (1) these vapors cool via indirect heat exchange the liquefied product streams before each pressure reduction step and (2) these vapors cool via indirect heat exchange the compressed vapors from the open methane cycle prior to the combination of this stream or streams with the main natural gas feed stream. These cooling stages include the previously described third cooling stage and will be discussed in more detail in the discussion of figure 1.1, an embodiment where ethylene and methane are used in the second and third cycles, the contact can be carried out via a number of ethylene and methane preheaters. In a preferred embodiment which is illustrated in Figure 1 and which will be discussed in more detail later, the process uses a main ethylene preheater, a main methane preheater and one or more additional methane preheaters. These additional preheaters are referred to herein as second methane preheaters, the third methane preheater, etc. and each such additional methane preheater corresponds to a separate downstream flash stage.

Removal of benzene, other aromatics and/or heavier hydrocarbons

The inventive process for the removal of benzene, other aromatics and/or the higher molecular weight hydrocarbon species from a methane-based gas stream is an extremely energy efficient and operationally simple process. Due to its mode of operation, the column referred to here performs as a stripping column which has both stripping and fractionation functions. The process comprises cooling the methane-based gas stream so that 0.1 to 20 mol%, preferably 0.5 to approx. 10 mol%, and more preferably 1.75 to 6 mol% of the total gas flow is condensed to thereby form a two-phase flow. The optimal mole percentage will depend on the composition of the gas undergoing liquefaction and other process-related parameters that can be easily determined by one skilled in the art.

In one embodiment, the desired two-phase flow is achieved by cooling the entire feed stream to such an extent that the desired liquid percentage is achieved. In the preferred embodiment, the gas stream is first cooled to nearly the liquefaction temperature and then split into a first stream and a second stream. The first stream undergoes further cooling and partial condensation and is then combined with the second stream to thereby produce a two-phase stream containing the desired percentage of liquids. The latter approach is preferred because of the associated ease of operation and process control.

The two-phase stream is then fed to the upper section of a column where the stream contacts the rising vapor stream from the lower portion of the column to thereby produce a heavy residue-rich liquid stream that acts as a return stream and a heavy residue-reduced vapor stream produced from the column. As used herein, "heavy residues" will refer to any predominantly organic compound having a molecular weight greater than ethane. The column is unique in that it does not, as previously stated, use a condenser for backflow generation and further does not use an evaporator for steam generation.

As previously stated, a methane-rich strip gas stream is fed to the column. This stream preferably originates from an upstream location where the methane-based gas stream undergoing cooling has undergone a certain degree of cooling and removal of liquids. Before entering the bottom of the column, this gas stream is cooled via indirect contact, preferably in countercurrent, with the liquid product produced from the bottom of the column which thereby produces a heated heavy residue-rich stream and a cooled methane-rich strip gas stream. The methane-rich stripping gas can undergo partial condensation on cooling and the resulting cooled methane-rich stripping gas containing two phases can be fed directly to the column.

The use of the cooled methane-rich strip gas containing small amounts of C3+ components instead of steam generated from an evaporator containing significant amounts of C3+ components significantly reduces problems associated with fluids in the column approaching critical conditions where poor component separation occurs. This factor becomes particularly significant when operating in a more preferred pressure range of approx. 550 to 675 psia. The critical temperature and pressure of methane is -82.4°C and 673.3 psia. The critical temperature and pressure of propane is 96.8°C and 617.4 psia and the critical temperature and pressure of n-butane is 152.1°C and 551.25 psia. The presence of significant amounts of C3+ components will (1) lower the critical pressure thereby approaching the preferred operating pressures for the process and (2) raise the critical temperature. The resulting effect is to make the separation of the components via vapor/liquid contact more difficult. A second factor that distinguishes the applications of the cooled methane-rich stripping gas above the steam from an evaporator is the temperature difference between these respective streams and the liquid discharge from the last stage. Because it is preferred that the cooled methane-rich stripping gas be hotter than the analogous vapor from an evaporator, this preferred stream has a greater ability to strip the liquid phase of the lighter components. A temperature difference between the discharge liquid from the column and the discharge stripping gas of the column is more preferably -6.7°C to 43.3°C, even more preferably 4.4°C to 32.2°C, and most preferably 15.6°C to 26.7°C.

The number of theoretical plates in the column will depend on the composition, temperature and flow rate of the inlet vapor stream to the column and the composition, temperature, flow rate and liquid to vapor ratio of the two-phase stream fed to the upper section of the column. It is easy to come to such a determination within the knowledge of a professional in the field. The theoretical number of plates can be provided via different types of column packing (pallet rings, saddle-shaped packing material etc) or distinct contact steps (eg plates) placed in the column or a combination thereof. In general, two (2) to fifteen (15) theoretical steps are required, more preferably three (3) to ten (10), and even more preferably four (4) to eight (8), and most preferably approx. five (5) theoretical steps. Plates are generally preferred when the column diameter is greater than approx. 2 meters.

Preferred open-loop embodiment of cascade liquefaction process The flow chart and apparatus set forth in Figures 1 and 2 is a preferred embodiment of the open-cycle cascade liquefaction process and is presented for illustrative purposes. A nitrogen removal system is intentionally omitted from the preferred embodiment, because such a system is dependent on the nitrogen content of the feed gas. However, as noted in the previous discussion of nitrogen removal technologies, methodologies suitable for this preferred embodiment are readily available to those skilled in the art. Shown in Figures 3 and 4 in greater detail for illustrative purposes is the inventive cryogenic column and in particular the methodology for cooling and regulating the temperature of the stripping gas fed to the cryogenic column. Those skilled in the art will also recognize that Figures 1-4 are schematic only and therefore many pieces of equipment needed in a commercial plant for successful operation may have been omitted for clarity. Such devices may include e.g. compressor regulators, flow and level measurements and corresponding controls, additional temperature and pressure regulators, pumps, motors, filters, additional heat exchangers, valves, etc. These devices are obtained according to standard technical practice.

For a better understanding of Figures 1, 2, 3 and 4, devices or particles numbered 1 through 99 generally correspond to process vessels and equipment directly associated with the fluidizing process. Articles indicated with 100-199 correspond to flow lines or conduits that contain methane in significant proportion. Items listed with 200-299 correspond to flow lines or conduits containing the refrigerant ethylene or optionally ethane. Items listed as 300-399 correspond to flow lines or lines containing the refrigerant propane. To the extent possible, the numbering system used in Figure 1 has been used in Figures 2, 3 and 4. In addition, the following numbering system has been added for additional items not illustrated in Figure 1. Articles listed as 400- 499 corresponds to additional flow lines or conduits. Articles listed with 500-599 correspond to additional process equipment such as vessels, columns, heat exchangers and valves, including process control valves. Articles listed with numbers from 600-799 generally relate to the process control system, excluding control valves and particularly include sensors, transducers, regulators and setpoint inputs.

In almost all control systems, a certain combination of electrical, pneumatic or hydraulic signals is used. However, the use of any other type of signal transmission is compatible with the process and equipment in use within the scope of this invention. With regard to the invention as it appears in figures 1-4, lines are designed as signal lines drawn as dashed lines in the drawings. These lines are preferably electric or pneumatic signal lines. In general, signals obtained from any transducer are in electrical form. However, the signals obtained from flow sensors are generally pneumatic in form. The transduction of these signals is not always illustrated for simplicity, because it is well known in the art that if a flow is measured in pneumatic form, then it must be transduced into electrical form if it is to be transmitted in electrical form by a flow transducer.

Referring to Figure 1, gaseous propane is compressed in multi-stage compressor 18 driven by a gas turbine engine which is not illustrated. The three stages of compression preferably exist in a single unit, although each compression stage may be a separate unit and the units mechanically connected may be driven by a single motor. During compression, the compressed propane is passed through pipeline 300 to cooler 20 where it is liquefied. A representative pressure and temperature of the liquefied propane refrigerant before flashing is approx. 37°C and approx. 190 psia. Although not illustrated in Figure 1, it is preferred that a separation vessel be located downstream of cooler 20 and upstream of a pressure reducing device, illustrated as expansion valve 12, for the removal of residual light components from the liquefied propane. Such vessels can be comprised of a single-stage gas-liquid separator or can be more advanced/sophisticated and consist of an accumulator section, a condenser section and an absorber section, where the latter two can be continuously operated or periodically brought on-line for the removal of residues of light components from the propane. The flow from this vessel or the flow from cooler 20, as the case may be, is passed through pipeline 302 to a pressure reduction device, illustrated as expansion valve 12, where the pressure on the liquefied propane is reduced to thereby evaporate or flash a portion thereof. The resulting two-phase product then flows through pipeline 304 to a high-stage propane cooler 2 where gaseous methane refrigerant is introduced via pipeline 152, natural gas feed is introduced via pipeline 100 and gaseous ethylene refrigerant is introduced via pipeline 202 are respectively cooled via indirect heat exchange devices 4, 6 and 8 to thereby produce chilled gas streams produced via pipelines 154, 102 and 204 respectively. The gas in pipeline 154 is fed to the main methane preheater 74 which will be discussed in more detail in a subsequent section and where the stream is cooled via indirect heat exchange device 98. The resulting cooled methane recycle stream product via pipeline 158 is then combined with heavy residues of reduced steam flow in pipeline 120 from the heavy residue removal column 60 and fed to the methane condenser 68.

The propane gas from cooler 2 is returned to compressor 18 through pipeline 306. This gas is fed to the high-stage inlet opening in compressor 18. The remaining liquid propane is passed through pipeline 308, the pressure is further reduced by passage through a

pressure reduction device, illustrated as expansion valve 14, on which a

a further proportion of the liquefied propane flashes. The resulting two-phase stream is then fed to cooler 22 through pipeline 310 to thereby provide a coolant for cooler 22. The cooled feed gas stream from cooler 2 flows via pipeline 102 to a separation vessel 10 where gas and wash phases are separated. The liquid phase, which is rich in C3+ components, is removed via pipeline 103. The gaseous phase is removed via pipeline 104 and is then split into two separate streams which are carried via pipelines 106 and 108.

The stream in pipeline 106 is fed to propane cooler 22. The stream in pipeline 108 becomes feed material to heat exchanger 62 and is finally the stripping gas to the heavy-residue removal column 60. Ethylene refrigerant from cooler 2 is introduced to cooler 22 via pipeline 204. In cooler 22, the feed gas stream is cooled, also referred to to here as a methane-rich stream, and the ethylene refrigerant streams respectively via indirect heat transfer devices 24 and 26 to thereby produce cooled methane-rich and ethylene refrigerant streams via pipelines 110 and 206. The thus evaporated portion of the propane refrigerant is separated and passed through pipeline 311 to the intermediate stage inlet of compressor 18. Propane refrigerant in liquid form from cooler 22 is removed via pipeline 314, flashed over a pressure reduction device, illustrated as expansion valve 16, and then fed to a three-stage cooler 28 via pipeline 316.

As illustrated in Figure 1, the methane-rich stream flows from the mid-stage propane cooler 22 to the low-stage propane cooler/condenser 28 via pipeline 110.1 this cooler is stream cooled via indirect heat exchange devices 30. Similarly, the ethylene refrigerant stream flows from the mid-stage propane cooler 22 to the low-stage propane cooler/condenser 28 via pipeline 206.1 in the latter case, the ethylene refrigerant is completely or almost completely condensed via indirect heat exchange device 32. The vaporized propane is removed from the low-stage propane cooler/condenser 28 and returned to the low-stage inlet at the compressor 18 via conduit 320. Although Figure 1 illustrates cooling of streams produced in pipelines 110 and 206 to occur in the same vessel, the cooling of stream 110 and the cooling and condensing of stream 206 can respectively take place in separate process vessels (eg, a separate cooler and a separate condenser). In a similar way, the previous cooling steps where multiple streams are cooled in a common vessel (e.g. cooler) can be performed in separate vessels. The first arrangement is a preferred design due to the cost of multiple vessels and the need for less installation space.

As illustrated in Figure 1, the methane-rich stream exiting the low-stage propane cooler is introduced to the high-stage ethylene cooler 42 via pipeline 112. The ethylene refrigerant exits the low-stage propane cooler 28 via pipeline 208 and is preferably fed to a separation vessel 37 where light components are removed via pipeline 209 and condensed ethylene is removed via pipeline 210. The separation vessel is analogous to the vessel previously discussed for the removal of light components from liquefied propane refrigerant and may be a single-stage gas-liquid separator or may be a multi-stage operation that provides greater selectivity in the removal of light components from the system. The ethylene refrigerant at this location in the process is generally at a temperature of approx. -31°C and a pressure of approx. 285 psia. The ethylene refrigerant via pipeline 210 then flows to the ethylene preheater 34 where it is cooled via indirect heat exchange device 38 and removed via pipeline 211 and passed to a pressure reduction device illustrated as expansion valve 40 whereupon the refrigerant is flashed to a preselected temperature and pressure and fed to the high-stage ethylene cooler 42 via pipeline 212. Steam is removed from this cooler via pipeline 214 and is led to the ethylene preheater 34 where the steam acts as a refrigerant via indirect heat exchange device 46. The ethylene vapor is then removed from the ethylene preheater via pipeline 216 and fed to the high-stage inlet of the ethylene compressor 48. The ethylene refrigerant that is not evaporated in this high-stage ethylene cooler 42, is removed via pipeline 218 and returned to the ethylene preheater 34 for further cooling via indirect heat exchange device 50, removed from the ethylene preheater via pipeline 220 and flashed in a pressure reduction device illustrated as expansion v until 52 whereupon the resulting two-phase product is introduced into the low-stage ethylene cooler 54 via pipeline 222.

Removed from high-stage ethylene cooler 42 via pipeline 116 is a methane-rich stream. This stream is then partially condensed via cooling provided by indirect heat exchanger 56 in low-stage ethylene cooler 54 which thereby produces a two-phase stream which flows via pipeline 118 to the benzene/aromatics/heavy residue removal column 60. As previously stated, the methane-rich stream in pipeline 104 was split as follows that it flows via pipelines 106 and 108. The contents of pipeline 108, which is referred to here as the methane-rich stripping gas, are first fed to heat exchanger 62 where this flow is cooled via indirect heat exchange device 66 to thereby become a cooled methane-rich stripping gas stream which then flows in pipeline 109 to the benzene/heavy residue removal column 60. Liquid containing a significant concentration of benzene, other aromatics and/or heavier hydrocarbon components is removed from the benzene/heavy residue removal column 60 via conduit 114, preferably flashed via a flow control device which may also act as a pressure reduction device 97, preferably a control valve, and is transported to heat exchanger 62 in pipeline 117. Preferably, the flow flashed via flow control device 97 is flashed to a pressure of approx. or greater than the pressure at the high-stage inlet of the methane compressor. Flashing also provides greater cooling capacity for the current. In the heat exchanger 62, the stream supplied by pipeline 117 provides cooling capabilities via indirect heat exchange device 64 exits the heat exchanger via pipeline 119. In the benzene/aromatic/heavy-residue stripping column 60, the two-phase stream introduced via pipeline 118 is brought into contact with the cooled methane-rich strip gas stream introduced via pipeline 109 in countercurrent to thereby produce a benzene/heavy-residue-reduced, methane-rich vapor stream via pipeline 120 and a benzene/heavy-residue-reduced liquid stream via pipeline 117.

The flow in pipeline 119 is rich in benzene, other aromatics and/or other heavier hydrocarbon components. This stream is then separated into liquid and vapor portions or preferably flashed or fractionated in vessel 67.1 in each case a liquid stream rich in benzene, other aromatics and/or heavier hydrocarbon components is produced via pipeline 123 and a second methane rich vapor stream is produced via pipeline 121.1 the preferred embodiment illustrated in Figure 1, the stream in pipeline 121 is then combined with a second stream delivered via pipeline 128 and the combined stream is fed via pipeline 140 to the high pressure inlet of the methane compressor 83.

As previously stated, the gas is fed in pipeline 154 to the main methane preheater 74 where the stream is cooled via indirect heat exchange device 98. The resulting cooled compressed methane recycle or refrigerant stream in pipeline 158 is preferably combined with the heavy-residue-reduced steam stream from the heavy-residue removal column 60 delivered via pipeline 120 and fed to the low-stage ethylene condenser 68.1 the low-stage ethylene condenser this stream is cooled and condensed via indirect heat exchange device 70 with the liquid discharge from the low-stage ethylene cooler 54 which is fed to the low-stage ethylene condenser 68 via pipeline 226. The condensed methane-rich product from the low-stage condenser is produced via pipeline 122. The steam from the low-stage ethylene cooler 54 extracted via pipeline 224 and the low-stage ethylene condenser 68 extracted via pipeline 228 are combined and fed via pipeline 230 to the ethylene preheater 34 where the vapors act as a coolant via indirect heating switching device 58. The flow is then carried via pipeline 232 from the ethylene preheater 34 to the low-stage side of the ethylene compressor 48.

As shown in Figure 1, the compressor discharge is removed from steam introduced via the low stage side via pipeline 234, cooled via interstage cooler 71 and returned to compressor 48 via pipeline 236 for injection with the high stage stream present in pipeline 216. Preferably, the two stages are a single module, although they may each be a separate module and the modules are mechanically connected to a common motor. The compressed ethylene product from the compressor is fed to a downstream cooler 72 via pipeline 200. The product from the cooler flows via pipeline 202 and is introduced, as previously explained, to the high-stage propane cooler 2.

The liquefied flow in pipeline 122 is generally at a temperature of approx. -87°C and a pressure of approx. 600 psi. This flow passes via pipeline 122 through the main methane preheater 74, where the flow is further cooled by indirect heat exchange device 76 which is explained in the following. From the main methane preheater 74, the liquefied gas is passed through conduit 124 and its pressure is reduced by a pressure reducing device as illustrated as expansion valve 78, which of course evaporates or flashes a portion of the gas stream. The flashed stream is then passed to the methane high-stage flash drum 80 where it is separated into a gas phase which flows out through pipeline 126 and a liquid phase which flows out through pipeline 130. The gas phase is then transferred to the main methane preheater via pipeline 126 where the vapor acts as a coolant via indirect heat transfer device 82 .The vapor exits the main methane preheater via pipeline 128 where it is combined with the gas stream supplied by pipeline 121. These streams are then fed to the high pressure inlet port of compressor 83.

The liquid phase in pipeline 130 is passed through a second methane preheater 87 where the liquid is further cooled by downstream flash vapor via indirect heat exchange device 88. The cooled liquid exits the second methane preheater 87 via pipeline 132 and is expanded or flashed via pressure reducing device illustrated as expansion valve 91 to further reduce the pressure and at the same time evaporate a second portion thereof. This flash stream is then passed to the intermediate stage methane flash drum 92 where the stream is separated into a gas phase which passes through pipeline 136 and a liquid phase which passes through pipeline 134. The gas phase flows through pipeline 136 to the second methane preheater 87 where the steam cools the liquid introduced to 87 via pipeline 130 via indirect heat exchange device 89. Pipeline 138 functions as a flow pipeline between indirect heat exchange device 89 in the second methane preheater 87 and the indirect heat transfer device 95 in the main methane preheater 74. This steam leaves the main methane preheater 74 via pipeline 140 which is connected to the intermediate stage inlet of the methane compressor 83.

The liquid phase exiting the intermediate flash drum 92 via pipeline 134 is further reduced in terms of pressure by passage through a pressure reduction device illustrated as expansion valve 93. A third portion of the liquefied gas is again vaporized or flashed. The fluids from expansion valve 93 are passed to final or low-stage flash drum 94. In flash drum 94, a vapor phase is separated and led through pipeline 144 to the second methane preheater 87 where the steam acts as a coolant via indirect heat exchange device 90, exits the second methane preheater via pipeline 146 which is connected to the first methane preheater 74 where the steam acts as a refrigerant via indirect heat exchange device 96 and finally leaves the first methane preheater via pipeline 148 which is connected to the low pressure opening on compressor 83.

The liquefied natural gas product from flash drum 94 which is at approximately atmospheric pressure is passed through pipeline 142 to the storage unit. The low-pressure, low-temperature LNG boiled vapor stream from the storage unit and optionally the vapor returned from the cooling of the pipelines from the production facility to storage associated with the LNG loading system are preferably recovered by combining such a stream, or streams, with the low-pressure flash vapors present in either pipeline 144, 146 or 148 ; the piping chosen is based on a desire to match the steam flow temperatures as accurately as possible.

As shown in Figure 1, the high, middle and low stages of compressor 83 are preferably combined as a single unit. However, each stage may exist as a separate unit where the units are mechanically linked together to be driven by a single drive wheel. The compressed gas from the low stage section passes through an intermediate stage cooler 85 and is combined with the intermediate pressure gas in conduit 140 prior to the second stage compression. The compressed gas from the intermediate stage of compressor 83 is passed through an intermediate stage cooler 84 and is combined with the high pressure gas in pipeline 140 before the third stage compression. The compressed gas is led from the high-stage methane compressor through pipeline 150, cooled in cooler 86 and led to the high-pressure propane cooler via pipeline 152 as previously explained.

Figure 1 shows the expansion of the liquefied phase using expansion valves with subsequent separation of gas and liquid parts in the cooler or condenser. While this simplified scheme is feasible and used in some cases, it is often more efficient and effective to perform partial evaporation and separation steps in separate equipment, e.g. an expansion valve and separate flash drum may be used prior to the flow of either the separated vapor or liquid to a propane cooler. Similarly, certain process streams undergoing expansion are ideal candidates for the use of a hydraulic expander as part of the pressure reduction device to thereby enable the extraction of working energy and also to lower two-phase temperatures.

With respect to the compressor/driver units used in the process, Figure 1 shows individual compressor/driver units (ie, a single compression impeller) for the propane, ethylene and open-cycle methane compression stages. However, in a preferred embodiment for any cascade process, process reliability can be significantly improved by using a multiple compression impeller that includes two or more compressor/driver combinations in parallel instead of the individual compressor/driver units shown. In the event that a compressor/driver unit becomes unavailable, the process can still be operated at a reduced capacity.

Preferred Embodiment of the Inventive Removal Process and Apparatus Shown in Figure 2 is a preferred embodiment of the benzene, other aromatics and/or heavier hydrocarbon component removal process and associated apparatus. As previously stated, the two-phase stream fed to the benzene/aromatics/heavier residue removal column 60 via pipeline 118 occurs from the cooling and partial condensation of the stream in pipeline 116 via cooling provided by heat exchange device 56 in ethylene cooler 54. In one embodiment, the entire stream in pipeline 116.1 is cooled a preferred embodiment illustrated in figure 2, the two-phase flow is achieved by cooling and partial condensation of a part of the flow in pipeline 116 and this part is then combined with the remaining part of the flow coming via pipeline 116.

Referring to Figure 2, the flow delivered via conduit 116 is split into a first flow flowing in conduit 450 and a second flow flowing in conduit 452. The flow in conduit 532 flows through an optional valve 532, preferably a manual control valve, to conduit 454 which delivers the first stream to ethylene cooler 54 where the stream undergoes at least partial condensation via indirect heat exchange device 56 and exits the device via pipeline 458. The second stream in pipeline 452 flows through a valve 530, preferably a control valve, into pipeline 456 which then combines with the first stream delivered via pipeline 458. The combined streams, now a two-phase stream, are delivered to the columns 60 via pipeline 118. From an operational perspective, the length of pipeline 118 must be sufficient to ensure adequate mixing of the two streams so that equilibrium conditions are reached. The quantity of liquids in the two-phase flow in pipeline 118 is preferably regulated by maintaining the flows at a desired temperature. This is achieved in the following way. A temperature transducing device 688 in combination with a sensor such as a thermocouple located in conduit 118 provides an input signal 686 to a temperature controller 682. Also provided to the controller by operating or computer algorithm is a set point temperature signal 684. The controller 682 responds to the differences in the two inputs and transmits a signal 680 to the flow control valve 530 located in the pipeline where flows of the portion of the flow is delivered via pipeline 116 that does not undergo cooling via heat exchange device 56 in the cooler 54. The transmitted signal 680 is scaled to be representative of the position of the control valve 530 which is required to maintain the flow rate necessary to achieve the desired temperature in conduit 118.

These feed streams to the process step where benzene, other aromatics and/or heavier hydrocarbon components are removed are the two-phase process stream from ethylene cooler 54 delivered via pipeline 118 to the upper section of column 60 and the methane-rich strip gas delivered via pipeline 108. Although derived in Figure 1 to come from the feed gas stream from the first stage of propane cooling, this stream may come from anywhere in the process or may be a methane-rich stream outside the process. As illustrated in Figure 2, at least a portion of the methane-rich strip gas undergoes cooling in heat exchanger 62 via indirect heat exchange device 62 before entering the bottom of column 60. The effluent streams from this inventive process step are heavy-residue-reduced gas stream from column 60 produced via pipeline 120 and the heated heavy-residue-rich stream produced via pipeline 119. As illustrated in Figure 2, a heavy-residue-rich stream is produced from column 60 and undergoes heating in heat exchanger 62 via indirect heat exchange device 66. In this way, the column discharge produced via pipeline 114 cools the stripping gas fed to the column via pipeline 109.

The number of theoretical stages in column 60 will depend on the composition of the feed streams to the column. In general, two (2) to fifteen (15) theoretical steps will be required. The preferred number of steps is three (3) to ten (10), even more preferably four (4) to eight (8) and from an operational and cost perspective the most preferred number is approx. five (5). The theoretical steps may be available via packing, plates or a combination thereof. In general, packing in columns of less than approx. 2 m diameter and slabs on columns of more than approx. 2 m diameter. As illustrated in Figure 2, the upper section of the column to which the two-phase flow in conduit 118 is fed is designed to facilitate gas/liquid separation. The top of the column preferably contains a device for removing dew or removing entrained liquids from the steam stream. This device shall be located between the entry point of pipeline 118 and the exit point of pipeline 120. As illustrated in Figure 2, the heavy-residue-rich liquid stream produced via pipeline 114 flows through control valve 97 and pipeline 117 to heat exchanger 62 where the flow provides cooling via indirect heat - transfer device 64 and is produced from heat exchanger 62 via pipeline 119 as a heated heavy-residual-rich stream. Depending on the operating pressure in the downstream processes, the cooling capacity of this stream can be increased by flashing to a lower pressure by flow through control valve 97. This process stream produced via pipeline 119 can be used directly or undergo subsequent treatment for the removal of lighter components. In the preferred embodiment illustrated in Figure 2, the flow is fed to a methane remover 67.

The flow rate of heavy-residue-rich liquid from column 60 can be regulated via various methodologies readily available to one skilled in the art. The regulating apparatus, which is illustrated in Figure 2, is a preferred apparatus and consists of a level regulating device 600, also a sensor, and a signal transducer associated with the level regulating device, operationally located in the lower section of the column 60. The regulator 600 establishes an output signal 602 which either represents the flow rate in conduit 114 necessary to maintain a desired level in column 60 or indicates that the actual level has exceeded a predetermined level. A flow measuring device and transducer 604 which is operationally located in pipeline 114 establishes an output signal 606 that represents the real flow rate of the fluid in pipeline 114. The flow measuring device is preferably located upstream of the control valve in order to avoid contact with a two-phase flow. Signal 602 is provided as a set point signal to flow controller 608. Signals 602 and 608 are respectively compared in flow controller 608 and controller 608 establishes an output signal 614 which is in response to the difference between signal 602 and 606. Signal 614 is provided to control valve 97 and valve 97 is manipulated in response to signal 614. A set point signal (not illustrated) which is representative of a desired level in column 60 may be manually supplied to level controller 600 by an operator or alternatively it may be under computer control via a control algorithm. Depending on the operating conditions, operational or computer logic is used to determine whether regulation will be based on liquid level or flow rate. In response to the variable flow rate input of signal 606 and the selected setpoint signal, the controller 608 provides an output signal 614 which is responsive to the difference between the respective input and setpoint signals. This signal is scaled to be representative, as the case may be, of the position of control valve 97 necessary to maintain the fluid flow rate substantially equal to the desired flow rate or fluid level substantially equal to the desired fluid level, which may be the case.

In heat exchanger 62, the heavy-residue-rich stream, which cools the methane-rich stripping gas stream, is fed to the heat exchanger via pipeline 117. Heavy-residue-rich stream flows through indirect heat exchange device 66 and is produced from the heat exchanger via pipeline 119. The degree to which methane-rich stripping gas is cooled by heavy -residue-carrying current before introduction into the column, can be regulated via different methodologies which are easily accessible to professionals in the field. In one embodiment, the entire methane-rich strip gas stream is fed to the heat exchanger and the degree of cooling is regulated by such parameters as the amount of heavy-residue-rich fluid stream made available for heat transfer, the heat transfer surface areas available for heat transfer and/or the residence times of the fluids undergoing heating or cooling as may be the case. In a preferred embodiment, the methane-rich stripped gas stream delivered via pipeline 108 flows through control valve 500 into pipeline 400 where the stream is split and transferred via pipelines 402 and 403. The stream flowing through 403 ultimately flows through indirect heat transfer device 64 in heat exchanger 62. A device for manipulating the relative flow rates of fluid in conduits 402 and 403 are obtained in either conduits 402 and 403 or both. The devices illustrated in Figure 2 are simple manual control valves, indicated as 502 and 504, which are respectively attached to pipelines 404 and 407. However, a control valve whose position is manipulated by a controller and where the input to the controller consists of a set point and a signal representative of pipeline flow, such as that discussed above for heavy-residue-bearing streams, is substituted for one or both of the manual control valves. In any case, the valves are operated so that the temperature approximation difference of the flows in pipelines 117 and 404 to heat exchanger 62 does not exceed 10°C, whereupon damage to the heat exchanger may occur. The cooled fluid leaves the indirect heat transfer device 64 via pipeline 405 and combines at a connection point with uncooled methane-rich stripping gas delivered via pipeline 407 to thereby form the cooled methane-rich stripping gas stream which is delivered to the column via pipeline 109.

Operationally located in pipeline 109 is a flow transducing device 616 which, in combination with a flow sensor such as a diaphragm (not illustrated), establishes an output signal 618 which represents the actual flow rate of the fluid in the pipeline. Signal 618 is provided as a process variable input to a flow controller 620. Also obtained either manually or via data output signal is a set point value for the flow rate represented by signal 622. The flow controller then provides an output signal 624 which is responsive to the difference between the respective input and set point values the signals and which are scaled to be representative of the position of control valves necessary to maintain the desired flow rate in pipeline 109.

In another embodiment, the relative flow rate of fluid through conduits 402 and 403 can be regulated by placing a temperature and a

transducer connected to the device, if necessary, in conduit 109 and using the resulting output and a set point temperature as input to a flow controller which will generate an output signal which is responsive to the difference between the two signals and scaled to be representative of a control valve position that is necessary to maintain the desired flow rate in pipeline 109. Such control valves can be used instead of manual valves 502 and/or 504.

In yet another embodiment depicted in Figure 3, the temperature of the stripping gas to column 60 is regulated in the following manner. Temperature transducer 704 in combination with a measuring device such as a thermocouple operatively placed in pipeline 117 provides an output signal 708 that is representative of the actual temperature of liquid flowing in pipeline 117. Signal 708 is obtained as a first input to ratio calculator 700. Ratio calculator 700 is also provided with a second temperature signal 706 which is representative of the temperature of fluid flowing into conduit 109. Signal 706 occurs in temperature transducer 702 whose output signal 706 is in response to a sensing element such as a thermocouple operatively located in conduit 109.1 response to signals 706 and 708 gives ratio calculator 700 an output signal 710 which is representative of the ratio between signals 706 and 708. Signal 710 is obtained as an input to ratio regulator 712. Ratio regulator 712 is also obtained with a set point signal 714 which is representative of the desired temperature ratio for the fluids flowing in pipelines 109 and 114.1 re response to signals 710 and 714, ratio controller 712 provides an output signal 716 that is responsive to the difference between signals 710 and 714. Signal 716 is scaled to be representative of the position of control valve 534, which is operatively located in bypass conduit 718, which is required to maintain the desired ratio represented by set point signal 714. Control valve 534 is manipulated in response to signal 716.

According to the most preferred control methodology depicted in figure 4 where like numerical references are used for elements shown in the previous figures, an automatic start-up of column 60 is facilitated by high selector 728. It should be noted that set point 724 on temperature controller 722 is desirably set to a temperature compatible with the liquid in column 60. However, at startup, the temperature in conduit 109 will be at or near ambient temperature. Accordingly, connecting signal 726 directly to manipulate valve 536 would cause valve 536 to close and not allow flow of the hot dry gas to a cryogenic separation column 60 during startup. This problem is overcome by temporarily selecting signal 742 to manipulate valve 536 as described above.

In response to signals 706 and 724, temperature controller 722 provides an output signal 726 in response to the difference between signals 706 and 724. Signal 726 is scaled to be representative of the location of control valve 536 operatively located in conduit 108 required to maintain it the actual temperature of the fluid in pipeline 109 which is essentially equal to the desired temperature represented by signal 724. However, as previously stated, the desired value for set point signal 724 will not allow starting up the column. Accordingly, signal 726 is provided to a signal selector 728. Signal selector 728 is also provided with a control signal 742 which is responsive to the difference between signals 736 and 740 and is scaled to be representative of the position of control valve 536 required to maintain the temperature of fluid in pipeline 119 which is substantially equal to the desired temperature represented by signal 740. When starting the column, the actual temperature of fluid in pipeline 119 will be less than the desired temperature represented by signal 740. Consequently, connecting signal 742 to valve 536 cause valve 536 to open so as to lower the temperature represented by signal 706. High selector 728 determines which of the control signals 726 and 742 will manipulate valve 536.

Start-up proceeds as follows. Feed gas is introduced into the top of the cryogenic separation column 60 in the upper section. As the temperature of the feed gas cools to the condensation temperature of the impurity to be removed, a level of liquid begins to build up in column 60. Level controller 600 senses the level and its output opens valve 97 in response to signal 614. The low temperature liquid is then passed to heat exchanger 62 and exchanges heat with a hot dry gas flow through pipeline 108 and valve 536. Valve 536 is initially opened by signal 742 at set point temperature. After dry gas flow is initiated, temperature transducer 702 senses a much colder temperature which results in signal 726 being selected by high selector 728. The start-up controls assist the operator in providing a safe start-up and in reducing the level of human supervision required.

The heated heavy-residue-rich liquid stream from heat exchanger 62 is fed via pipeline 119 to methane removal column 67 which contains both rectification and stripping sections. The rectification and stripping sections may contain discrete stages (eg plates) or may provide continuous mass transfer from column packing (eg saddles, stacking rings, wire, cloth) or a combination of the foregoing. In general, packing is preferred for columns that have a diameter of less than 2 m and separate stages are preferred for columns that have a diameter of less than 2 m. The number of theoretical stages in both the rectification and stripping sections of the desired composition of the final products and the composition of the food stream. Preferably, the stripping or lower section contains 4 to 20 theoretical stages, more preferably 8 to 12 theoretical stages, and most preferably approx. 10 theoretical steps. In a similar manner, the upper part or rectification part of the column preferably contains 4 to 20 theoretical stages, more preferably 8 to 13 theoretical stages, and most preferably approx. 10 theoretical steps.

A conventional evaporator 524 is provided at the bottom to provide stripping steam. In the preferred embodiment shown in Figure 2, fluid is fed from the lowest stage of the methane remover to the evaporator via pipeline 428 where the fluid is heated via an indirect heat transfer device 525 with a heating medium supplied via pipeline 440 and returned via pipeline 442 which is connected to the flow control valve as in ture is connected to pipeline 444. Steam from the evaporator is returned to the methane removal column via pipeline 430 and liquids are removed from the evaporator via pipeline 432. The flow in pipeline 432 can optionally be combined in pipeline 436 with a second liquid stream produced from the bottom of the methane remover via an optional pipeline 434. The total liquid flow produced from the methane remover via pipeline 436 and/or 432, as may be the case, may optionally flow through cooler 520 and be produced via pipeline 438. A device for a regulation of the liquid flow is inserted in one or both of the preceding pipelines. In an embodiment as illustrated in Figure 2, the flow control device consists of control valve 522 which is inserted between pipelines 438 and 123. The position of the control valve 522 is manipulated by a flow controller 632 which is responsive to the differences between a set point input signal 628 from a level control device 626 and the the actual flow rate of fluid in conduit 438 represented by signal 631. A setpoint flow rate 630 for level controller 626 may be obtained via operational or computer algorithm input. Output from regulator 632 is signal 634 which is scaled to be representative of the position of control valve 522 required to maintain the desired flow rate in conduit 438 to maintain the desired level in 67.

Although various control techniques are readily available to control the flow rate of stripping steam to column 67 via conduit 430, a preferred technique is based on the temperature of the returned steam. A temperature transducing device 636 in combination with a sensing device such as a thermocouple located in conduit 430 provides an input signal 638 to a temperature controller 642. Also provided to the controller by operating or computer algorithm is a set point temperature signal 640. The controller 642 is responsive to the differences between the two inputs and transmits a signal 644 to the flow control valve 526 located in a conduit containing the heating medium, preferably conduits 440 or 444, most preferably conduit 444 as illustrated. The transmitted signal 644 is scaled to be representative of the position of the control valve 526 required to maintain the flow rate necessary to achieve the desired temperature in pipeline 440.

A novel aspect of the methane stripping column is the manner in which reflux liquids are generated. As illustrated in Figure 2, the overhead product exits the methane removal column 67 via pipeline 410 where at least a portion of the stream is partially condensed by flow through indirect heat exchange device 510 in heat exchanger 62 which is cooled via the heavy-residue-rich liquid product from the heavy-residue suspension column 60.1 a preferred embodiment, the heavy-residue-rich liquid product is first used for cooling at least part of the overhead steam stream and then used for cooling the methane-rich stripping gas stream. The condensed liquids obtained from cooling via the heavy-residue-rich liquid stream become the source of reflux for methane removal column 67. Preferably, the heat exchange between the two designated streams occurs in countercurrent. In one embodiment, the entire stream can flow to heat exchanger 62 in a manner as previously stated for the cooling of the entire methane stripping gas. In a preferred embodiment illustrated in Figure 2, the overhead steam product in pipeline 410 is split into streams flowing in pipelines 412 and 414. The stream in pipeline 414 is cooled in heat exchanger 62 by flowing the stream through indirect heat exchange device 510 in exchanger 62 and the resulting cooled stream is produced via pipeline 418. The relative flow rates of the steam streams in pipelines 412 and 414 or 418 are regulated by a flow control device, preferably a flow control valve through which overhead steam can flow without flowing through the heat exchanger to thereby avoid the regulation of a two-phase fluid. Steam flowing in conduit 412 flows through flow control device 512 and is produced from there via conduit 416. Conduits 416 and 418 are then joined, resulting in a combined cooled two-phase flow flowing through conduit 420. Located within conduit 420 is a temperature transducing device 646 , in combination with a temperature sensing device, preferably a thermocouple, which provides a signal 648 that is representative of the real temperature of the fluid flowing in pipeline 420 to temperature regulator 652. A desired temperature 650 is also fed to regulator 652, either manually or via a calculation algorithm . Based on comparison of the input via the transducing device 646 and the set point 650, the controller 652 then provides an output signal 654 to the valve 512 which is scaled to manipulate the valve 512 in an appropriate manner so that the set point temperature is reached or maintained. The resulting two-phase fluid in pipeline 420 is then fed to separator 514 from which a methane-rich vapor stream via pipeline 422 and a reflux liquid stream via pipeline 424 are produced. In another preferred embodiment, the preceding methodology is used, but the heavy-residue-rich stream in pipeline 117 is first used for cooling the stream delivered via pipeline 414 before cooling the stream delivered via pipeline 414. As illustrated in Figure 1, the methane-rich vapor stream in pipeline 121 can be returned to the open methane cycle for subsequent liquefaction. The pressure on the methane remover and associated equipment is regulated by automatic manipulation of control valve 518 in response to a pressure transducer device 656 which is operatively located in pipeline 422. The control valve is interconnected on the inlet side of pipeline 422 and on the outlet side of pipeline 121 which is preferably directly or indirectly connected to low pressure the inlet opening of the methane compressor, and the pressure transducing device 656 in combination with a sensing device provides a signal 658 to a pressure regulator 660 which is representative of the real pressure in pipeline 422. A set point pressure signal 662 is also provided as an input to the pressure regulator 660. The regulator then generates a response signal 664 which is representative of the difference between the pressure sensing device signal 658 and the set point signal 662. Signal 664 is scaled in such a way as to actuate the valve 518 to approach and maintain the set point pressure. In one embodiment, the regulator and the control valve and optionally the pressure-sensing transducer 656 are approximated in a single device which is usually called a back pressure regulator.

The reflux from the separator finally flows to the methane remover. In the preferred embodiment illustrated in Figure 2, the reflux leaves the separator 514 via line 424, flows through pump 516, and then flows through line 425, control valve 519, and line 426 whereupon the stream is introduced into the upper section of the methane removal column. In this embodiment, the flow rate of the return is regulated via input from a level control device 666 which is responsive to a sensing device located in the lower section of the separator 514. Controller 666 generates a signal

668 which is representative of the flow rate in conduit 426 which is

necessary to maintain the desired level in separator 514, signal 668 is provided as a set point input to flow controller 670 to which is also fed a signal 671 representing the actual flow rate in pipeline 425. Controller 670 then generates a signal 674 to control valve 519 which is representative for the difference in signals and scaled to provide the appropriate fluid flow through flow control valve 519 so that the fluid level in separator 514 is regulated.

The controllers previously discussed can use various well-known control modes such as proportional, proportional-integral or proportional-integral-derivative (PID). A digital computer having backup accommodations is preferred in the preferred embodiment depicted in Figure 4 for calculating the required control signals based on measured process variables and set points supplied to the computer. Any digital computer that has software for reading values of external variables and transmitting signals to external devices is suitable for use. The PID controllers shown in figures 2, 3 and 4 can use the different ways of regulation such as proportional, proportional-integral or proportional-integral-derivative. In the preferred embodiment, a proportional-integral method is used. However, any regulator capable of accepting two or more input signals and producing a scaled output signal representative of the comparison of the two input signals is within the scope of the invention.

The scaling of an output signal by a regulator is well known in the field of regulation systems. Essentially, the output of a regulator can be scaled to represent any desired factor or variable. An example of this is where a desired temperature and an actual temperature are compared with the regulator. The output of the regulator may be a signal representative of a flow rate of a "control" gas necessary to make the desired and actual temperatures equal. On the other hand, the same output signal could be scaled to represent a pressure required to make the desired and actual temperatures equal. If the control output could be in the range 0-10 units, then the control output signal could be scaled so that an output with a level of 5 units corresponds to 50% or a specified flow rate or a specified temperature. The transducing device used to measure parameters that characterize a process in the various signals generated thereby can have a number of shapes or formats. E.g. can the control elements in this system be implemented using electrical analogue, digital electronic, pneumatic, hydraulic, mechanical or other similar types of equipment or a combination of such types of equipment.

Selective control loops are used in a number of process situations to select an appropriate control action. Typically, a normal control signal is overridden by a second control signal that has a higher priority in case of certain process conditions. E.g. dangerous conditions can be avoided, or desirable features such as automatic start-up can be implemented by temporarily selecting a second control signal.

The specific hardware and/or software used in such feedback control systems are well known in the area of process plant control. Compare e.g. Chemical Engineering's Handbook, 5th Edition, McGraw-Hill, pages 22-1 to 22-147.

While specific cryogenic methods, materials, devices or equipment and regulatory instruments are referred to herein, it is to be understood that such specific recitations are not to be considered limiting, but are intended to be illustrative and set forth for a best manner according to the present invention.

EXAMPLE I

This example shows via computer simulation the effectiveness of the process described in the description for the removal of benzene and heavier components from a methane-based stream immediately before liquefaction of the methane-based stream in a significant proportion. The flow rates are representative of those existing in a 2.5 million tonne/year LNG facility using the liquefaction technology shown in Figures 1 and 2. The benzene concentrations in the methane-based gas streams used in this example are considered to be representative of the concentrations which exists for the many natural gas streams at this point in the process. However, the methane-based gas streams are considered to be relatively lean with regard to heavier hydrocarbon components (ie C3+). Simulation results were obtained using Hyproteck's Process Simulation HYSIM, version 386/C2.10, Prop. Pkg PR/LK.

Shown in Table 1 are the composition, temperature, pressure and phase conditions of the inlet streams and outlet streams of the heavy-residue removal column. The simulation is based on the column containing 5 theoretical steps. The partially condensed stream, also referred to as the two-phase stream, which will later undergo significant liquefaction, is first fed to the top stage of the column (stage 1). The temperature of this stream is -80.3°C and the pressure is 587.0 psia. As previously stated, this stream has undergone partial condensation so that the stream is 98.24 mol% steam.

The cooled methane-rich strip gas fed to the bottom stage (stage 5) is taken from the upstream location shown in Figure 1. This stream is cooled from approximately 17°C to -23°C via countercurrent heat exchange with the heavy-residue-rich liquid stream produced from stage 5.1 during such heat exchange as shown in Figure 2, this flow is heated from approximately -61°C to approximately 17°C. This stream can also be used to cool the overhead vapors from the methane removal column. Shown in Table 2 are the simulated temperatures, pressures and relative flow rates for each phase on a stepwise basis inside the column. Shown in Table 3 for each step are the respective liquid and vapor equilibrium compositions.

The heated heavy-residue-rich stream is then fed to the methane removal column containing rectification and stripping sections from which a methane/ethane-rich stream is produced which is preferably recycled as feed to the high-stage inlet of the methane compressor and a stream rich in natural gas liquids.

The efficiency of the process for removing aromatics/heavier components is illustrated by a comparison of the combined nitrogen, methane and ethane mole percentages in the feed streams of stages 1 and 5 and the product from stage 1. These percentages for each stream are 99.88, 99 respectively .89 and 99.94 mol%. The process therefore produces a product that is significantly enriched with these light components than for both of the two gaseous feed streams.

The efficiency of the process for removing benzene and heavier aromatics is illustrated by a comparison of enrichment ratios defined as the mole percent of the component in the liquid product from step 5 divided by the mole percent of the component in the vapor product from step 1. Using benzene as an example, the respective mole fractions 0.1616E-04 and 0.00352. This results in an enrichment ratio of approximately 220.

A further basis for illustrating the efficiency of the process is the enrichment ratio of the C3+ components in the feed streams to stages 1 and 5 and the liquid product stream produced from stage 1. This ratio varies from approx. 45 for propane to approx. 200 for n-octane. The respective ratios between the product streams vary from approx. 50 for propane to approx. 20,000 for n-octane.

EXAMPLE II

This example, like the previous one, shows via computer simulation the effectiveness of the process described in the description for the removal of benzene and heavier components from a methane-based gas stream immediately before liquefaction of the stream in a significant proportion. The flow rates are representative of those existing in a 2.5 million ton/year LNG plant using the liquefaction technology shown in Figures 1 and 2. The benzene concentrations in the methane-rich feed streams used in this example are considered to be representative of the concentrations which exist for many gas streams at this point in the process. However, the concentrations of ethane and heavier components in the gas stream have been increased significantly to thereby represent a richer gas stream, which places a greater burden on the process for the removal of both these components and benzene. This example illustrates in more detail the ability of the process to remove benzene and heavier hydrocarbon components simultaneously. In addition, this example illustrates the ability of the benzene removal process to tolerate significant process upsets in the form of significant increases in ethane and heavier hydrocarbon concentrations without significantly affecting the efficiency and operation of the benzene removal process. Furthermore, this example illustrates the ability of the process to recover heavier hydrocarbons as a separate, liquid stream. Simulation results were obtained using Hyprotech's Process Simulation HYSIM, version 386/C2.10, Prop. Pkg

PR/LK.

Shown in Table 4 are the composition, temperature, pressure and phase conditions of the inlet streams and outlet streams of the heavy-residue suspension column. The simulation is based on the column containing 5 theoretical steps. The partially condensed stream, also referred to as the two-phase stream, which will undergo significant liquefaction, is first fed to the top stage of the column (stage 1). The temperature of this stream is -68.4°C and the pressure is 596.0 psia. As stated in the description, this stream has undergone partial condensation so that the stream is 94.04 mol% steam.

The methane-rich stripping stream fed to the bottom stage (stage 5) is taken from the upstream location shown in Figure 1. This stream is cooled from approximately -23°C via countercurrent heat exchange with the liquid product stream produced from stage 5. As indicated in Table 4, this stream has underwent partial condensation during cooling.

Shown in Table 5 are the simulated temperatures, pressures and relative flow rates for each phase on a stepwise basis inside the column. Shown in Table 6 for each stage are the respective liquid and vapor equilibrium compositions.

The efficiency of the process for the removal of heavier components is illustrated by a comparison of the combined nitrogen, methane and ethanol mole percentages in the feed streams respectively to stages 1 and 5 and the product stage from stage 1. These percentages are respectively 97.85, 97.30 and 99, 37 mol%. The process produces a product stream that is significantly enriched with these components than for either of the two gaseous feed streams.

The efficiency of the process for removing benzene and heavier aromatics is illustrated by a comparison of enrichment ratios which for benzene are as defined in example 1. The respective mole fractions are 0.003E-04 and 0.00923, which thus results in an enrichment ratio of approximately 30.

A further basis for illustrating the efficiency of the process is the enrichment ratios for the C3+ components in the feed streams to stages 1 and 5 and the liquid product stream produced from stage 1. This ratio varies from approx.

19 for propane to approx. 30 for n-octane. The respective ratios between the product streams vary from approx. 67 for propane to approx. 19,000 for n-octane.

Claims (47)

1. Process for the removal and concentration of higher molecular weight hydrocarbons from a methane-based gas stream, characterized in that it comprises the steps of: (a) condensing a minor portion of the methane-based gas stream to thereby produce a two-phase stream; (b) feeding the two-phase stream to the upper section of a column; (c) removing from the upper section of the column a heavy-residue-reduced gas stream; (d) removing from the lower section of the column a heavy-residue-rich liquid stream; (e) contact treatment via indirect heat exchange of the heavy-residue-rich liquid stream with a methane-rich stripping gas stream to thereby produce a heated heavy-residue-rich stream and a cooled methane-rich stripping gas stream; (f) feeding the cooled methane-rich strip gas stream to the lower section of the column; and (g) contacting the two-phase stream and the cooled methane-rich strip gas stream in the column to thereby produce the heavy-residue-reduced gas stream and the heavy-residue-rich liquid stream. 2. Procedure as stated in claim 1, characterized in that step (a) consists of splitting the methane-based gas stream into a first stream and a second stream, cooling the first stream to thereby produce a partially condensed first stream, and combining the partially condensed first stream with the second the current to thereby produce the two-phase current. 3. Procedure as stated in claim 2, characterized in that the quantity of liquids in the two-phase flow is regulated by determining for the methane-based gas flow a two-phase flow temperature that corresponds to the desired liquid content under equilibrium conditions, measurement of the temperature of the two-phase flow, maintaining a constant flow rate of the first stream and the amount of cooling provided to the stream, and adjusting the flow rate of the second stream in response to the two-phase stream temperature so that it approaches the calculated two-phase stream temperature. 4. Procedure as stated in claim 1, characterized in that it further comprises step (h) sequentially cooling the methane-based gas stream prior to step (a) by passing the gas stream through at least one indirect heat exchange device in contact with a first refrigerant stream to produce a cooled methane-based gas stream and passing the cooled methane-based gas stream through at least one indirect heat exchange device in contact with a second refrigerant stream where the boiling point of the second refrigerant stream is less than the boiling point of the first refrigerant stream to thereby produce the feed stream to step (a). 5. Procedure as stated in claim 4, characterized in that the first coolant stream consists mainly of propane and the second coolant stream mainly consists of ethane, ethylene or a mixture thereof. 6. Procedure as stated in claim 4, characterized in that it further comprises: (i) withdrawing a sidestream from the methane-based gas stream at a location downstream of one of the indirect heat exchange devices and using the sidestream as the methane-rich stripping gas in step (e). 7. Procedure as stated in claim 4, characterized in that the cooling with at least one indirect heat exchange device in contact with a first coolant flow consists of passing the gas flow to be cooled through two or more indirect heat exchange devices in a sequential manner and where the first coolant of each such indirect heat exchange device has been flashed to a progressively lower temperature and pressure in a sequential manner and wherein the cooling with at least one indirect heat exchange device in contact with a second refrigerant stream consists of passing the gas stream to be cooled through two or more indirect heat exchange devices in a sequential manner and wherein the second refrigerant of each indirect heat exchange device has been flashed to a progressively lower temperature and pressure in a sequential manner. 8. Procedure as stated in claim 7, characterized in that three indirect heat exchange devices are used for cooling with the first coolant flow and two or three indirect heat exchange devices are used for cooling with the second coolant flow, where the pressure of the methane-based feed gas is 500-900 psia, especially 575-650 psia. 9. Procedure as stated in claim 1, characterized in that it further comprises: (h) feeding the heated heavy-residue-rich stream in step (e) to a methane remover consisting of a fractionating column, an evaporator and a condenser to thereby produce a heavy-residue-rich liquid stream and a methane-rich steam stream. 10. Procedure as stated in claim 9, characterized in that a significant proportion of the cooling performance of the condenser is obtained from the heavy-residue-rich liquid stream produced in step (d) or step (e), and/or by flow through an indirect heat exchange device in contact with the heavy-residue-rich liquid stream in step (d) and the resulting treated heavy-residue-rich liquid stream becomes the heavy-residue-bearing feed stream to step (e). 11. Procedure as specified in claim 10, characterized in that the cooling performance is obtained by splitting the peak vapor stream into a first vapor stream and a second vapor stream, cooling and partial condensation of the first stream via indirect heat exchange with the heavy-residue-rich liquid stream in step (d) to thereby produce a cooled, partially condensed first stream, combining the first stream and the second stream, feeding the combined stream to a gas-liquid separator from which the reflux stream to the fractionation column and the methane-rich vapor stream are produced. 12. Procedure as stated in claim 11, characterized in that the flow rate of the reflux stream is regulated by calculating for the peak vapor stream a two-phase stream temperature corresponding to the desired liquid content at equilibrium conditions, measuring the temperature of the two-phase stream, maintaining a constant flow rate of the first stream and the amount of cooling provided to the stream, and adjusting the flow rate of the second the current in response to the two-phase current temperature so that the calculated two-phase current temperature is reached. 13. Procedure as specified in claim 10, characterized in that it comprises between steps (d) and (e) the further steps: (i) flashing of the heavy-residue-rich liquid stream to a lower pressure in order to thereby further lower the temperature of the stream. 14. Procedure as specified in claim 13, characterized in that it further comprises step (j) condensing the heavy-residue-reduced gas stream to thereby produce a liquid natural gas stream. 15. Procedure as specified in claim 14, characterized in that the condensation consists in the heavy-residue-reduced gas stream being passed through an indirect heat exchange device cooled with the second refrigerant stream, where the pressure on the methane-based gas stream is 500-900 psia. 16. Procedure as stated in claim 15, characterized in that it further comprises the steps (k) flashing the liquid product in step G) in one or more steps to approximately atmospheric pressure to thereby produce an LNG product stream and one or more methane vapor streams; (1) compressing the majority of the vapor streams in step (k) to a pressure of 500-900 psia, (m) cooling the compressed vapor stream in step (1); and (n) combining the resulting cooled stream with the methane-based gas stream fed to step (a) or the resulting product from one of the indirect heat exchange devices of step (h). 17. Procedure as stated in claim 16, characterized in that the methane-rich steam flow in step (h) is combined with one of the steam flows in step (k) before step (1), particularly where the pressure of the methane-based feed gas and the gas flow from step (1) is 575-650 psia. 18. Method as stated in claim 1 and/or 17, characterized in that the column is supplied with two to fifteen theoretical stages for gas-liquid contact, in particular with three to ten theoretical stages. 19. Method for removing benzene and other aromatics from a methane-based gas stream, characterized in that it consists of the steps: (a) condensing a minor portion of the methane-based gas stream to thereby produce a two-phase stream; (b) feeding the two-phase stream to the upper section of a column; (c) removing from the upper section of the column a benzene/aromatic reduced gas stream; (d) removing from the lower section of the column a benzene/aromatic liquid stream; (e) contacting via indirect heat exchange of the benzene/aromatic liquid stream with a methane-rich stripping gas stream to thereby produce a heated benzene/aromatic stream and a cooled methane-rich stripping gas stream; (f) feeding the cooled methane-rich strip gas stream to the lower section of the column; and (g) contacting the two-phase stream and the cooled methane-rich strip gas stream in the column to thereby produce the benzene/aromatic reduced gas stream and the benzene/aromatic liquid stream. 20. Procedure as stated in claim 19, characterized in that step (a) consists of splitting the methane-based gas stream into a first stream and a second stream, cooling the first stream to thereby produce a partially condensed first stream, and combining the partially condensed first stream with the second the current to thereby produce the two-phase current. 21. Procedure as stated in claim 20, characterized in that the amount of liquids in the two-phase stream is regulated by determining for the methane-based gas stream a two-phase stream temperature that corresponds to the desired liquid content at equilibrium conditions, measuring the temperature of the two-phase stream, maintaining a constant flow rate of the first stream and the amount of cooling given to the stream, and adjusting of the flow rate of the second stream in response to the two-phase flow temperature so that this approaches the calculated two-phase flow temperature. 22. Procedure as stated in claim 19, characterized in that it further comprises the step (h) sequential cooling of the methane-based gas stream before step (a) by passing the gas stream through at least one indirect heat exchange device in contact with a first refrigerant stream to thereby produce a cooled methane-based gas stream and passing the cooled methane-based gas stream the gas stream through at least one indirect heat exchange device in contact with a second refrigerant stream where the boiling point of the second refrigerant stream is less than the boiling point of the first refrigerant stream to thereby produce the feed stream to step (a). 23. Procedure as stated in claim 22, characterized in that the first coolant stream consists mainly of propane and the second coolant stream mainly consists of ethane, ethylene or a mixture thereof. 24. Procedure as stated in claim 22, characterized in that it further comprises: (i) withdrawing a sidestream from the methane-based gas stream at a location downstream of one of the indirect heat exchange devices and using the sidestream as the methane-rich stripping gas in step (e). 25. Procedure as stated in claim 22, characterized in that the cooling with at least one indirect heat exchange device in contact with a first coolant flow consists of passing the gas flow to be cooled through two or more indirect heat exchange devices in a sequential manner and where the first coolant of each such indirect heat exchange device has been flashed to a progressively lower temperature and pressure in a sequential manner and wherein the cooling with at least one indirect heat exchange device in contact with a second refrigerant stream consists of passing the gas stream to be cooled through two or more indirect heat exchange devices in a sequential manner and wherein the second refrigerant of each indirect heat exchange device is been flashed to a progressively lower temperature and pressure in a sequential manner. 26. Procedure as stated in claim 25, characterized in that three indirect heat exchange devices are used for cooling with the first coolant flow and two or three indirect heat exchange devices are used for cooling with the second coolant flow, where the pressure of the methane-based feed gas is 500-900 psia, especially 575-650 psia. 27. Procedure as stated in claim 19, characterized in that it further comprises: v (h) feeding the heated benzene/aromatic stream in step (e) to a methane remover consisting of a fractionating column, an evaporator and a condenser to thereby produce a benzene/aromatic liquid stream and a methane-rich steam flow. 28. Procedure as stated in claim 27, characterized in that a major proportion of the cooling performance of the condenser is obtained from the benzene/aromatic liquid stream produced in step (d) or step (e), and/or is obtained by flowing through an indirect heat exchange device in contact with the benzene/aromatic liquid stream of step (d) and the resulting treated benzene/aromatic liquid stream becomes the benzene/aromatic-bearing feed stream of step (e). 29. Procedure as stated in claim 28, characterized in that the cooling performance is obtained by splitting the peak vapor stream into a first vapor stream and a second vapor stream, cooling and partially condensing the first stream via indirect heat exchange with the benzene/aromatic liquid stream in step (d) to thereby produce a cooled, partially condensed first stream, combining the first stream and the second stream, feeding the combined stream to a gas-liquid separator from which the reflux stream to the fractionation column and the methane-rich vapor stream are produced, where the flow rate of the reflux stream is regulated by calculating for the peak vapor stream a two-phase flow temperature corresponding to the desired the liquid content at equilibrium conditions, measuring the temperature of the two-phase stream, maintaining a constant flow rate of the first stream and the amount of cooling provided to the stream, and adjusting the flow rate of the second stream in response to the two-phase stream temperature so that the calculated tof the ash flow temperature is reached. 30. Procedure as stated in claim 28, characterized in that it further comprises between steps (d) and (e) the further steps: (i) flashing the benzene/aromatic liquid stream to a lower pressure to thereby further lower the temperature of the stream, (j) condensing the benzene/ aromatics-reduced gas flow to thereby produce a liquid natural gas flow. 31. Procedure as stated in claim 30, characterized in that the condensation consists in the benzene/aromatic-reduced gas stream being passed through an indirect heat exchange device cooled with the second refrigerant stream, where the pressure on the methane-based gas stream is 500-900 psia. 32. Procedure as stated in claim 31, characterized in that it further comprises the steps of: (k) flashing the liquid product of step (j) in one or more steps to approximately atmospheric pressure to thereby produce an LNG product stream and one or more methane vapor streams; (1) compressing the majority of the vapor streams in step (k) to a pressure of 500-900 psia, (m) cooling the compressed vapor stream in step (1); and (n) combining the resulting cooled stream with the methane-based gas stream fed to step (a) or the resulting product from one of the indirect heat exchange devices of step (h). 33. Procedure as stated in claim 32, characterized in that the methane-rich steam flow in step (h) is combined with one of the steam flows in step (k) before step (o), in particular where the pressure on the methane-based feed gas and the gas flow from step (1) is 575-650 psia. 34. Method as stated in claim 19 and/or 33, characterized in that the column is provided with two to fifteen theoretical stages for gas-liquid contact, in particular with three to ten theoretical stages. 35. Apparatus for carrying out the method according to claim 1 or 19, characterized in that it comprises: (a) a capacitor (54); (b) a column (60); (c) a heat exchanger (62) providing indirect heat exchange between two fluids; (d) a conduit (118,458) between the condenser (54) and the upper section of the column (60) for the flow of a two-phase current to the column (60); (e) a second conduit (120) connected to the upper section of the column (60) for the removal of a vapor stream from the column (60); (f) a conduit (109,405) between the column (60) and the heat exchanger (62) for the flow of a cooled gas stream from the heat exchanger (62); (g) a conduit (114,117) between the column (60) and the heat exchanger (62) for the flow of a liquid stream from the column (60); (h) a conduit (119) connected to the heat exchanger (62) for the flow of a heated liquid stream from the heat exchanger (62); and (i) a conduit (108,400,403,404) connected to the heat exchanger (62) for flow of a gas stream to the heat exchanger (62); and optionally a pressure reduction device (97) located in the pipeline (g) (114,117). 36. Apparatus as specified in claim 35, characterized in that it further comprises (j) a first pipeline (116); (k) a splitter connected to the first conduit (116); (1) a second conduit (452) and a third conduit (450,454) connected to the split device wherein the third conduit (450,454) is connected to the condenser (54); (m) a control valve (530) connected at the inlet side of the second pipeline (452); (n) a pipeline (456) connected at the outlet side of the control valve (530); (o) a connecting or combining device connected to the pipeline (456) in item (n) and the pipeline (118,458) in item (d) prior to the connection with the column; (p) a temperature sensor (688) with a sensing element located in the pipeline (118) in point (d) between the connection device and the connection with the column (60); and (q) a control device (682) operatively attached to the control valve (530) and operative in response to input received from the temperature sensing device (688) at point (p) and a temperature set point. 37. Apparatus as specified in claim 35, characterized in that the column contains 2-12 theoretical stages, in particular that it further comprises two or more indirect heat exchange devices (6,24,30,44) placed in a sequential manner, pipelines (102,104,106,110,112,116) between each heat exchange device for the sequential flow of a common fluid through the heat exchangers whereupon the last pipeline (116) is connected to the condenser (54) in point (a), pipelines (212,214,218,304,306,308,310,311,314,316,320) to and from each heat exchanger which ensures the flow of a refrigerant to each heat exchanger and where the pipeline (108,400,403,404) in point (i) is in flow communication with one of the aforementioned pipelines for the flow of a common fluid between the heat exchangers, particularly where propane is used as the refrigerant in at least one of the heat exchange devices; and ethane, ethylene or a mixture thereof are used as coolants in at least one of the heat exchange devices. 38. Apparatus as specified in claim 35, characterized in that it further comprises: (j) a fractionation column (67); (k) an evaporator (524); (1) a second capacitor (62,418,420,510,514); (m) an overhead product line (410,414) connecting the upper section of the fractionating column (67) to the condenser (62,418,420,510,514) for removing the overhead vapor, a reflux line (424,425,426) connecting the condenser (62,418,420,510,514) to the fractionating column (67) for returning the reflux fluid , a vapor product line (121,422) connected to the condenser (62,418,420,510,514) for removing uncondensed vapors; (n) a bottoms line (428) connecting the lower section of the fractionating column (67) to the evaporator (524), a steam line (430) for returning stripping steam to the fractionating column (67), and a bottoms line (432) connected to the evaporator (524 ) for removing unvaporized product from the evaporator (524); and where the pipeline (119) in point (h) is connected to the fractionation column (67) at a point between the theoretical steps from top to bottom, in particular where the condenser (62,418,420,510,514) in point (1) consists of an indirect heat exchange device (510), where coolant for such a device is obtained by a connection connecting the cooling side of the indirect heat exchange device to the pipeline (114,117) in point (g) 39. Apparatus as specified in claim 38, characterized in that it further includes (0) a pressure reduction device (97) located in conduit (g) (114,117); or (p) a conduit (116) connected to the condenser in point (a). (q) a compressor (83) connected at the inlet opening of the steam pipeline (121,140) in point (m); and (r) a pipeline connecting the outlet opening of the compressor element (p) (83) to the pipeline (116) in point (o). 40. Apparatus as specified in claim 37, characterized in that it further comprises: (j) a fractionation column (67); (k) an evaporator (524); (1) a second capacitor (62,418,420,510,514); (m) an overhead product line (410,414) connecting the upper section of the fractionating column (67) to the condenser (62,418,420,510,514) for removing the overhead vapor, a reflux line (424,425,426) connecting the condenser (62,418,420,510,514) to the fractionating column (67) for returning the reflux fluid , a vapor product line (121,422) connected to the condenser (62,418,420,510,514) for removing uncondensed vapors; (n) a bottoms line (428) connecting the lower section of the fractionating column (67) to the evaporator (524), a steam line (430) for returning stripping steam to the fractionating column (67), and a bottoms line (432) connected to the evaporator (524 ) for removing unvaporized product from the evaporator (524); and where the pipeline (119) in point (h) is connected to the fractionation column (67) at a midpoint location, in particular where the apparatus further comprises (o) a compressor (83) connected at the inlet opening to the steam pipeline in point (m) (121,422) and (p) pipeline connecting the outlet opening of the compressor to one of the common flow pipelines (102,104,106,110,112,116) in claim 37. 41. Apparatus for carrying out the method according to claim 1 or 19, characterized in that it comprises: (a) a cryogenic separation column (60) for partial condensation of a feed gas stream in an LNG extraction process; (b) means (114,117) for withdrawing a liquid condensate stream from the cryogenic separation column (60); (c) a heat exchanger (62) associated with the cryogenic separation column (60); (d) means for guiding the liquid condensate flow through the heat exchanger; (e) means for passing a hot dry gas stream through the heat exchanger (62) and then to the cryogenic separation column (60), where the hot dry gas stream is cooled by indirect heat exchange with the liquid condensate stream in the heat exchanger; (f) a bypass conduit (718) having a first control valve (534) operatively located therein for bypassing the hot dry gas stream around the heat exchanger (62); (g) means (702) for establishing a first signal (706) representative of the actual temperature of the hot dry gas stream exiting the heat exchanger (62); (h) means (704) for establishing a second signal (708) representative of the actual temperature of the liquid condensate stream entering the heat exchanger (62); (i) means (700) for dividing the first signal (706) by the second signal (708) to establish a third signal (710) which is representative of the relationship between the first signal (706) and the second signal (708) ); (j) means for establishing a fourth signal (714) which is representative of a desired value for the ratio represented by the third signal (710); (k) means (712) for comparing the third signal (710) and the fourth signal (714) and establishing a fifth signal (716) which is responsive to the difference between the third signal (710) and the fourth signal ( 714), wherein the fifth signal (716) is scaled to be representative of the position of the first control valve (534) necessary to maintain the actual ratio represented by the third signal (710) substantially equal to the desired ratio represented by the fourth signal (714); and (m) means for regulating the first control valve (534) in the bypass pipeline (718) in response to the fifth signal (716). 42. Apparatus as specified in claim 41, characterized in that it further comprises: device (600) for establishing a sixth signal (602) which is scaled to be representative of the flow rate of the liquid condensate stream necessary to maintain a desired liquid level in the cryogenic separation column (60); means (97,608,614) for regulating the flow rate of the liquid condensate stream in response to the sixth signal; in particular where the apparatus further comprises: a second control valve (536) operatively positioned to regulate flow of the hot dry gas stream; and means (728,730) for manipulating the second control valve in response to the temperature selected from the pair of temperatures consisting of: i. the actual temperature of the hot dry gas stream exiting the heat exchanger; and ii. the actual temperature of the liquid condensate stream exiting the heat exchanger. 43. Apparatus as specified in claim 42, characterized in that the devices for regulating the second control valve (536) comprise: device (734) for establishing a seventh signal (736) which is representative of the real temperature of the liquid condensate stream exiting the heat exchanger (62); means for establishing an eighth signal (740) representative of the desired temperature of the liquid condensate stream exiting the heat exchanger; means (738) for comparing the seventh signal (736) and the eighth signal (740) to establish a ninth signal (742) in response to the difference between the seventh signal (736) and the eighth signal (740), wherein the ninth signal (742) is scaled to be representative of the position of the second control valve (536) necessary to maintain the actual temperature of the liquid condensate stream exiting the heat exchanger (62) represented by the seventh signal (736) which in total is substantially equal to the desired temperature represented by the eighth signal (740); device for establishing a tenth signal (724) which is representative of the desired temperature of the hot the dry gas stream exiting the heat exchanger (62) represented by the first signal (706); means (722) for comparing the first signal (706) and the tenth signal (724) to establish an eleventh signal (726) in response to the difference between the first signal (706) and the tenth signal (724), wherein the eleventh signal (726) is scaled to be representative of the position of the second control valve (536) necessary to maintain the actual temperature of the hot dry gas stream exiting the heat exchanger substantially equal to the desired value represented by the tenth signal (724); means (728) for establishing a twelfth signal (730) selected as the one of the ninth signal (742) and the eleventh signal (726) having the higher value; and means for regulating the second regulating valve (536) in response to the twelfth signal (730). 44. Method for regulating the temperature in a heat exchanger equipped with a bypass pipeline having a first control valve operatively connected therein, which heat exchanger is associated with a cryogenic separation column that removes a benzene contaminant from a feed stream in an LNG extraction process, characterized in that it comprises: withdrawing a liquid condensate stream at a cryogenic temperature from the cryogenic separation column; routing the liquid condensate flow through the heat exchanger; passing a hot dry gas stream through the heat exchanger and then introducing the hot dry gas stream into the cryogenic separation column, where the hot dry gas stream is cooled by indirect heat exchange with the liquid condensate stream in the heat exchanger; establishing a first signal representative of the actual temperature of the hot dry gas stream exiting the heat exchanger; establishing a second signal representative of the actual temperature of the liquid condensate stream entering the heat exchanger; dividing the first signal by the second signal to establish a third signal representative of the ratio of the first signal to the second signal; establishing a fourth signal representative of the desired value of the third signal; comparing the third signal and the fourth signal and establishing a fifth signal responsive to the difference between the third signal and the fourth signal, the fifth signal being scaled to be representative of the position of the first control valve necessary to maintaining the actual ratio represented by the third signal to be substantially similar to the desired ratio represented by the fourth signal; and regulating the first control valve in the bypass pipeline in response to the fifth signal. 45. Procedure as stated in claim 44, characterized in that it further comprises the following steps: establishing a sixth signal scaled to be representative of the flow rate of the liquid condensate stream necessary to maintain a desired liquid level in the cryogenic separation column; and regulating the flow rate of the liquid condensate stream in response to the sixth signal. 46. Procedure as stated in claim 44, characterized in that a second control valve is operatively positioned to control the flow rate of the hot dry gas stream, further comprising the steps of: controlling the second control valve in response to a temperature selected from the pair of temperatures consisting of: i) the actual temperature of the hot dry gas stream exiting the heat exchanger; and ii) the actual temperature of the liquid condensate stream exiting the heat exchanger. 47. Procedure as specified in claim 46, characterized in that the steps for regulating the second regulating valve comprise: establishing a seventh signal representative of the actual temperature of the liquid condensate stream exiting the heat exchanger; establishing an eighth signal representative of the actual temperature of the liquid condensate stream exiting the heat exchanger; comparing the seventh signal and the eighth signal to establish a ninth signal in response to the difference between the seventh signal and the eighth signal, the ninth signal being scaled to be representative of the position of the second control valve necessary to maintain the the actual temperature of the liquid condensate stream exiting the heat exchanger represented by the seventh signal which is substantially equal to the desired temperature represented by the eighth signal; establishing a tenth signal representative of the desired temperature of the hot dry gas stream exiting the heat exchanger represented by the second signal; comparing the second signal and the tenth signal to establish an eleventh signal in response to the difference between the second signal and the tenth signal, the eleventh signal being scaled to be representative of the position of the second control valve necessary to maintain the the actual temperature of the hot dry gas stream exiting the heat exchanger substantially equal to the desired value represented by the tenth signal; establishing a twelfth signal selected as one of the ninth signal and the eleventh signal having the higher value; and regulating the second control valve in response to the twelfth signal.