Patent Publication Number: US-2007107465-A1

Title: Apparatus for the liquefaction of gas and methods relating to same

Description:
CROSS REFERENCE TO RELATED APPLICATIONS  
      This application is a continuation-in-part of U.S. patent application Ser. No. 11/124,589 filed on May 5, 2005, which is a continuation of U.S. patent application Ser. No. 10/414,991 filed on Apr. 14, 2003, now U.S. Pat. No. 6,962,061 issued on Nov. 8, 2005, which is a divisional of U.S. patent application Ser. No. 10/086,066 filed on Feb. 27, 2002, now U.S. Pat. No. 6,581,409 issued on Jun. 24, 2003 and which claims the benefit of U.S. Provisional Patent Application Ser. No. 60/288,985, filed May 4, 2001. This application is also a continuation in part of U.S. patent application Ser. No. 11/381,904 filed on May 5, 2006, entitled APPARATUS FOR THE LIQUEFACTION OF NATURAL GAS AND METHODS RELATING TO SAME which is also a continuation-in-part of the above-referenced U.S. patent application Ser. No. 11/124,589 filed on May 5, 2005. Further, this application is a continuation-in-part of U.S. patent application Ser. No. 11/383,411, filed on May 15, 2006, entitled APPARATUS FOR THE LIQUEFACTION OF NATURAL GAS AND METHODS RELATING TO SAME which is also a continuation-in-part of the above-referenced U.S. patent application Ser. No. 11/124,589 filed on May 5, 2005, and U.S. patent application Ser. No. 11/381,904 filed on May 5, 2006. Additionally, this application is a continuation in part of U.S. application Ser. No. 11/536,477 filed on Sep. 28, 2006, entitled APPARATUS FOR THE LIQUEFACTION OF NATURAL GAS AND METHODS RELATING TO SAME which is also a continuation-in-part of the above-referenced U.S. patent application Ser. No. 11/124,589 filed on May 5, 2005, and U.S. patent application Ser. No. 11/381,904 filed on May 5, 2006. The disclosures of the above-referenced priority patents and patent applications are each incorporated by reference herein in their entireties.  
    
    
     GOVERNMENT RIGHTS  
      The United States Government has certain rights in this invention pursuant to Contract No. DE-AC07-05ID14517 between the United States Department of Energy and Battelle Energy Alliance, LLC. 
    
    
     BACKGROUND OF THE INVENTION  
      1. Field of the Invention  
      The present invention relates generally to the compression and liquefaction of gases, and more particularly to the liquefaction of a gas, such as natural gas, on a small scale by utilizing a combined refrigerant and expansion process.  
      2. State of the Art  
      Natural gas is a known alternative to combustion fuels such as gasoline and diesel. Much effort has gone into the development of natural gas as an alternative combustion fuel in order to combat various drawbacks of gasoline and diesel including production costs and the subsequent emissions created by the use thereof. As is known in the art, natural gas is a cleaner burning fuel than other combustion fuels. Additionally, natural gas is considered to be safer than gasoline or diesel as natural gas will rise in the air and dissipate, rather than settling or accumulating.  
      To be used as an alternative combustion fuel, natural gas (also termed “feed gas” herein) is conventionally converted into compressed natural gas (CNG) or liquified (or liquid) natural gas (LNG) for purposes of storing and transporting the fuel prior to its use. Conventionally, two of the known, basic processes used for the liquefaction of natural gases are referred to as the “cascade cycle” and the “expansion cycle.” 
      Briefly, the cascade cycle consists of subjecting the feed gas to a series of heat exchanges, each exchange being at successively lower temperatures until the desired liquefaction is accomplished. The levels of refrigeration are obtained with different refrigerants or with the same refrigerant at different evaporating pressures. The cascade cycle is considered to be relatively efficient at producing LNG as operating costs are relatively low. However, the efficiency in operation is often seen to be offset by the relatively high investment costs associated with the expensive heat exchange equipment and the compression equipment associated with the refrigerant system. Additionally, a liquefaction plant incorporating such a system may be impractical where physical space is limited, as the physical components used in cascading systems are relatively large.  
      In an expansion cycle, gas is conventionally compressed to a selected pressure, cooled, then allowed to expand through an expansion turbine, thereby producing work as well as reducing the temperature of the feed gas. The low temperature feed gas is then heat exchanged to effect liquefaction of the feed gas. Conventionally, such a cycle has been seen as being impracticable in the liquefaction of natural gas since there is no provision for handling some of the components present in natural gas which freeze at the temperatures encountered in the heat exchangers, for example, water and carbon dioxide. It is noted that the need for expensive preclean-up or prepurification is also an issue associated with the cascade cycle.  
      Additionally, to make the operation of conventional systems cost effective, such systems are conventionally built on a large scale for the processing of large volumes of natural gas. As a result, fewer facilities are built, making it more difficult to provide the raw gas to the liquefaction plant or facility as well as making distribution of the liquefied product an issue. Another major issue with large scale facilities is the capital and operating expenses associated therewith. For example, a conventional large scale liquefaction plant, i.e., producing on the order of 70,000 gallons of LNG per day, may cost $2 million to $15 million, or more, in capital expenses. Also, such a plant may require thousands of horsepower to drive the compressors associated with the refrigerant cycles, making operation of the plants expensive.  
      An additional problem with large facilities is the cost associated with storing large amounts of fuel in anticipation of future use and/or transportation. Not only is there a cost associated with building large storage facilities, but there is also an efficiency issue related therewith as stored LNG will tend to warm and vaporize over time, creating a loss of the LNG fuel product. Further, safety may become an issue when larger amounts of LNG fuel product are stored.  
      In addition to such technical issues, it is noted that significant issues may be associated with siting and licensing of large scale LNG and CNG facilities including obtaining the necessary real estate and approval from numerous levels of government agencies.  
      In confronting the foregoing issues, various systems have been devised which attempt to produce LNG or CNG from feed gas on a smaller scale, in an effort to eliminate long-term storage issues and to reduce the capital and operating expenses associated with the liquefaction and/or compression of natural gas. However, such systems and techniques have all suffered from one or more drawbacks.  
      U.S. Pat. No. 5,505,232 to Barclay, issued Apr. 9, 1996 is directed to a system for producing LNG and/or CNG. The disclosed system is stated to operate on a small scale producing approximately 1,000 gallons a day of liquefied or compressed fuel product. However, the liquefaction portion of the system itself requires the flow of a “clean” or “purified” gas, meaning that various constituents in the gas such as carbon dioxide, water, or heavy hydrocarbons must be removed before the actual liquefaction process can begin.  
      Similarly, U.S. Pat. Nos. 6,085,546 and 6,085,547 both issued Jul. 11, 2000 to Johnston, describe methods and systems of producing LNG. The Johnston patents are both directed to small scale production of LNG, but again, both require “prepurification” of the gas in order to implement the actual liquefaction cycle. The need to provide “clean” or “prepurified” gas to the liquefaction cycle is based on the fact that certain gas components might freeze and plug the system during the liquefaction process because of their relatively higher freezing points as compared to methane which makes up the larger portion of natural gas.  
      Since many sources of natural gas including, for example, pipelines and well gas, whether being provided to residential or industrial end customers, are considered to be relatively “dirty,” the requirement of providing “clean” or “prepurified” gas is actually a requirement of implementing expensive and often complex filtration and purification systems prior to the liquefaction process. This requirement simply adds expense and complexity to the construction and operation of such liquefaction plants or facilities.  
      In view of the shortcomings in the art, it would be advantageous to provide a process, and a system or a plant for carrying out such a process, of efficiently producing liquefied natural gas on a small scale. Additionally, it would be advantageous to provide a system for producing liquefied natural gas from a source of relatively “dirty” or “unpurified” natural gas without the need for “prepurification.” Such a system or process may include various clean-up cycles which are integrated with the liquefaction cycle for purposes of efficiency.  
      It would be additionally advantageous to provide a plant or a system for the liquefaction of natural gas which is relatively inexpensive to build and operate, and which desirably requires little or no operator oversight.  
      It would be additionally advantageous to provide such a plant or a system which is easily transportable and which may be located and operated at existing sources of natural gas which are within or near populated communities, thus providing easy access for consumers of LNG fuel.  
     BRIEF SUMMARY OF THE INVENTION  
      The present invention provides apparatuses, systems and methods for the liquefaction of gas including, for example, the liquefaction of natural gas. In accordance with one embodiment of the present invention, a method of producing liquid natural gas is provided. The method includes providing a source of unpurified natural gas and flowing a portion of the natural gas from the source. The portion of natural gas is divided into at least a process stream and a cooling stream. The process stream is flowed sequentially through a compressor and a first side of at least one heat exchanger. At least a portion of the process stream is flowed from the at least one heat exchanger through an expansion device and into a liquid-gas separator. The cooling stream is flowed sequentially through an expander and a second side of the at least one heat exchanger. A refrigerant is flowed in a heat exchange relationship with the process stream, the refrigerant being maintained separate from the process stream and the cooling stream.  
      The method may further include forming a slurry within the separator, the slurry comprising at least liquid natural gas and solid carbon dioxide. Forming the slurry may be accomplished by expanding the gas, such as through one or more Joule-Thomson valves. The slurry may be flowed into one or more hydrocyclones by way of one or more pressurized transfer tanks. The transfer tanks may be used alternately or sequentially so as to provide a continuous transfer of slurry to the hydrocyclones. The hydrocyclones substantially separate the solid carbon dioxide and the liquid natural gas. A thickened slush may exit an underflow of the hydrocyclone wherein the thickened slush may include the solid carbon dioxide and a portion of the liquid natural gas. The remaining portion of liquid natural gas is flowed through an overflow of the hydrocyclone.  
      In accordance with another embodiment of the present invention, a liquefaction apparatus, which may also be termed a “plant,” is provided. The liquefaction plant includes a compressor, a first expansion device, a first heat exchanger, at least a second expansion device and a gas-liquid separator. The liquefaction plant further includes a first flow path configured for sequential delivery of a first stream of gas through the compressor and a first side of the first heat exchanger. A second flow path is defined and configured for sequential delivery of a second stream of gas through the first expansion device and a second side of the first heat exchanger. At least one additional flow path is defined and configured for delivery of at least a portion of the first stream of gas from the first exchanger through the second expansion device and into the gas-liquid separator. A refrigerant loop is defined and configured to flow a refrigerant stream in a heat exchange relationship with the first stream, wherein the refrigerant stream remains separate from the first stream and the second stream.  
      The liquefaction plant may include additional components including a plurality of transfer tanks configured to sequentially or alternately fill with slurry and transfer the slurry to one or more hydrocyclones. The hydrocyclones may be used to separate solids from the liquids. Additionally, filters may be used to further remove solids from the liquids. A sublimation tank may be coupled to the hydrocyclones and configured to receive the solids and sublime them back to a gaseous state. 
    
    
     BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS  
      The foregoing and other advantages of the invention will become apparent upon reading the following detailed description and upon reference to the drawings in which:  
       FIG. 1  is a schematic overview of a liquefaction plant according to one embodiment of the present invention;  
       FIG. 2  is a process flow diagram depicting a liquefaction cycle according to one embodiment of the present invention;  
       FIG. 3  is a process flow diagram depicting a liquefaction cycle according to another embodiment of the present invention. 
    
    
     DETAILED DESCRIPTION OF THE INVENTION  
      Referring to  FIG. 1 , a schematic overview of a portion of a liquefied natural gas (LNG) station  100  is shown according to one embodiment of the present invention. It is noted that, while the present invention is set forth in terms of liquefaction of natural gas, the present invention may be utilized for the liquefaction of other gases as will be appreciated and understood by those of ordinary skill in the art.  
      The liquefaction station  100  includes a “small scale” natural gas liquefaction plant  102  which is coupled to a source of natural gas such as a pipeline  104 , although other sources, such as a well head, are contemplated as being equally suitable. The term “small scale” is used to differentiate from a larger scale plant having the capacity of producing, for example 70,000 gallons of LNG or more per day. In comparison, the presently disclosed liquefaction plant may have capacity of producing, for example, approximately 10,000 gallons of LNG a day but may be scaled to produce a different output as needed and is not limited to small scale operations or plants. Additionally, the liquefaction plant  102  of the present invention is considerably smaller in physical size than conventional large-scale plants and may be readily transported from one site to another.  
      One or more pressure regulators  106  may be positioned along the pipeline  104  for controlling the pressure of the gas flowing therethrough. Such a configuration is representative of a pressure letdown station wherein the pressure of the natural gas is reduced from the high transmission pressures at an upstream location to a pressure suitable for distribution to one or more customers at a downstream location. Upstream of the pressure regulators  106 , for example, the pressure in the pipeline may be approximately 600 to 800 pounds per square inch gauge (psig) while the pressure downstream of the regulators may be reduced to approximately 470 psig or less. Of course, such pressures are merely examples and may vary depending on the particular pipeline  104  and the needs of the downstream customers. It is noted that the available pressure of the upstream gas in the pipeline  104  (i.e., at plant entry  112 ) is not critical as the pressure thereof may be raised, for example by use of an auxiliary booster pump, compressor, or other appropriate mechanism prior to the gas entering the liquefaction process described herein. It is further noted that the regulators may be positioned near the plant  100  or at some distance therefrom. As will be appreciated by those of ordinary skill in the art, in some embodiments such regulators  106  may be associated with, for example, low pressure lines crossing with high pressure lines or with a different flow circuits.  
      Prior to any reduction in pressure along the pipeline  104 , a stream of feed gas  108  is split off from the pipeline  104  and fed through a flow meter  110  which measures and records the amount of gas flowing therethrough. The stream of feed gas  108  then enters the small scale liquefaction plant  102  through a plant inlet  112  for processing, as will be detailed hereinbelow. A portion of the feed gas entering the liquefaction plant  102  becomes LNG and exits the plant  102  at a plant outlet  114  for storage in a suitable tank or vessel  116 . In one embodiment, the vessel  116  is configured to hold at least 10,000 gallons of LNG at a pressure of approximately 35 pounds per square inch absolute (psia) and at temperatures, for example, as low as approximately −240° F. However, other vessel sizes and configurations may be utilized, for example, depending on specific output and storage requirements of the plant  102 .  
      A vessel outlet  118  is coupled to a flow meter  120  in association with dispensing the LNG from the vessel  116 , such as to a vehicle which is powered by LNG or into a transport vehicle as may be required. A vessel inlet  122 , coupled with a valve/meter set  124  which could include flow and or process measurement devices, enables the venting and/or purging of a vehicle&#39;s tank during dispensing of LNG from the vessel  116 . Piping  126  associated with the vessel  116  and connected with a second plant inlet  128  provides flexibility in controlling the flow of LNG from the liquefaction plant  102  and also enables the flow to be diverted away from the vessel  116 , or for drawing vapor from the vessel  116 , should conditions ever make such action desirable.  
      The liquefaction plant  102  is also coupled to a downstream section  130  of the pipeline  104  at a second plant outlet  132  for discharging the portion of natural gas not liquefied during the process conducted within liquefaction plant  102  along with other constituents which may be removed during production of the LNG. Optionally, adjacent the vessel inlet  122 , vent piping  134  may be coupled with piping of liquefaction plant  102  as indicated by interface points  136 A and  136 B. Such vent piping  134  will similarly carry gas into the downstream section  130  of the pipeline  104 . As noted above, while the second plant outlet  132  is shown as being coupled with the pipeline  104 , the second plant outlet  132  could actually be configured for discharging into a different pipeline, a different circuit of the same pipeline, or into some other structure if desired.  
      Assuming that the second plant outlet  132  is coupled with the pipeline  104 , as the various gas components leave the liquefaction plant  102  and enter into the downstream section  130  of the pipeline  104 , a valve/meter set  138 , which could include flow and/or process measuring devices, may be used to measure the flow of gas therethrough. The valve/meter sets  124  and  138 , as well as the flow meters  110  and  120 , may be positioned outside of the plant  102  and/or inside the plant as may be desired. Thus, flow meters  110  and  120 , when the outputs thereof are compared, help to determine the net amount of feed gas removed from the pipeline  104  as the upstream flow meter  110  measures the gross amount of gas removed and the downstream flow meter  138  measures the amount of gas placed back into the pipeline  104 , the difference being the net amount of feed gas removed from pipeline  104 . Similarly, optional flow meters  120  and  124  indicate the discharge of LNG and vapor from the vessel  116 .  
      Referring now to  FIG. 2 , a process flow diagram is shown, representative of one embodiment of the liquefaction plant  102  schematically depicted in  FIG. 1  and as discussed in detail in U.S. patent application Ser. No. 11/383,411 filed on May 15, 2006 (one of the applications from which the present application claims priority). As previously indicated with respect to  FIG. 1 , a high pressure stream of feed gas  140  (i.e., 600 to 800 psia), for example, at a temperature of approximately 60° F. enters the liquefaction plant  102  through the plant inlet  112 . While not specifically depicted, prior to processing the feed gas, a small portion of feed gas  140  may be split off, passed through a drying filter and utilized as instrument control gas in conjunction with operating and controlling various components in the liquefaction plant  102 .  
      In another embodiment, a separate source of instrument gas, such as, for example, nitrogen, may be provided for controlling various instruments and components within the liquefaction plant  102 . As will be appreciated by those of ordinary skill in the art, other instrument controls including, for example, mechanical, electromechanical, or electromagnetic actuation, may likewise be implemented.  
      Upon entry into the liquefaction plant  102 , the feed gas  140  flows through a filter  142  to remove any sizeable objects which might cause damage to, or otherwise obstruct, the flow of gas through the various components of the liquefaction plant  102 . The filter  142  may additionally be utilized to remove certain liquid and solid components. For example, the filter  142  may be a coalescing type filter. An example filter is available from Parker Filtration, located in Tewksbury, Mass. and is designed to process approximately 5000 standard cubic feet per minute (SCFM) of natural gas at approximately 60° F. at a pressure of approximately 500 psia. Another example of a filter that may be utilized includes a model AKH-0489-DXJ with filter #200-80-DX available from MDA Filtration, Ltd. of Cambridge, Ontario, Canada.  
      The filter  142  may be provided with an optional drain which may discharge, for example, into piping near the plant exit  132  or it may discharge to some other desired location. In one embodiment, the discharge from the filter  142  may ultimately reenter the downstream section  130  of the pipeline  104  (see  FIG. 1 ). Bypass piping may be routed around the filter  142 , allowing the filter  142  to be isolated and serviced as may be required without interrupting the flow of gas into the liquefaction plant  102 .  
      After the feed gas  140  flows through the filter  142 , it may flow through a compressor  144 , if necessary, to raise the pressure of the feed gas  140  to a desired level. For example, if the feed gas entering the inlet  112  from the pipeline  104  (or other source) does not exhibit a desired pressure of, for example, 600 to 800 psig, the compressor  144  may be used to boost the pressure of the feed gas  140  to the desired pressure. If the pressure of the feed gas  140  entering the inlet  112  is sufficient, the feed gas  140  may be routed around the compressor  144 .  
      A water clean-up cycle may be incorporated into the plant  102 . In one example, a water clean-up cycle may include a source of methanol  146 , or some other water absorbing product, which is injected into the feed gas  140 , such as, for example, by means of a pump, at a location relatively early in the flow of feed gas  140  through the plant  102 . Such a pump or other device may desirably include variable flow capability to inject methanol into the gas stream such as, for example, by way of at least one of an atomizing or a vaporizing nozzle. In another embodiment, multiple types of nozzles may be utilized such that an appropriate nozzle may be selectively utilized depending on the flow characteristics of the feed gas  140  at a given point in time.  
      In one embodiment, a suitable pump for injecting the methanol may include variable flow control in the range of 0.4 to 2.5 gallons per minute (GPM) at a design pressure of approximately 1000 psia for a water content of approximately 2 to 7 pounds mass per millions of standard cubic feet (lbm/mmscf). The variable flow control may be accomplished through the use of a variable frequency drive coupled to a motor of the pump. For example, one such pump is available from America LEWA located in Holliston, Mass. as model number EKM7-2-10MM.  
      When methanol is used, it is mixed with the gas stream to lower the freezing point of any water which may be contained therein. The methanol mixes with the gas stream and binds with the water to prevent the formation of ice in one or more flow paths defined within the liquefaction process.  
      Subsequent any desired compression of the feed gas  140  and any injection of methanol or other water absorbing materials thereinto, the feed gas  140  is split into two streams, a cooling stream  152  and a process stream  154 . In one embodiment, the cooling stream  152  enters a turbo expander  156  at a pressure of approximately 840 psig and at a temperature of approximately 60° F. and is expanded to form an expanded cooling stream  152 ′ exhibiting a lower pressure, for example approximately 50 psig, and a reduced temperature of, for example, approximately −140° F. As will be seen hereinbelow, the expanded cooling stream  152 ′ is a cold mass of fluid that provides cooling during the process of producing liquefied gas.  
      The turbo expander  156  is a turbine which expands the gas and extracts power from the expansion process. A rotary compressor  158  may be coupled to the turbo expander  156  by mechanical means, such as through a shaft  160 , so as to utilize the power generated by the turbo expander  156  to compress the process stream  154 . In one embodiment, the reduction of pressure from the transmission line or pipeline  104  to a distribution pressure, effected by the turbo expander  156 , provides the majority of the energy used in the plant  102  making it extremely economical to operate the plant  102 .  
      By compressing the process stream  154 , a larger volume of produced liquid will be realized. Additionally, elevated pressures help to keep any CO 2  contained within the process stream  154  from plugging the various downstream flow paths.  
      The proportion of gas in each of the cooling and process lines  152  and  154  is determined by the power requirements of the compressor  158  as well as the flow and pressure drop across the turbo expander  156 . Vane control valves within the turbo expander  156  may be used to control the proportion of gas between the cooling and process lines  152  and  154  as is required according to the above stated parameters. In one embodiment, the feed gas  140  may be proportioned substantially evenly between the cooling and process lines  152  and  154 .  
      An example of a turbo expander  156  and compressor  158  system includes a frame size ten (10) system available from GE Rotoflow, Inc., located in Gardona, Calif. In one embodiment, the expander  156  compressor  158  system may be designed to operate at approximately 840 psig at 5,000 pounds mass per hour at about 60° F. The expander/compressor system may also be fitted with gas bearings. Such gas bearings may be supplied with gas through a supply line  155  which draws a portion of the feed gas therethrough. However, the portion of gas directed to any such gas bearing is relatively insubstantial as compared to the mass of gas flowing through the cooling and process lines  152  and  154 . In another embodiment, gas bearings may be supplied by a separate flow of gas such as nitrogen. In yet another embodiment, the expander/compressor system may be fitted with other types of bearings including, for example, magnetic or oil bearings.  
      Bypass piping  162  routes the cooling stream  152  around the turbo expander  156 . Likewise, bypass piping  164  routes the process stream  154  around the compressor  158 . The bypass piping  162  and  164  may be used during startup of the plant  102  to bring certain components to a steady state condition prior to the processing of LNG within the liquefaction plant  102 . For example, the bypass piping  162  and  164  may be used while various components (such as the heat exchanger  166  which will be discussed hereinbelow), are gradually brought to a steady state temperature so as to avoid inducing thermal shock in such components. Additionally, if the pressure of the feed gas  140  is sufficient, the compressor  158  need not be used and the process stream may continue through the bypass piping  164 . Indeed, if it is known that the pressure of the feed gas  108  will remain at a sufficiently high pressure, the compressor  158  could conceivably be eliminated. In such a case where the compressor  158  is not being utilized, the work generated by the expander  156  could be utilized to drive a generator or provide power to some other component if desired. The bypass piping  164  additionally protects the compressor  158  from surging in the event of off-normal flow disruption. For example, if a reduced level of flow through the compressor  158  is sensed or otherwise determined for a given RPM of the compressor  158 , valves may be opened to recirculate high pressure gas through the bypass piping  164  to the inlet side of the compressor  158 .  
      Without bypass piping  162  and  164 , thermal shock might result from the immediate flow of gas from the turbo expander  156  and compressor  154  into certain downstream components. Depending on the design of specific components being used in the liquefaction plant  102  (e.g., the heat exchanger  166 ), several hours may be required to bring the system to a thermally steady state condition upon start-up of the liquefaction plant  102 .  
      For example, by routing the process stream  154  around the compressor  158 , the temperature of the process stream  154  is not increased prior to its introduction into the heat exchanger  166 . However, the cooling stream  152 , as it bypasses the expander  156 , may pass through an expansion valve, such as a Joule-Thomson (JT) valve  163 , allowing the cooling stream to expand thereby reducing its temperature. As will be appreciated by those of ordinary skill in the art, the JT valve  163  utilizes the Joule-Thomson principle that expansion of gas will result in an associated cooling of the gas as well. The cooling stream  152  may then be used to incrementally reduce the temperature of the heat exchanger  166 .  
      In one embodiment, the heat exchanger  166  is a high efficiency heat exchanger made from aluminum. In start-up situations it may be desirable to reduce the temperature of such a heat exchanger  166  by, for example, as much as approximately 1.8° F. per minute until a defined temperature limit is achieved. During start-up of the liquefaction plant  102 , the temperature of the heat exchanger  166  may be monitored as it incrementally decreases. The JT valve  163  and other valving or instruments may be controlled in order to effect the rate and pressure of flow in the cooling stream  152  and process stream  154 ′ which ultimately controls the cooling rate of heat exchanger  166  and/or other components of the liquefaction plant.  
      Additionally, during start-up, it may be desirable to have an amount of LNG already present in the tank  116  ( FIG. 1 ). Some of the LNG may be cycled through the system in order to cool various components if so desired or deemed necessary. Also, as will become apparent upon reading the additional description below, other cooling devices, including additional JT valves, located in various “loops” or flow streams may likewise be controlled during start-up in order to cool down the heat exchanger  166  or other components of the liquefaction plant  102 .  
      When the plant  102  or liquefaction system is in a steady state condition, the process stream  154  flows through the compressor  158  raising the pressure of the process stream  154 . In one embodiment, the ratio of the outlet to inlet pressures of a rotary compressor may be approximately 1.5 to 2.0, with an average ratio being around 1.7. The compression process is not thermodynamically ideal and, therefore, adds heat to the process stream  154  as it is compressed. To remove heat from the compressed process stream  154 ′, it is flowed through a heat exchanger  166  and is cooled to a very low temperature, for example approximately −200° F. at a pressure, for example, of approximately 1,100 psig. It is noted that, if the heat of compression is too high, the gas may be precooled, for example, by an ambient heat exchanger prior to its entry into the heat exchanger  166 . The heat exchanger  166  may include a high efficiency heat exchanger and, in one embodiment, may be formed as a countercurrent flow, plate and fin type heat exchanger. Additionally, the plates and fins may be formed of a highly thermally conductive material such as, for example, aluminum. In one embodiment, the high efficiency heat exchanger  166  may include a multipass, plate and fin heat exchanger such as is available from Chart Industries, Inc. of La Crosse, Wis.  
      The heat exchanger  166  is positioned and configured to efficiently transfer as much heat as possible away from the compressed process stream  154 ′ as it passes therethrough. The liquefaction plant  102  is desirably configured such that temperatures generated within the heat exchanger  166  are never low enough to generate solid CO 2  which may be present in the feed gas  140 , and which formation of solid CO 2  might result in blockage in the flow path of the compressed process stream  154 ′.  
      As noted hereinabove, methanol may be mixed with the feed gas to lower the freezing point of any water which may be contained therein. The methanol mixes with the gas stream and binds with the water to prevent the formation of ice in the cooling stream  152  during expansion in the turbo expander  156 . Thus, the methanol is present in the process stream  154  and passes therewith through the compressor  158 . About midway through the heat exchange process (i.e., between approximately −60° F. and −90° F.) the methanol and water become liquid. The compressed process stream  154 ′ is temporarily diverted from the heat exchanger  166  and passed through a separating tank  168  wherein the methanol/water liquid is separated from the compressed process stream  154 ′. The liquid is discharged through a valve  170 A and the gas flows to a coalescing filter  172  to remove an additional amount of the methanol/water mixture. The methanol/water mixture may be discharged from the coalescing filter  172  through a valve  170 B while the dried gas reenters the heat exchanger  166  for further cooling and processing. As is indicated by interface connections  136 A and  136 C, both valves  170 A and  170 B discharge the removed methanol/water mixture into piping near the plant exit  132  for discharge into the downstream section  130  of the pipeline  104  (see  FIG. 1 ).  
      In one example, a coalescing filter  172  used for removing the methanol/water mixture may exhibit an efficiency of removing the methane/water mixture to less than approximately 75 ppm/w. One such filter is available from Parker Filtration, located in Tewksbury, Mass.  
      The liquefaction process shown in  FIG. 2  thus provides for efficient production of natural gas by integrating the removal of water during the process without expensive equipment and preprocessing required prior to the liquefaction cycle, and particularly prior to the expansion of the gas through the turbine expander  156 .  
      After exiting the heat exchanger  166 , the cooled, compressed process stream  154 ″ (referred to hereinafter as the product stream  154 ″ for purposes of convenience) flows through two expansion valves, such as JT valves  174  and  176  and into a liquid/vapor separator  180 . The two valves  174  and  176  are arranged in a parallel flow configuration and work in concert with one another to control the flow of the product stream  154 ″ into the separator  180 . In one embodiment, the two valves  174  and  176  are of different sizes. In other words, the two valves may exhibit different flow coefficients (C v ). For example, in one embodiment, one valve  174  may be sized and configured to accommodate approximately 80% of the flow entering into the separator from the product stream  154 ″ while the other valve  176  may be sized and configured to accommodate the remaining approximately 20% of the flow.  
      Of the two valves  174  and  176 , the larger valve is held at a constant position while the valve carrying the remaining flow is used for the fine control required to maintain a desired flow rate. As the gas expands through the valves, a Joule-Thomson effect reduces the temperature and pressure from, for example, approximately 1100 psig at approximately −185° F. to approximately 35 psig and approximately −230° F. (which is the saturation temperature and pressure for the liquid). This pressure drop also precipitates solid CO 2 . The three phase (gas, liquid, and solid CO2) mixture exiting the valves is collected in the separator tank  180 .  
      While a single valve may be used instead of the two JT valves  174  and  176 , the use of two (or more) valves  174  and  176  provides a more controlled flow and reduces shock or fluctuation in the stream. Additionally, the use of multiple valves may be beneficial during start-up of the plant  102  because the gas is less dense in such circumstances. An accumulator  177  may be coupled with the product stream  154 ″ at a location upstream from the valves  174  and  176  to further dampen flow pulses that may be introduced into the stream  154 ″ by the valves  174  and  176 . A pressure sense line  178  may extend between the accumulator and the product stream  154 ″ and may be buffered by a restrictive valve  179 . Additionally, the accumulator  177  may be directly coupled to the product stream  154 ″.  
      When the product stream  154 ″ passes through the two expansion valves  174  and  176 , the stream follows a constant enthalpy pressure drop that changes from a high pressure, single phase mixture at a high pressure and low temperature (e.g., approximately 1,100 psig and approximately −200° F.) to three phases (solid, liquid and gas) with approximately 10% to 28% mass flow being vapor, at a reduced pressure of, for example, 35 psig. The solid component includes solid CO 2  The vapor component from the separator  180  is collected and removed therefrom through piping  182  and is routed back to the heat exchanger  166  to provide additional cooling by way of a compressor  186 . While shown to be located on the warm side of the heat exchanger  166 , the compressor  186  could be positioned on the cold side of the heat exchanger  166 , although such positioning might require the compressor to be configured as a cryogenic compressor. In one embodiment, the compressor  186  may be powered by an internal combustion engine driven by a portion of the natural gas flowing through the plant  102 . In another embodiment, the compressor  186  may be powered by electricity or other means as will be appreciated by those of ordinary skill in the art. It is further noted that an ejector or an eductor might be utilized in place of the compressor  186  in another embodiment.  
      To maintain the separator  180  at a desired pressure, for example at approximately 35 psig, the compressor  186  may be used to recompress the excess gas from the separator  180  to pressures suitable, for example, for introduction of the gas into the heat exchanger  166 . For example, the compressor  186  may be used to increase the pressure of the gas from approximately 35 psig to approximately 50 psig. The compressor  186  may also be coupled to a vent line associated with the storage tank  116  to likewise help maintain the pressure within storage tank  116  at substantially the same pressure as that of the separator  180 .  
      A make up line  187  having a regulator  188  may be routed around the compressor  186  to prevent flow surges as may be the case when gas flow from the separator  180  and or storage tank  116  is relatively low. The pressure of such a regulator may be set at a level that is just under the desired saturation pressure for the separator  180 . In one embodiment, a floating ball check valve may also be installed in the suction line of the compressor  186  to prevent a sudden surge of liquid. If the compressor  186  is located on the cold side of the heat exchanger  166 , the floating ball check valve may also be used to prevent any accumulated liquid from entering the suction side of the pump. It is noted that if the compressor  186  is located on the warm side of the heat exchanger  166 , no liquid will be present at the suction side of the compressor  186  under normal operating conditions.  
      A back-pressure regulator may be located in the vapor piping  182  to also help control the pressure within the separator  180 . In one example, the back pressure regulator  184  may be configured with set-point of approximately 35 psig so as to create a saturation pressure of the liquid that is below a desired transfer pressure (i.e., the pressure used to transfer liquid from the separator  180  to other components within the plant  102 ).  
      In one embodiment, the storage tank  116  may be maintained at substantially the same pressure as that of the separator  180 . By maintaining the liquid saturation pressure below associated transfer pressures, the liquid is prevented from boiling when the liquid experiences a pressure drop such as will occur when the liquid flows through piping, valves and other equipment as it is transferred from the separator  180 . The pressure difference between the separator  180  (e.g., approximately 35 psig) and a transfer pressure may be specified such that it is sufficient to ensure that any and all line pressure drops encountered en route to the storage tank  116  are accounted for. The liquid will then arrive at the storage tank  116  at saturation pressure, minimizing loss and flow complications that might otherwise occur due to boiling of the liquid during the transfer thereof.  
      As noted above, solid CO 2  mostly forms as small crystals in the liquid as it exits the JT valves  174  and  176 . With the appropriate resident time in the liquid, the CO 2  becomes a sub-cooled solid particle. In the sub-cooled state the particles are less likely to clump together. Keeping the particles suspended in the liquid provides more effective and efficient transfer and separation of the solids from the liquid component. If allowed to settle, the particles have a tendency to clump or stick together. To aid in keeping the CO 2  particles suspended in the liquid, gas bubbles may be introduced into the bottom of the separator  180 . Introduction of the gas bubbles helps to agitate the CO 2  solids within the liquid and keep the particles continually moving within the liquid. While not specifically shown in  FIG. 2 , gas may be drawn from, for example, a location subsequent the coalescing filter  172 , to provide the bubbling and agitation of the solids within the separator.  
      As the separator  180  is filled, the level may be monitored by appropriate sensors. The level of the liquid/solid within the separator  180  may be desirably monitored and controlled in order to provide desired resident times for the CO 2  and thereby ensure that the CO2 particles are subcooled.  
      When a specified maximum level of liquid/solid slurry is reached within the separator  180 , the liquid/solid slurry will be transferred to at least one of a plurality of transfer tanks  190 A and  190 B. In one embodiment, the transfer tanks  190 A and  190 B are used alternately. The transfer tanks  190 A and  190 B are utilized to transfer the slurry from the separator  180  to one of a plurality of hydrocyclones  192 A and  192 B. While it is possible to transfer the slurry from the separator  180  to the hydrocyclones  192 A and  192 B without the use of the transfer tanks  190 A and  190 B, it is believed that, in the currently described embodiment, the use of transfer tanks  190 A and  190 B provides improved control over the transfer of the slurry (including transfer of the slurry to the hydrocyclones  192 A and  192 B and subsequent transfer of the liquid from the hydrocyclones  192 A and  192 B to downstream components such as the storage tank  116 ), and ensures that adequate transfer pressures are maintained during such transfer. If pressures are not properly maintained during transfer of the slurry, the liquid may boil due to pressure losses associated with piping and other components. Additionally, failure to maintain proper pressures during transfer of the slurry may result in inadequate solid-liquid separation. The use of separate, alternating tanks  190 A and  190 B to effect the transfer of the slurry from the separator  180 , is one means that may be used to maintain the pressure integrity of the liquefaction plant  102 .  
      When the separator  180  has reached its specified maximum level, two valves will open allowing the fluid to move into one of the transfer tanks (e.g., transfer tank  190 A for purposes of the present discussion). The first valve  220 A allows the transfer of liquid/CO 2  slurry, while the second valve  222 A vents the transfer tank  190 A back to the separator  180  enabling the captured gases in the transfer tank  190 A to escape as it is being filled with the slurry. Depending, for example, on the length of the piping run between the separator  180  and the transfer tank  190 A, bubbler locations may be added to the bottom of the pipe to prevent the CO 2  from settling during the transfer of the slurry (similar to that which has been previously described with respect to the separator  180 ). It is noted that a single valve may be utilized instead of multiple valves if the single valve is properly located (e.g., physically below the separator  180 ).  
      When the level in the separator  180  tank is reduced to a specified minimum level, the valves  220 A and  222 A to the transfer tank  190 A close. The liquid CO 2  transfer alternates between the two transfer tanks  190 A and  190 B associated with the separator tank  180 . Once the valves connecting the separator  180  and transfer tank are closed the liquid/CO 2  mixture is ready to be transferred to the hydrocyclone separator. The pressure sensitive hydrocyclone separates the CO 2  from the liquid by cyclonic action. The transfer tank is pressurized to the desired pressure and the transfer valve is opened. The transfer pressure is approximately 20 psi higher than the saturation pressure of the liquid. This pressure head provides the motive force for the liquid/CO 2  mixture, prevents the liquid from boiling as pressure drops are realized, and prevents the formation of additional CO 2  that could occur if the pressure were to drop below saturation pressure.  
      By alternating the filling of the two (or more) transfer tanks  190 A and  190 B, a constant flow of slurry to a selected hydrocyclone (e.g.,  192 A) may be easily maintained. The alternating use of transfer tanks  190 A and  190 B also improves the efficiency and effectiveness of the separation process performed by the hydrocyclones  192 A and  192 B. It is noted that, if the rate at which liquid is produced (i.e., within the separator  180 ) falls behind with respect to a desired separation rate of a hydrocyclone  192 A, the flow to the hydrocyclone  192 A may be suspended while the separator  180  and transfer tanks  190 A and  190 B fill to a desired level. The transfer tanks  190 A and  190 B and hydrocyclones  192 A and  192 B may be oversized to prevent the possibility of producing liquid in the separator  180  faster than the transfer/separation capabilities of the hydrocyclones  192 A and  192 B.  
      The transfer tank (considering tank  190 A as an example) is pressurized by use of a pressure regulator  224  which is set at a desired transfer pressure. If the feed line to the transfer tank  190 A is sufficient and the regulator  224  is large enough, a regulator  224  can be mounted directly on the transfer tank  190 A. This would require one regulator for each tank. However, in another embodiment, both transfer tanks  190 A and  190 B could be maintained with a smaller feed line and a single regulator  224  as shown in  FIG. 2 . Use of a single regulator may require the use of storage or accumulator tanks (e.g.,  226 A) to ensure that the proper volume of gas is used so as to maintain a constant pressure during the complete transfer process. It is noted that the gas used to transfer the liquid will be warmer than the liquid/solid slurry being transferred. As such, any heat transfer effects are accounted for in configuring and sizing the regulator(s)  224  and accumulator tank(s)  226 A.  
      As previously noted, the liquid/solid slurry is transferred to, and processed by, one of the hydrocyclones  192 A and  192 B. The hydrocyclones  192 A and  192 B act as separators to remove the solid CO 2  from the slurry allowing the LNG or other liquid product to be collected and stored. The hydrocyclones  192 A and  192 B may be configured to be substantially identical to one another. As such, only a single hydrocyclone  192 A is referenced with respect to the particular details thereof. In one embodiment, the hydrocyclone  192 A may be designed, for example, to operate at a pressure of approximately 125 psia at a temperature of approximately −238° F. The hydrocyclone  192 A uses a pressure drop to create a centrifugal force which separates the solids from the liquid. A thickened slush, formed of a portion of the liquid natural gas with the solid CO 2 , exits the hydrocyclone  192 A through an underflow  194 A. The remainder of the liquid natural gas is passed through an overflow  196 A for additional filtering. A slight pressure differential, for example, between approximately −0.5 psid and 1.5 psid, exists between the underflow  194 A and the overflow  196 A of the hydrocyclone  192 A. The pressure in the hydrocyclone  192 A is provided and maintained by the transfer tank ( 190 A or  190 B). A control valve  240 A may be positioned at the overflow  196 A of the hydrocyclone  192 A to assist in controlling the pressure differential developed within the hydrocyclone  192 A. The underflow pressure may be controlled by the mid-system pressure as may be maintained by the suction side of a recompression compressor  228  (if one is being used) or by the distribution line pressure at the plant outlet  132 .  
      A suitable hydrocyclone  192 A is available, for example, from Krebs Engineering of Tucson, Ariz. In one example, the hydrocyclone  192 A may be configured to operate at design pressures of up to approximately 125 psi within a temperature range of approximately 100° F. to −300° F. Additionally, the hydrocyclone  192 A may desirably include an interior surface which exhibits a specified surface finish.  
      It is noted that the hydrocyclones  192 A and  192 B are selectively coupled with each of the transfer tanks  190 A and  190 B through appropriate valving and piping such that each of the transfer tanks  190 A and  190 B may selectively flow slurry to either of the hydrocyclones  192 A and  192 B. The use of two hydrocyclones  192 A and  192 B provides redundancy in the system so that if one hydrocyclone becomes plugged (or partially plugged), the other hydrocyclone may be used while appropriate maintenance is performed on the first. If desired, warm gas may be routed from another location in the plant  102  to assist in unplugging a hydrocyclone such as by melting or sublimation of solid CO 2  that may be the source of any such plugging. The selection and control of the transfer tanks  190 A and  190 B and hydrocyclones  192 A and  192 B will be further discussed hereinbelow with respect to the control and operation of the plant  102 .  
      The liquid natural gas flows through the overflow  196 A of the hydrocyclone  192 A and may flow through one of a plurality of filters  200 A and  200 B placed in a parallel flow configuration. The filters  200 A and  200 B capture any remaining solid CO 2  which may not have been separated out in the hydrocyclone  192 A. The filters  200 A and  200 B may be configured such as substantially described in the priority patent applications and patents that have been incorporated by reference. Generally, in one embodiment, such filters  200 A and  200 B may include a first filter screen of coarse stainless steel mesh, a second conical shaped filter screen of stainless steel mesh less coarse than the first filter screen, and a third filter screen formed of fine stainless steel mesh. In another embodiment, all three filter screens may be formed of the same grade of mesh.  
      The filters  200 A and  200 B may, from time to time, become clogged or plugged with solid CO 2  captured therein. Thus, as one filter, i.e.,  200 A, is being used to capture CO 2  (or other solids) from the liquid stream, the other filter, i.e.,  200 B, may be purged of CO 2  by passing a relatively high temperature natural gas therethrough in a counter flowing fashion. For example, gas may be drawn from a relatively warmer gas stream, as indicated at interface points  202 B (or  202 A for filter  200 A) and  202 C to flow through and clean the filter  200 B.  
      During cleaning of the filter  200 B, the cleaning gas may be discharged to a downstream location within the plant  102  adjacent the plant outlet  132  as indicated by interface connections  136 E ( 136 D for filter  202 A) and  136 A. Appropriate valving and piping including, for example, three way valves  204 A and  204 B, which may be used to enable the filters  200 A and  200 B to be switched and isolated from one another as may be required. Other methods of removing CO 2  solids (or other solids) that have accumulated in the filters  200 A and  200 B are readily known by those of ordinary skill in the art.  
      In another embodiment, the filters  200 A and  200 B may be configured to include a floating bed that traps solid CO 2  while permitting fluid to pass therethrough. As the floating bed becomes filled with CO 2 , the trapped CO 2  settles to the bottom. When the filter (e.g.,  200 A) is filled with CO 2 , an elevated pressure differential develops indicating that the filter  200 A needs to be cleaned and flow can be switched to the redundant filter (e.g.,  200 B). The first filter  200 A may then be cleaned in a manner similar to that which has been described hereinabove.  
      The filtered liquid passes from the filter  200 A (or  200 B) to a diversion tank  206 . Liquid in the diversion tank  206  may be selectively passed to the storage tank  116 , utilized for additional cooling within the liquefaction  102 , or both. When used for additional cooling, the liquid in the diversion tank  206  may be routed back to the heat exchanger  166 , such as through stream  208  and by use of an appropriate pump  210  (referred to herein as a diversion pump). The diversion pump  210  may also be used to elevate the pressure of the liquid such that it may be subsequently recirculated through the liquefaction plant  102  or reintroduced into the pipeline  104 . For example, a positive displacement pump may be used to pump liquid out of the diversion tank  208  to the heat exchanger  166  while increasing the pressure of the liquid to, for example, approximately 495 psig if the liquid is going to be passed back to the pipeline  104  (or some other receiving line) or, for example, to approximately 800 psig if the liquid is to be recirculated back through the plant  102 . By pressurizing to liquid to a distribution or recirculation pressure, the load on the recompressor  228  is reduced, it being more efficient to compress a liquid than it is to compress a gas.  
      The diversion tank  206  may also be supplied with liquid by way of a make-up pump  210  coupled with an outlet of the storage tank  116 . In the event of off normal or startup conditions, where the plant  102  is not supplying adequate liquid to keep the diversion tank  206  full, the make-up pump  212  may be used to supply the needed liquid. When the liquid level drops to a predetermined level within the diversion tank  206 , the pump  212  will start and fill the tank  206  back to a desired level. Thus, a supply of liquid may be maintained in the diversion tank  206  which may be pumped into the heat exchanger  166  to assist in preparing the plant  102  for the liquid production process. In other words, the cryogenic liquid in the diversion tank  206  may be used provide cooling during in the final stages of the heat exchanger  166  in order to reduce the temperature of what becomes the compressed product stream  154 ″ to temperatures required for liquid production.  
      In one embodiment, the flow of liquid from the diversion tank  206  to the heat exchanger may be controlled based on the temperature of the product stream  154 ″. Thus, for example, as the temperature of the product stream  154 ″ becomes warmer, the pump  210  may provide additional flow of liquid from the diversion tank  206  to the heat exchanger  166 . Additionally, as the temperature of the product stream  154 ″ decreases, the pump  210  may be controlled to reduce the amount of liquid being provided to the heat exchanger  166 . The pump  210  may be configured as a variable flow pump and controlled, for example, by a proportional, integral, derivative (PID) controller.  
      Referring back to the hydrocyclones  192 A and  192 B, the thickened slush formed in the hydrocyclone (e.g.,  192 A) exits the underflow  194 A and passes through piping  213 A to a sublimation tank  214 . The sublimation tank  214  may include, for example, a heat exchanger configured to convert the solid CO 2  to a gaseous state.  
      In one particular embodiment, the sublimation tank  214  may include a tube-in-shell heat exchanger such as that which is disclosed in the priority applications and patents previously incorporated by reference. The slush may enter such a heat exchanger on the tube side thereof. In one embodiment, the slush entering the sublimation tank  214  will include approximately 10% solid CO 2  by mass in a liquid carrier. Warm gas, for example, gas at a temperature of approximately 100° F., may flow through the sublimation tank  214  by way of a flow path  216  from the heat exchanger  166 , or from some other location, to heat the slush and effect sublimation of the solid CO 2 .  
      It has been determined that, in natural gas mixtures found in conventional U.S. pipelines, CO 2  becomes a solid at approximately −160° F. at approximately 35 psig. However, once the CO 2  has frozen, it no longer follows the phase change path it would when found in the natural gas mixture. Instead, the solid CO 2  acts as pure CO 2  which sublimes at approximately −80° F. and at approximately 35 psig.  
      As the slush enters the sublimation tank  214 , the liquid carrier violently flashes to a gas which, in addition to transferring heat to the solid CO 2 , provides a positive motive flow for the solid CO 2 . Due to the turbulent nature of the flow, the CO 2  constantly interacts with the tube walls as it progresses through the tubes. Additionally, the tube walls become progressively warmer along the flow path of the CO 2 . Once all of the liquid has flashed to a gas and warmed to approximately −80° F., the CO 2  will start to sublime, aided by the relatively warm tube walls and the warmed gases. It is noted that the sublimation tank  214  may be configured such that the warm gas from stream  216  will warm all areas of the shell (when configured as a tube-in-shell heat exchanger) to a temperature above the sublimation temperature of the CO2. In this manner, the sublimation tank becomes “self-thawing” in the case of any potential plugs caused by the solid CO 2  passing through the tube side thereof.  
      The gas leaving the sublimation tank (including both the warming gas and the sublimed CO 2 ) may be routed back to the expanded cooling stream  152 ′ to assist in cooling the compressed process stream  154 ′ in heat exchanger  166 .  
      As previously noted hereinabove, the plant  102  may include a recompression compressor  228 . The recompression compressor  228  may be used to recompress gas to a desired pressure prior to reintroduction of the gas into the pipeline  104  (or other receiving station or system) or prior to the recirculation of gases into the plant  102  for reprocessing thereof. Gas from the separator  180  and from the storage tank  116  may be used, for example, as fuel for a combustion engine that drives the recompression compressor  228 .  
      It is noted that, while not specifically shown, a number of valves may be placed throughout the liquefaction plant  102  for various purposes such as facilitating physical assembly and startup of the plant  102 , maintenance activities, or for collecting of material samples at desired locations throughout the plant  102  as will be appreciated by those of ordinary skill in the art.  
      It is further noted that the plant  102  may be configured as a relatively compact structure such as described in the applications and patents previously incorporated by reference. Generally, the plant  102  may be constructed on one or more skids for simple transportation and erection of the plant  102 .  
      The plant  102  may further include controls such that minimal operator input is required for the operation of the plant  102 . Indeed, it may be desirable that the plant be able to function without an on-site operator. Thus, with proper programming and control design, the plant may be accessed through remote telemetry for monitoring and/or adjusting the operations of the plant. Similarly, various alarms may be built into such controls so as to alert a remote operator or to shut down the plant in an upset condition. One suitable controller, for example, may be a DL405 series programmable logic controller (PLC) commercially available from Automation Direct of Cumming, Ga.  
      Reviewing now the operation of the plant  102  and considering various control aspects thereof, when the plant  102  is started, the JT valves  174  and  176  are closed such that the product stream  154 ″ is diverted back into the heat exchanger  166  after passing through a JT valve  230 . This produces a cooling stream that may be used to cool the heat exchanger  166  until the temperature of the product stream  154 ″ approaches approximately −90° F. at a pressure of approximately 800 psig. When starting, the expander  156 /compressor  158  will be manually accelerated at a rate that corresponds with approximately 2° F. per minute temperature reduction in the heat exchanger  166 . This acceleration may stop when the pressure of the compressed process stream  154 ′ builds to approximately 800 psig. If the pressure of the pipeline  104  or other source is running at a pressure of approximately 800 psig, use of the compressor  158  may not be necessary. However, the compressor  158  may be started to provide a desired boost in pressure to the process stream  154 .  
      Prior to closing the JT valve  230  in the cooling stream and opening valves  174  and  176 , the diversion tank  206  may be filled with liquid from the storage tank  116 . The flow may simply fill the diversion tank  206  or it may recirculate back into the storage tank  116 . When the temperature of the product stream  154 ″ reaches a desired temperature, the flow of product stream  154 ″ is routed to the separator  180 . At this time the diversion tank pump  210  will start pumping liquid from the diversion tank  206  to the heat exchanger  166  to aid in the final and rapid cooling of the compressed process stream  154 ′.  
      Switching the flow of the product stream  154 ″ into the separator  180  will prevent CO 2  from building up in the heat exchanger  166 . It is noted that CO 2  formation begins when the pressure drops from approximately 800 psig at approximately −160° F. to a pressure of approximately 35 psig at a temperature of approximately −220° F. The initially warm tank of the separator  180  will flash the small amount of liquid and CO 2  to a gas, as the temperature of the product stream  154 ″ decreases. Decreased temperatures in the product stream  154 ″ result in the production of additional liquid. The liquid quality will also improve as the temperature drops and the CO 2  will be suspended in the liquid as the tank of the separator  180  cools to a point at which the liquid remains.  
      If the separator  180  should fill before the temperature of the product stream is within the desired range, the separator  180  may be flushed. Flushing the cold liquid into the warm transfer tanks  190 A and  190 B will boil off most of the liquid and any remaining liquid may be used to continue cooling off various components of the plant  102 . As the temperature of the product stream  154 ″ reaches a desired range of, for example, approximately −180° F. to approximately—200° F., the expander  156  will have been accelerated to a desired operational speed.  
      During operation of the plant  102 , the relationship between the “back-end flow loop” and the “cooling loop” may be used as the basis for the liquid production and control of the plant  102 . The back-end flow loop generally refers to the flow of fluid through the liquid handling components of the plant and particularly the flow through the valve or valves (e.g., valves  174  and  176 ) leading into the gas-liquid separator  180 . The cooling loop refers generally to flow of fluid that provides cooling via the heat exchanger  166  during normal operating conditions and particularly includes the flow of liquid from the diversion tank  206 . Further details regarding the control of the plant  102  are set forth in the various U.S. patents and U.S. patent applications previously incorporated by reference including, for example, U.S. patent application Ser. No. 11/383,411 filed on May 15, 2006 previously incorporated by reference.  
      Referring now to  FIG. 3 , a process flow diagram is shown which is representative of another embodiment of a liquefaction plant  102 ′. The plant  102 ′ is similar to the plant  102  previously discussed herein with respect to  FIG. 2  and similar components and flow paths are identified using similar reference numerals.  
      It is noted that the plant  102  discussed with respect to  FIG. 2  utilizes a substantial portion of the gas for cooling of the process/product streams. In one example, depending on scale of the plant  102  and the specific design implemented, such a plant  102  might produce between approximately 6,000 to approximately 40,000 volumetric gallons of liquid product per day. This output may represent a production rate of approximately 6% to approximately 20% of the gas that is introduced into the plant  102 . The balance of the gas entering the plant  102  that is not liquefied product is used primarily for refrigeration of the liquefied product. Of the gas being used as a refrigerant, up to approximately 40% may be liquefied with approximately 20% being returned to the plant  102  for use in the cooling required to convert the gas to a liquid and, therefore, is not available to be utilized as liquid product. Stated another way, approximately half of the total liquid produced by the plant may be required for refrigeration purposes and is discharged to the receiver (e.g., pipeline, reservoir or other receiving station). Such a configuration can pose limits on the amount of liquid a plant  102  is able to produce. Such a configuration may also be limited by the size of receiver (e.g., pipeline, reservoir or other receiving station) that receives gas (also referred to as tail gas) from the outlet  132  of the plant  102 .  
      The plant  102 ′ shown and described with respect to  FIG. 3  reduces the amount of gas required for refrigerant purposes, resulting in higher liquefied product volumes, and provides additional flexibility in site location of the plant  102 ′, including the ability to install and operate the plant  102 ′ at a location where tail gas reservoirs or receivers are limited or smaller than desired for operating previously described plants (e.g., plant  102 ).  
      Upon entry into the liquefaction plant  102 ′, the feed gas  140  may flow through a filter  142  such as previously discussed. After the feed gas  140  flows through the filter  142 , it may flow through a compressor  144 , if necessary, to raise the pressure of the feed gas  140  to a desired level. If the pressure of the feed gas  140  entering the inlet  112  is sufficient, the feed gas  140  may be routed around the compressor  144 .  
      A water clean-up cycle may again be incorporated into the plant  102 . In one example, a water clean-up cycle may include a source of methanol  146 , or some other water absorbing product, which is injected into the feed gas  140 , such as, for example, by means of a pump, at a location relatively early in the flow of feed gas  140  through the plant  102 . Other possible water clean-up methods are also contemplated as will be appreciated by those of ordinary skill in the art.  
      Subsequent any desired compression of the feed gas  140  and any injection of methanol or other water absorbing materials thereinto, the feed gas  140  is split into a cooling stream  152  and a process stream  154 . In one embodiment, the cooling stream  152  enters a turbo expander  156  at a pressure of approximately 840 psig and at a temperature of approximately 60° F. and is expanded to form an expanded cooling stream  152 ′ exhibiting a lower pressure, for example approximately 50 psig, and a reduced temperature of, for example, approximately −140° F. As will be seen hereinbelow, the expanded cooling stream  152 ′ is a cold mass of fluid that provides cooling during the process of producing liquefied gas.  
      The turbo expander  156  is a turbine which expands the gas and extracts power from the expansion process. A rotary compressor  158  may be coupled to the turbo expander  156  by mechanical means, such as through a shaft  160 , so as to utilize the power generated by the turbo expander  156  to compress the process stream  154 . In one embodiment, the reduction of pressure from the transmission line or pipeline  104  to a distribution pressure, effected by the turbo expander  156 , provides the majority of the energy used in the plant  102  making it extremely economical to operate the plant  102 .  
      By compressing the process stream  154 , a larger volume of produced liquid will be realized. Additionally, elevated pressures help to keep any CO 2  contained within the process stream  154  from plugging the various downstream flow paths.  
      The proportion of gas in each of the cooling and process lines  152  and  154  may be determined by the power requirements of the compressor  158  as well as the flow and pressure drop across the turbo expander  156 . Vane control valves within the turbo expander  156  may be used, to a certain extent, to control the proportion of gas between the cooling and process lines  152  and  154 . Additionally, some flow adjustments through the compressor  156  and expander  158  may be effected by altering the downstream pressure through adjustment of the JT valves  174  and  176 . For example, adjusting the valves  174  and  176  to increase the pressure within the product stream  154 ″ results in a reduced flow through the compressor  156 . In one embodiment, the feed gas  140  may be proportioned substantially evenly between the cooling and process lines  152  and  154 .  
      The expander/compressor system may also be fitted with gas bearings. Such gas bearings may be supplied with gas through a supply line  155  which draws a portion of the feed gas therethrough. However, the portion of gas directed to any such gas bearing is relatively insubstantial as compared to the mass of gas flowing through the cooling and process lines  152  and  154 . In another embodiment, gas bearings may be supplied by a separate flow of gas such as nitrogen. In yet another embodiment, the expander/compressor system may be fitted with other types of bearings including, for example, magnetic or oil bearings.  
      Bypass piping  162  routes the cooling stream  152  around the turbo expander  156 . Likewise, bypass piping  164  routes the process stream  154  around the compressor  158 . The bypass piping  162  and  164  may be used during startup of the plant  102  to bring certain components to a steady state condition prior to the processing of LNG within the liquefaction plant  102 . Additionally, if the pressure of the feed gas  140  is sufficient, the compressor  158  need not be used and the process stream may continue through the bypass piping  164 . In such a case, the compressor  156  could be replaced by a generator or other device to take advantage of the power produced by the expander  158 .  
      In one embodiment, the heat exchanger  166  is a high efficiency heat exchanger made from aluminum. In start-up situations it may be desirable to reduce the temperature of such a heat exchanger  166  by, for example, as much as approximately 1.8° F. per minute until a defined temperature limit is achieved. During start-up of the liquefaction plant  102 , the temperature of the heat exchanger  166  may be monitored as it incrementally decreases. The JT valve  163  and other valving or instruments may be controlled in order to effect the rate and pressure of flow in the cooling stream  152  and process stream  154 ′ which ultimately controls the cooling rate of heat exchanger  166  and/or other components of the liquefaction plant.  
      Additionally, during start-up, it may be desirable to have an amount of LNG already present in the tank  116  ( FIG. 1 ). Some of the LNG may be cycled through the system in order to cool various components if so desired or deemed necessary. Also, as will become apparent upon reading the additional description below, other cooling devices, including additional JT valves, located in various “loops” or flow streams may likewise be controlled during start-up in order to cool down the heat exchanger  166  or other components of the liquefaction plant  102 .  
      When the plant  102  or liquefaction system is in a steady state condition, the process stream  154  flows through the compressor  158  raising the pressure of the process stream  154 . The compression process is not thermodynamically ideal and, therefore, adds heat to the process stream  154  as it is compressed. Thus, the compressed process stream is subjected to one or more cooling processes including, for example, a heat exchange process carried out in heat exchanger  166 . It is noted that, if the heat of compression is too high, the gas may be precooled, for example, by an ambient heat exchanger prior to its entry into the heat exchanger  166 . The heat exchanger  166  may include a high efficiency heat exchanger and, in one embodiment, may be formed as a countercurrent flow, plate and fin type heat exchanger. Additionally, the plates and fins may be formed of a highly thermally conductive material such as, for example, aluminum. In one embodiment, the high efficiency heat exchanger  166  may include a multipass, plate and fin heat exchanger such as is available from Chart Industries, Inc. of La Crosse, Wis.  
      If methanol or some other component is used to absorb water in the incoming gas stream, the methanol and water may be removed from the flow at a location about midway through the heat exchange process as previously described herein.  
      After exiting the heat exchanger  166 , the cooled, compressed process stream  154 ″ (referred to hereinafter as the product stream  154 ″ for purposes of convenience) flows through a second heat exchanger  300  that is associated with a refrigeration system  302 . The refrigeration system includes a refrigerant loop  304  that maintains the refrigerant separate and independent from the flow of any gas within the plant  102 ′. In other words, the refrigerant being used in the refrigerant loop  304  does not include any of the gas introduced into the plant  102 ′ through the inlet  112 . The refrigerant in the refrigerant loop  304  does not come into physical contact with, or otherwise intermix with the various gas or liquid streams of the plant  102 ′ (i.e., cooling stream  152 , expanded cooling stream  152 ′, process stream  154 , compressed process stream  154 ′, product stream  153 ″, the liquid streams flowing from the hydrocyclones  192 A and  192 B through the filters  200 A and  200 B to the storage tank  116 , or the slush streams flowing from the hydrocyclones  192 A and  192 B to the sublimation tank  214 ). Various types of refrigerants and refrigeration components may be utilized depending on cooling requirements of the plant  102 ′ as will be recognized by those of ordinary skill in the art. For example, refrigerants such as propane, ethane, methane, or nitrogen may be used. Cycles such as mixed refrigerant or cascade cycles may also be employed.  
      The combination of the high efficiency heat exchanger  166  and the second heat exchanger serve to remove heat from the compressed process stream  154 ′, to a very low temperature, for example between approximately −185° F. and approximately −200° F. at a pressure, for example, of approximately 1,100 psig. The heat exchangers  166  and  300  are positioned and configured to efficiently transfer as much heat as possible away from the compressed process stream  154 ′ and product stream  154 ″ as it passes through such heat exchangers  166  and  300 . The liquefaction plant  102 ′ is desirably configured such that temperatures generated within the heat exchangers  166  and  300  are never low enough to generate solid CO 2  which may be present in the feed gas  140 , and which formation of solid CO 2  might result in blockage in the flow path of the compressed process stream  154 ′ or product stream  154 ″.  
      During start up, it may be desirable to flow a portion of the product stream  154 ″ back through the heat exchanger  166  to help bring the plant  102 ′, and various components thereof, to a steady state operating temperature. In one embodiment, the portion may be flowed through a JT valve  230  to expand the gas and provide additional cooling. Depending on the cooling requirements, the portion of gas may be split from the product stream  154 ″ at a location prior to the second heat exchanger  300  (such as shown by dashed lines) or at a location subsequent the second heat exchanger  300 .  
      When in a steady state operating condition, after flowing through the second heat exchanger  300 , the product stream  154 ″ flows through two expansion valves, such as JT valves  174  and  176  and into a liquid/vapor separator  180  (although a different number of valves may be utilized). As previously described, the two valves  174  and  176  may be arranged in a parallel flow configuration and work in concert with one another to control the flow of the product stream  154 ″ into the separator  180 . As the gas expands through the valves, a Joule-Thomson effect reduces the temperature and pressure from, for example, approximately  1100  psig at approximately −185° F. to approximately 35 psig and approximately −230° F. (which is the saturation temperature and pressure for the liquid). This pressure drop also precipitates solid CO 2 . The three phase (gas, liquid, and solid CO2) mixture exiting the valves is collected in the separator tank  180  wherein a liquid/solid slurry is formed and the gas or vapor is separated from the liquid/solid slurry.  
      An accumulator  177  may be coupled with the product stream  154 ″ at a location upstream from the valves  174  and  176  to further dampen flow pulses that may be introduced into the stream  154 ″ by the valves  174  and  176 . A pressure sense line  178  may extend between the accumulator  177  and the product stream  154 ″ and may be buffered by a restrictive valve  179 . Additionally, the accumulator  177  may be directly coupled to the product stream  154 ″.  
      When the product stream  154 ″ passes through the expansion valves  174  and  176 , the stream follows a constant enthalpy pressure drop that changes from a high pressure, single phase mixture at a high pressure and low temperature (e.g., approximately 1,100 psig and approximately −200° F.) to three phases (solid, liquid and gas) with approximately 10% to 28% mass flow being vapor, at a reduced pressure of, for example, 35 psig. The solid component includes solid CO 2  The vapor component from the separator  180  is collected and removed therefrom through piping  182  and is routed back to the heat exchanger  166  to provide additional cooling by way of a compressor  186 . While shown to be located on the warm side of the heat exchanger  166 , the compressor  186  could be positioned on the cold side of the heat exchanger  166 , although such positioning might require the compressor to be configured as a cryogenic compressor. In one embodiment, the compressor  186  may be powered by an internal combustion engine driven by a portion of the natural gas flowing through the plant  102 . In another embodiment, the compressor  186  may be powered by electricity or other means as will be appreciated by those of ordinary skill in the art. It is further noted that an ejector or an eductor might be utilized in place of the compressor  186  in other embodiments.  
      To maintain the separator  180  at a desired pressure, for example at approximately 35 psig, the compressor  186  may be used to recompress the excess gas from the separator  180  to pressures suitable, for example, for introduction of the gas into the heat exchanger  166 . For example, the compressor  186  may be used to increase the pressure of the gas from approximately 35 psig to approximately 50 psig. The compressor  186  may also be coupled to a vent line associated with the storage tank  116  to likewise help maintain the pressure within storage tank  116  at substantially the same pressure as that of the separator  180 .  
      A make up line  187  having a regulator  188  may be routed around the compressor  186  to prevent flow surges as may be the case when gas flow from the separator  180  and or storage tank  116  is relatively low. The pressure of such a regulator may be set at a level that is just under the desired saturation pressure for the separator  180 . In one embodiment, a floating ball check valve may also be installed in the suction line of the compressor  186  to prevent a sudden surge of liquid. If the compressor  186  is located on the cold side of the heat exchanger  166 , the floating ball check valve may also be used to prevent any accumulated liquid from entering the suction side of the pump. It is noted that if the compressor  186  is located on the warm side of the heat exchanger  166 , no liquid will be present at the suction side of the compressor  186  under normal operating conditions.  
      A back-pressure regulator may be located in the vapor piping  182  to also help control the pressure within the separator  180 . In one example, the back pressure regulator  184  may be configured with set-point of approximately 35 psig so as to create a saturation pressure of the liquid that is below a desired transfer pressure (i.e., the pressure used to transfer liquid from the separator  180  to other components within the plant  102 ).  
      In one embodiment, and as previously described with respect to other embodiments, the storage tank  116  may be maintained at substantially the same pressure as that of the separator  180 . By maintaining the liquid saturation pressure below associated transfer pressures, the liquid is prevented from boiling when the liquid experiences a pressure drop such as will occur when the liquid flows through piping, valves and other equipment as it is transferred from the separator  180 . The pressure difference between the separator  180  (e.g., approximately 35 psig) and a transfer pressure may be specified such that it is sufficient to ensure that any and all line pressure drops encountered en route to the storage tank  116  are accounted for. The liquid will then arrive at the storage tank  116  at saturation pressure, minimizing loss and flow complications that might otherwise occur due to boiling of the liquid during the transfer thereof.  
      As noted above, solid CO 2  mostly forms as small crystals in the liquid as it exits the JT valves  174  and  176 . With the appropriate resident time in the liquid, the CO 2  becomes a sub-cooled solid particle. In the sub-cooled state the particles are less likely to clump together. Keeping the particles suspended in the liquid provides more effective and efficient transfer and separation of the solids from the liquid component. To aid in keeping the CO 2  particles suspended in the liquid, gas bubbles may be introduced into the bottom of the separator  180  in a manner similar to that previously described.  
      As the separator  180  is filled, the level may be monitored by appropriate sensors. The level of the liquid/solid within the separator  180  may be desirably monitored and controlled in order to provide desired resident times for the CO 2  and thereby ensure that the CO 2  particles are subcooled. When a specified maximum level of liquid/solid slurry is reached within the separator  180 , the liquid/solid slurry will be transferred to at least one of a plurality of transfer tanks  190 A and  190 B such as previously described.  
      When the separator  180  has reached its specified maximum level, two valves will open allowing the fluid to move into one of the transfer tanks (e.g., transfer tank  190 A for purposes of the present discussion). The first valve  220 A allows the transfer of liquid/CO 2  slurry, while the second valve  222 A vents the transfer tank  190 A back to the separator  180  enabling the captured gases in the transfer tank  190 A to escape as it is being filled with the slurry. Depending, for example, on the length of the piping run between the separator  180  and the transfer tank  190 A, bubbler locations may be added to the bottom of the pipe to prevent the CO 2  from settling during the transfer of the slurry (similar to that which has been previously described with respect to the separator  180 ). It is noted that a single valve may be utilized instead of multiple valves if the single valve is properly located (e.g., physically below the separator  180 ).  
      When the level in the separator  180  tank is reduced to a specified minimum level, the valves  220 A and  222 A to the transfer tank  190 A close. The liquid CO 2  transfer alternates between the two transfer tanks associated with the SGL tank. Once the valves connecting the separator  180  and transfer tank  190 A are closed the liquid/CO 2  mixture is ready to be transferred to the hydrocyclone separator. The pressure sensitive hydrocyclone separates the CO 2  from the liquid by cyclonic action. The transfer tank is pressurized to the desired pressure and the transfer valve is opened. The transfer pressure is approximately 20 psi higher than the saturation pressure of the liquid. This pressure head provides the motive force for the liquid/CO 2  mixture, prevents the liquid from boiling as pressure drops are realized, and prevents the formation of additional CO 2  that could occur if the pressure were to drop below saturation pressure.  
      The transfer tank (considering tank  190 A as an example) is pressurized by use of a pressure regulator  224  which is set at a desired transfer pressure. If the feed line to the transfer tank  190 A is sufficient and the regulator  224  is large enough, a regulator  224  can be mounted directly on the transfer tank  192 A. This would require one regulator for each tank. However, in another embodiment, both transfer tanks  190 A and  190 B could be maintained with a smaller feed line and a single regulator  224  as shown in  FIG. 3 . Use of a single regulator may require the use of storage or accumulator tanks (e.g.,  226 A) to ensure that the proper volume of gas is used so as to maintain a constant pressure during the complete transfer process. It is noted that the gas used to transfer the liquid will be warmer than the liquid/solid slurry being transferred. As such, any heat transfer effects are accounted for in configuring and sizing the regulator(s)  224 A and accumulator tank(s)  226 A.  
      As previously noted, the liquid/solid slurry is transferred to, and processed by, one of the hydrocyclones  192 A and  192 B. The hydrocyclones  192 A and  192 B act as separators to remove the solid CO 2  from the slurry allowing the LNG or other liquid product to be collected and stored in a manner similar to that previously described herein in association with other embodiments.  
      Generally, the liquid natural gas flows through the overflow  196 A of the hydrocyclone  192 A and may flow through one of a plurality of filters  200 A and  200 B placed in a parallel flow configuration. The filters  200 A and  200 B capture any remaining solid CO 2  which may not have been separated out in the hydrocyclone  192 A. The filters  200 A and  200 B may be configured such as substantially described in the priority patent applications and patents that have been incorporated by reference.  
      The filters  200 A and  200 B may, from time to time, become clogged or plugged with solid CO 2  captured therein. Thus, as one filter, i.e.,  200 A, is being used to capture CO 2  (or other solids) from the liquid stream, the other filter, i.e.,  200 B, may be purged of CO 2  by passing a relatively high temperature natural gas therethrough in a counter flowing fashion. For example, gas may be drawn from a relatively warmer gas stream, as indicated at interface points  202 B (or  202 A for filter  200 A) and  202 C to flow through and clean the filter  200 B as has been previously described. The filtered liquid passes from the filter  200 A (or  200 B) to the storage tank.  
      It is noted that, in the presently described embodiment, the plant  102 ′ does not include a diversion tank (e.g., diversion tank  206  in  FIG. 2 ) or a make-up pump (e.g., make-up pump  210  in  FIG. 2 ) since none of the liquid produced by the plant  102 ′ is being returned or recycled to act as a refrigerant. Rather, the refrigeration system  302  described above is configured to provide adequate cooling such that all of the liquid produced by the plant  102 ′ may be collected as a product.  
      Referring briefly back to the hydrocyclones  192 A and  192 B, the thickened slush formed in the hydrocyclone (e.g.,  192 A) exits the underflow  194 A and passes through piping  213 A to a sublimation tank  214  in a manner similar to that which has been previously described herein.  
      The gas leaving the sublimation tank (including both the warming gas and the sublimed CO 2 ) may be routed back to the expanded cooling stream  152 ′ to assist in cooling the compressed process stream  154 ′ in heat exchanger  166 .  
      As previously noted hereinabove, the plant  102 ′ may include a recompression compressor  228 . The recompression compressor  228  may be used to recompress gas to a desired pressure prior to reintroduction of the gas into the pipeline  104  (or other receiving station, reservoir or system) or prior to the recirculation of gases into the plant  102  for reprocessing thereof. Gas from the separator  180  and from the storage tank  116  may be used, for example, as fuel for a combustion engine that drives the recompression compressor  228 .  
      It is noted that, while not specifically shown, and as with other embodiments described herein, a number of valves may be placed throughout the liquefaction plant  102 ′ for various purposes such as facilitating physical assembly and startup of the plant  102 ′, maintenance activities, or for collecting of material samples at desired locations throughout the plant  102 ′ as will be appreciated by those of ordinary skill in the art.  
      It is further noted that the plant  102 ′ may also be configured as a relatively compact structure such as described in the applications and patents previously incorporated by reference. Generally, the plant  102 ′ may be constructed on one or more skids for simple transportation and erection of the plant  102 ′.  
      As with other embodiments, the plant  102 ′ may include a variety of controls for effective and efficient operation thereof. Examples of various control schemes are described in association with other embodiments set forth in the present application as well as the various patents and patent applications that have been incorporated by reference herein.  
      The liquefaction processes depicted and described herein with respect to the various embodiments provide for low cost, efficient and effective means of producing LNG without the requisite “purification” of the gas before subjecting the gas to the liquefaction cycle. Such enable the use of relatively “dirty” gas typically found in transmission and distribution lines, eliminates the requirement for expensive pretreatment equipment and provides a significant reduction in operating costs for processing such relatively “dirty” gas.  
      It is noted that, while the invention has been disclosed primarily in terms of liquefaction of natural gas, the present invention may be utilized simply for removal of gas components, such as, for example, CO 2  from a stream of relatively “dirty” gas. Additionally, other gases, such as for example, hydrogen, may be liquefied and processed, and other gas components, such as, for example, nitrogen, may be removed from a given feed gas. Thus, the present invention is not limited to the liquefaction of natural gas and the removal of CO 2  therefrom. It is also noted that various teachings set forth in the documents incorporated by reference herein may be combined with one or more of the embodiments described herein and that the described embodiments are not limited by their specific examples.  
      While the invention may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. However, it should be understood that the invention is not intended to be limited to the particular forms disclosed. Rather, the invention includes all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the following appended claims.