Patent Publication Number: US-7594414-B2

Title: Apparatus for the liquefaction of natural 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 May 5, 2005, now U.S. Pat. No. 7,219,512, issued May 22, 2007, which is a continuation of U.S. patent application Ser. No. 10/414,991, filed Apr. 14, 2003, now U.S. Pat. No. 6,962,061, issued Nov. 8, 2005, which is a divisional of U.S. patent application Ser. No. 10/086,066, filed Feb. 27, 2002, now U.S. Pat. No. 6,581,409, issued 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 related to U.S. patent application Ser. No. 11/383,411, filed May 15, 2006, U.S. patent application Ser. No. 11/674,984, filed Feb. 14, 2007, U.S. patent application Ser. No. 11/536,477, filed Sep. 28, 2006, U.S. patent application Ser. No. 11/560,682, filed Nov. 16, 2006, U.S. patent application Ser. No. 11/855,071, filed Sep. 13, 2007, and U.S. patent application Ser. No. 09/643,420, filed Aug. 23, 2001, now U.S. Pat. No. 6,425,263, issued Jul. 30, 2002, which is a continuation of U.S. patent application Ser. No. 09/212,490, filed Dec. 16, 1998, now U.S. Pat. No. 6,105,390, issued Aug. 22, 2000, which claims benefit of U.S. Provisional Application No. 60/069,988 filed Dec. 16, 1997, the disclosures of which are hereby incorporated herein in their entirety by this reference. 
    
    
     GOVERNMENT RIGHTS 
     This invention was made with government support under Contract No. DE-AC07-05ID14517 awarded by the United States Department of Energy. The government has certain rights in this invention. 
    
    
     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 partial 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 very 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 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 and 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. 
     Additionally, to make the operation of conventional systems cost effective, such systems are conventionally built on a large scale to handle 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 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, such as residential or industrial service gas, 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 plant for carrying out such a process, of efficiently producing liquefied natural gas on a small scale. More particularly, 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 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 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 
     In accordance with one aspect of the invention, a method is provided for removing carbon dioxide from a mass of natural gas. The method includes cooling at least a portion of the mass of natural gas to form a slurry which comprises at least liquid natural gas and solid carbon dioxide. The slurry is flowed into a hydrocyclone and a thickened slush is formed therein. The thickened slush comprises the solid carbon dioxide and a portion of the liquid natural gas. The thickened slush is discharged through an underflow of the hydrocyclone while the remaining portion of liquid natural gas is flowed through an overflow of the hydrocyclone. 
     Cooling the portion of the mass of natural gas may be accomplished by expanding the gas, such as through a Joule-Thomson valve. Cooling the portion of the mass of natural gas may also include flowing the gas through a heat exchanger. 
     The method may also include passing the liquid natural gas through an additional carbon dioxide filter after it exits the overflow of the hydrocyclone. 
     In accordance with another aspect of the invention, a system is provided for removing carbon dioxide from a mass of natural gas. The system includes a compressor configured to produce a compressed stream of natural gas from at least a portion of the mass of natural gas. At least one heat exchanger receives and cools the compressed stream of natural gas. An expansion valve, or other gas expander, is configured to expand the cooled, compressed stream and form a slurry therefrom, the slurry comprising liquid natural gas and solid carbon dioxide. A hydrocyclone is configured to receive the slurry and separate the slurry into a first portion of liquid natural gas and a thickened slush comprising the solid carbon dioxide and a second portion of the liquid natural gas. 
     The system may further include additional heat exchangers and gas expanders. Additionally, carbon dioxide filters may be configured to receive the first portion of liquid natural gas for removal of any remaining solid carbon dioxide. 
     In accordance with another aspect of the invention, a liquefaction plant is provided. The plant includes a plant inlet configured to be coupled with a source of natural gas, which may be unpurified natural gas. A turbo expander is configured to receive a first stream of the natural gas drawn through the plant inlet and to produce an expanded cooling stream therefrom. A compressor is mechanically coupled to the turbo expander and configured to receive a second stream of the natural gas drawn through the plant inlet and to produce a compressed process stream therefrom. A first heat exchanger is configured to receive the compressed process stream and the expanded cooling stream in a countercurrent flow arrangement to cool to the compressed process stream. A first plant outlet is configured to be coupled with the source of unpurified gas such that the expanded cooling stream is discharged through the first plant outlet subsequent to passing through the heat exchanger. A first expansion valve is configured to receive and expand a first portion of the cooled compressed process stream and form an additional cooling stream, the additional cooling stream being combined with the expanded cooling stream prior to the expanded cooling stream entering the first heat exchanger. A second expansion valve is configured to receive and expand a second portion of the cooled compressed process stream to form a gas-solid-vapor mixture therefrom. A first gas-liquid separator is configured to receive the gas-solid-vapor mixture. A second plant outlet is configured to be coupled with a storage vessel, the first gas-liquid separator being configured to deliver a liquid contained therein to the second plant outlet. 
     In accordance with another aspect of the invention, a method of producing liquid natural gas is provided. The method includes providing a source of unpurified natural gas. A portion of the natural gas is flowed from the source and divided into a process stream and a first cooling stream. The first cooling stream is flowed through a turbo expander where work is produced to power a compressor. The process stream is flowed through the compressor and is subsequently cooled by the expanded cooling stream. The cooled, compressed process stream is divided into a product stream and a second cooling stream. The second cooling stream is expanded and combined with the first expanded cooling stream. The product stream is expanded to form a mixture comprising liquid, vapor and solid. The liquid and solid is separated from the vapor, and at least a portion of the liquid is subsequently separated from the liquid-solid mixture. 
     In accordance with yet another aspect of the present invention, another liquefaction plant is provided. The liquefaction plant includes a first flow path comprising a first stream of natural gas flowing sequentially through a compressor, a first side of a first heat exchanger and a first side of a second heat exchanger. A second flow path includes a second stream of natural gas flow sequentially through an expander, a second side of the second heat exchanger and a second side of the first heat exchanger. At least two paths, including a cooling path and liquid production path, are formed from the first flow path subsequent flow of the first stream of natural gas through the first side of the second heat exchanger. The cooling path selectively directs at least a first portion of the first stream of natural gas to the second side of the second heat exchanger. The liquid production path selectively directs a second portion of the first stream of natural gas to a gas-liquid separator. 
     In accordance with a further aspect of the present invention, another 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 flows sequentially through a compressor, a first side of a first heat exchanger and a first side of a second heat exchanger. The cooling stream flows sequentially through an expander, a second side of the second heat exchanger and a second side of the first heat exchanger. A temperature of the process stream is sensed after it exits the first side of the second heat exchanger. Substantially all of the process stream flows from the first side of the second heat exchanger to the second side of the heat exchanger if the sensed temperature is warmer than a specified temperature. A first portion of the process stream flows from the first side of the second heat exchanger to the second side of the second heat exchanger and a second portion of the process stream flows from the first side of the second heat exchanger to a gas-liquid separator if the sensed temperature is equal to or colder than the specified temperature. 
     In accordance with yet a further aspect of the present invention, a method of controlling a plurality of valves is provided such that the plurality of valves act cooperatively as a single valve. The method includes defining a number (N) of a plurality of valves. A flow capacity (Cv) is determined for each valve and the Cvs of the individual valves are summed to determine a cumulative flow capacity. A ratio of cumulative flow capacity to individual Cv is determined for each valve. The actuation of each valve is controlled with a proportional, integral, derivative (PID) control loop with a specified output resolution wherein a range of resolution is assigned to each valve based on their respective determined ratios. Each valve is actuated when an output of the PID control loop corresponds with the associated range of the respective valve. 
    
    
     
       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 the basic cycle of a liquefaction plant according to one embodiment of the present invention; 
         FIG. 3  is a process flow diagram depicting a water clean-up cycle integrated with the liquefaction cycle according an embodiment of the present invention; 
         FIG. 4  is a process flow diagram depicting a carbon dioxide clean-up cycle integrated with a liquefaction cycle according to an embodiment of the present invention; 
         FIGS. 5A and 5B  show a heat exchanger according to one embodiment of the present invention; 
         FIG. 5C  shows the heat exchanger of  FIGS. 5A and 5B  with additional features in accordance with another embodiment of the present invention; 
         FIGS. 6A and 6B  show plan and elevational views of cooling coils used in the heat exchanger of  FIGS. 5A and 5B ; 
         FIGS. 7A through 7C  show a schematic of different modes of operation of the heat exchanger depicted in  FIGS. 5A and 5B  according to various embodiments of the invention; 
         FIGS. 8A and 8B  show perspective and elevational views, respectively, of a plug which may be used in conjunction with the heat exchanger of  FIGS. 5A and 5B ; 
         FIG. 9  is a cross-sectional view of a filter used in conjunction with the liquefaction plant and process of  FIG. 4 ; 
         FIG. 10  is a process flow diagram depicting a liquefaction cycle according to another embodiment of the present invention; 
         FIG. 11  is a process schematic showing a differential pressure circuit incorporated in the liquefaction plant and process of  FIG. 10 ; 
         FIG. 12  is a process flow diagram depicting a liquefaction cycle according to another embodiment of the present invention; 
         FIG. 13  is a perspective view of a liquefaction plant according to one embodiment of the present invention; 
         FIG. 14  shows the liquefaction plant of  FIG. 4  in transportation to a plant site; 
         FIG. 15  is a process flow diagram showing state points of the flow mass throughout the system according to one embodiment of the present invention; 
         FIG. 16  shows an apparatus used to divert the flow within the coils of the heat exchangers of  FIGS. 5A-5C  in accordance with an embodiment of the present invention; 
         FIG. 17  shows an exploded view of a portion of the apparatus of  FIG. 16 ; 
         FIG. 18  is a process flow diagram depicting a liquefaction cycle according to yet another embodiment of the present invention; 
         FIGS. 19A-19E  are block diagrams showing control loops which may be used in accordance with various embodiments of the present invention; 
         FIG. 20  is a flow diagram relating to a control process that may used with a liquefaction plant in accordance with an embodiment of the present invention; 
         FIG. 21  is a graph showing a relationship of proportional gain and temperature which may be used in controlling portions of a liquefaction plant in accordance with an embodiment of the present invention; 
         FIG. 22  is a flow diagram showing logic that may be used in controlling certain components of a liquefaction plant in accordance with an embodiment of the present invention; and 
         FIG. 23  is a process flow diagram showing state points of the flow mass throughout the system according to one 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 the capacity of producing, for example, approximately 10,000 gallons of LNG a day but may be scaled for a different output as needed and is not limited to small-scale operations or plants. Additionally, as shall be set forth in more detail below, the liquefaction plant  102  of the present invention is considerably smaller in physical size than a large-scale plant and may be readily transported from one site to another. 
     One or more pressure regulators  106  are 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 300 to 1000 pounds per square inch absolute (psia) while the pressure downstream of the regulators may be reduced to approximately 65 psia, 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 inlet  112 ) is not critical as the pressure thereof may be raised, for example by use of an auxiliary booster pump, heat exchanger, or both, prior to the gas entering the liquefaction process described herein. It is further noted that the regulators  106  may be positioned near the liquefaction plant  102  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 and one regulator may be associated with a different flow circuit than another regulator. 
     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  108  entering the liquefaction plant  102  becomes LNG and exits the liquefaction 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 30 to 35 psia and at temperatures 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 liquefaction 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  which also allows 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 connections  136 A and  136 B. Such vent piping  134  will similarly carry gas into the downstream section  130  of 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 liquefaction plant  102  and/or inside the liquefaction plant  102 , 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  140  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  140  removed from pipeline  104 . Similarly, optional flow meter  120  and valve/meter set  124  indicate the net discharge of LNG 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 . As previously indicated with respect to  FIG. 1 , a high pressure stream of feed gas (i.e., 300 to 1000 psia), for example, at a temperature of approximately 60° F. enters the liquefaction plant  102  through the plant inlet  112 . Prior to processing the feed gas  140 , a small portion of feed gas  140  may be split off, passed through a drying filter  142  and utilized as instrument control gas in conjunction with operating and controlling various components in the liquefaction plant  102 . While only a single stream  144  of instrument gas is depicted, it will be appreciated by those of skill in the art that multiple lines of instrument gas may be formed in a similar manner. 
     Alternatively, 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  146  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  146  may additionally be utilized to remove certain liquid and solid components. For example, the filter  146  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  146  may be provided with an optional drain  148  which discharges into piping near the second plant outlet  132 , as is indicated by interface connections  136 C and  136 A, the discharge ultimately reentering the downstream section  130  of the pipeline  104  (see  FIG. 1 ). Bypass piping  150  is routed around the filter  146 , allowing the filter  146  to be isolated and serviced, as may be required, without interrupting the flow of gas through the liquefaction plant  102 . 
     After the feed gas  140  flows through the filter  146  (or alternatively around the filter by way of piping  150 ) the feed gas  140  is split into two streams, a cooling stream  152  and a process stream  154 . The cooling stream  152  passes through a turbo expander  156  and is expanded to an expanded cooling stream  152 ′ exhibiting a lower pressure, for example between approximately 100 psia and atmospheric pressure, at a reduced temperature of approximately −100° F. The turbo expander  156  is a turbine which expands the gas and extracts power from the expansion process. A rotary compressor  158  is coupled to the turbo expander  156  by mechanical means, such as with a shaft  160 , and utilizes the power generated by the turbo expander  156  to compress the process stream  154 . The proportion of gas in each of the cooling and process lines  152  and  154 , respectively, 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 , respectively, as is required according to the above stated parameters. 
     Examples of a turbo expander  156  and compressor  158  system include a frame size ten (10) system available from GE Rotoflow, Inc., located in Gardena, Calif. In one embodiment, the expander  156  and compressor  158  system is designed to operate at approximately 440 psia at 5,000 pounds mass per hour at about 60° F. The expander/compressor system may also be fitted with magnetic bearings to reduce the footprint of the expander  156  and compressor  158 , as well as simplify maintenance thereof. In another embodiment, the expander/compressor system may be fitted with gas bearings. Such bearings may utilize a portion of the feed gas flowing through the liquefaction plant  102  or may be supplied with a separate flow of gas such as nitrogen. 
     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 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  allows the heat exchanger  166 , and/or other components, to be brought to a steady state temperature without inducing thermal shock. Additionally, if the pressure of the feed gas  140  is sufficient, the compressor  158  need not be used and the process stream  154  may continue through the bypass piping  164 . Indeed, if it is known that the pressure of the feed gas  140  will remain at a sufficiently high pressure, the compressor  158  could conceivably be eliminated. In such a case where the compressor  158  was not being utilized, the work generated by the expander  156  could be utilized to drive a generator or power some other component, if desired. 
     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 (i.e., the heat exchanger  166 ) being used in the liquefaction plant  102 , 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 , passes through a Joule-Thomson (JT) valve  163  allowing the cooling stream  152  to expand thereby, reducing its temperature. The JT valve  163  utilizes the Joule-Thomson principle that expansion of gas will result in an associated cooling of the gas as well, as is understood by those of ordinary skill in the art. The cooling stream  152  may then be used to incrementally reduce the temperature of the heat exchanger  166 . 
     In one embodiment, as discussed in more detail below, 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 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  165  or instruments may be controlled, accordingly, in order to effect the rate and pressure of flow in the cooling stream  152  and compressed process stream  154 ′ which ultimately controls the cooling rate of heat exchanger  166  and/or other components of the liquefaction plant  102 . 
     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 . 
     Upon achieving a steady state condition, the process stream  154  is flowed through the compressor  158  which raises 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 the heat exchanger  166  and is cooled to a very low temperature, for example approximately −200° F. The heat exchanger  166  depicted in  FIG. 2  is a type utilizing countercurrent flow, as is known by those of ordinary skill in the art although other types may be used. 
     After exiting the heat exchanger  166 , the cooled compressed process stream  154 ″ is split into two new streams, a cooling stream  170  and a product stream  172 . The cooling stream  170  and the product stream  172  are each expanded through JT valves  174  and  176 , respectively. The expansion of the cooling and process streams  170  and  172  through the JT valves  174  and  176  result in a reduced pressure, such as, for example, between approximately 100 psia and atmospheric, and a reduced temperature, for example, of approximately −240° F. The reduced pressure and temperatures will cause the cooling and product streams  170  and  172  to form a mixture of liquid and vapor natural gas. 
     The cooling stream  170  is combined with the expanded cooling stream  152 ′ exiting the turbo expander  156  to create a combined cooling stream  178 . The combined cooling stream  178  is then used to cool the compressed process stream  154 ′ via the heat exchanger  166 . After cooling the compressed process stream  154 ′ in the heat exchanger  166 , the combined cooling stream  178  may be discharged back into the natural gas pipeline  104  at the downstream section  130  ( FIG. 1 ). In other embodiments, the cooling streams (e.g., cooling stream  170  and expanded cooling stream  152 ′) could be introduced into the heat exchanger  166  independently. Such cooling streams could remain as independent streams flowing through the heat exchanger  166  or become a combined cooling stream (similar to combined cooling stream  178 ) while flowing through the heat exchanger  166  or subsequent to their discharge therefrom. 
     After expansion via the JT valve  176 , the product stream  172  enters into a liquid/vapor separator  180 . The vapor component from the separator  180  is collected and removed therefrom through line  182  and is added to the combined cooling stream  178  at a location upstream of its entrance into the heat exchanger  166 . The liquid component in the separator  180  is the LNG fuel product and passes through the plant outlet  114  for storage in the vessel  116  ( FIG. 1 ). 
     By controlling the proportion of gas respectively flowing through the cooling and product streams  170  and  172 , the thermodynamics of the process will produce a product stream that has a high liquid fraction. If the liquid fraction is high, i.e., greater than 90%, the methane content in the liquid will be high and the heavy hydrocarbons (ethane, propane, etc.) will be low, thus approaching the same composition as the incoming gas stream into plant inlet  112 . If the liquid fraction is low, the methane content in the liquid will be low, and the heavy hydrocarbon content in the liquid will be high. The heavy hydrocarbons add more energy content to the fuel, which causes the fuel to burn hotter in combustion processes. 
     Referring now to  FIG. 3 , a process flow diagram is shown depicting a liquefaction process performed in accordance with another embodiment of a liquefaction plant  102 ′. As the liquefaction plant  102 ′ and the process carried out thereby share a number of similarities with the liquefaction plant  102  and process depicted in  FIG. 2 , like components are identified with like reference numerals for sake of clarity. 
     Liquefaction plant  102 ′ essentially modifies the basic cycle shown in  FIG. 2  to allow for removal of water from the natural gas stream during the production of LNG and for prevention of ice formation throughout the system. The water clean-up cycle includes a source of methanol  200 , or some other water absorbing product, which is injected into the gas stream, via a pump  202 , at a location prior to the gas being split into the cooling stream  152  and the process stream  154 . The pump  202  desirably includes variable flow capability to inject methanol  200  into the gas stream such as, for example, by way of at least one of an atomizing or a vaporizing nozzle. In another embodiment, valving  203  may be used to accommodate multiple types of nozzles 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. 
     A suitable pump  202  for injecting the methanol  200  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 two to seven 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  202 . For example, one such pump is available from America LEWA located in Holliston, Mass. as model number EKM7-2-10MM. 
     The methanol  200  is mixed with the gas stream to lower the freezing point of any water which may be contained therein. The methanol  200  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 . Additionally, as noted above, the methanol  200  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  200  and water become liquid. The compressed process stream  154 ′ is temporarily diverted from the heat exchanger  166  and passed through a separating tank  204  wherein the methanol/water liquid is separated from the compressed process stream  154 ′, the liquid being discharged through a valve  206  and the gas flowing to a coalescing filter  208  to remove an additional amount of the methanol/water mixture. The methanol/water mixture may be discharged from the coalescing filter  208  through a valve  210  with the dried gas reentering the heat exchanger  166  for further cooling and processing. As is indicated by interface connections  136 D and  136 A, both valves  206  and  210  discharge the removed methanol/water mixture into piping near the second plant outlet  132  for discharge into the downstream section  130  of the pipeline  104  (see  FIG. 1 ). 
     In one example, a coalescing filter  208  used for removing the methanol/water mixture may be designed to process natural gas at approximately −70° F. at flows of approximately 2500 SCFM and at a pressure of approximately 800 psia. Such a filter may exhibit an efficiency of removing the methane/water mixture to less than 75 ppm/w. A suitable filter is available from Parker Filtration, located in Tewksbury, Mass. Another suitable coalescing filter includes model number RO1-183746 with filter #200-80DX from MDA Filtration, Ltd. 
     The liquefaction process shown in  FIG. 3  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 turbo expander  156 . 
     Referring now to  FIG. 4 , a process flow diagram is shown depicting a liquefaction process performed in accordance with another embodiment of the liquefaction plant  102 ″. As the liquefaction plant  102 ″ and process carried out therein share a number of similarities with liquefaction plants  102  and  102 ′ and the processes depicted in  FIGS. 2 and 3  respectively, like components are again identified with like reference numerals for sake of clarity. Additionally, for sake of clarity, the portion of the cycle between the plant inlet  112  and the expander  156 /compressor  158  is omitted in  FIG. 4 , but may be considered an integral part of the liquefaction plant  102 ″ and process shown in  FIG. 4 . 
     The liquefaction plant  102 ″ shown in  FIG. 4  modifies the basic cycle shown in  FIG. 2  to incorporate an additional cycle for removing carbon dioxide (CO 2 ) from the natural gas stream during the production of LNG. While the liquefaction plant  102 ″ and process of  FIG. 4  are shown to include the water clean-up cycle described in reference to liquefactionplant  102 ′ and the process of  FIG. 3 , the CO 2  clean-up cycle is not dependent on the existence of the water clean-up cycle and may be independently integrated with the inventive liquefaction process. 
     The heat exchange process may be divided or distributed among three different heat exchangers  166 ,  220  and  224 . The first heat exchanger  220  in the flow path of the compressed process stream  154 ′ uses ambient conditions, such as, for example, air, water, or ground temperature or a combination thereof, for cooling the compressed process stream  154 ′. The ambient condition(s) heat exchanger  220  serves to reduce the temperature of the compressed process stream  154 ′ to ensure that the heat generated by the compressor  158  does not thermally damage the high efficiency heat exchanger  166  which sequentially follows the ambient heat exchanger  220  during the flow of the compressed process stream  154 ′. 
     In one example, the ambient heat exchanger  220  may be designed to process the compressed process stream  154 ′ at approximately 6700 to 6800 lbs mass per hour (lbm/hr) at a design pressure of approximately 800 psia. The heat exchanger  220  may further be configured such that the inlet temperature of the gas is approximately 240° F. and the outlet temperature of the gas is approximately 170° F. with an ambient source temperature (i.e., air temperature, etc.) being approximately 100° F. If such a heat exchanger is provided with a fan, such may be driven by a suitable electric motor. 
     The high efficiency heat exchanger  166 , sequentially following the ambient heat exchanger  220  along the flow path, 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 model number 01-46589-1 heat exchanger available from Chart Industries, Inc. of La Crosse, Wis. 
     The high efficiency heat exchanger  166  is positioned and configured to efficiently transfer as much heat as possible from the compressed process stream  154 ′ to the combined cooling stream  178 ′. The high efficiency heat exchanger  166  may be configured such that the inlet temperature of the gas will be approximately 170° F. and the outlet temperature of the gas will be approximately −105° F. The liquefaction plant  102 ″ is desirably configured such that temperatures generated within the high efficiency heat exchanger  166  are never low enough to generate solid CO 2  which might result in blockage in the flow path of the compressed process stream  154 ′. 
     The third heat exchanger  224  sequentially located along the flow path of the process stream (sometimes referred to herein as the CO 2  heat exchanger  224  for purposes of convenience and clarity) is, in part, associated with the processing of solid CO 2  removed from the process stream at a later point in the cycle. More specifically, the CO 2  heat exchanger  224  prepares the CO 2  for reintroduction into the gas pipeline  104  at the downstream section  130  (see  FIG. 1 ) by subliming the removed solid CO 2  in anticipation of its discharge back into the pipeline  104 . The sublimation of solid CO 2  in the CO 2  heat exchanger  224  helps to prevent damage to, or the plugging of, heat exchanger  166 . It is noted that heat exchangers  166  and  224  could be combined if desired. The sublimation of the solid CO 2  also serves to further chill the process gas in anticipation of the liquefaction thereof. 
     An example of a heat exchanger  224  used for processing the solid CO 2  may include a tube-in-shell type heat exchanger. Referring to  FIG. 5A , a tube-in-shell heat exchanger  224  is shown with a portion of the tank  230  stripped away to reveal a plurality of, in this instance three, cooling coils  232 A- 232 C stacked vertically therein. A filter material  234  may also be disposed in the tank  230  about a portion of the lower coil  232 A to ensure that no solid CO 2  exits the heat exchanger  224 . The filter material  234  may include, for example, stainless steel mesh. One or more structural supports  236  may be placed in the tank to support the coils  232 A- 232 C as may be required depending on the size and construction of the coils  232 A- 232 C. 
     Referring briefly to  FIGS. 6A and 6B , an example of a cooling coil  232  may include inlet/outlet pipes  238  and  240  with a plurality of individual tubing coils  242  coupled therebetween. The tubing coils  242  are in fluid communication with each of the inlet/outlet pipes  238  and  240  and are structurally and sealingly coupled therewith. Thus, in operation, fluid may flow into the first inlet/outlet pipe  238  for distribution among the plurality of tubing coils  242  and pass from the tubing coils  242  into the second inlet/outlet pipe  240  to be subsequently discharged therefrom. Of course, if desired, the flow through the cooling coils  232  could be in the reverse direction as set forth below. 
     A cooling coil  232  may include, for example, inlet/outlet pipes  238  and  240  which are formed of 3-inch diameter, schedule 80 304L stainless steel pipe. The tubing coils  242  may be formed of 304L stainless steel tubing having a wall thickness of 0.049 inch. The cooling coils  232  may further be designed and sized to accommodate flows having, for example, but not limited to, pressures of approximately 815 psia at a temperature between approximately −240° F. and 200° F. Such coils are available from the Graham Corporation located in Batavia, N.Y. 
     Referring back to  FIG. 5A , the ends of the inlet/outlet pipes  238  and  240  of each individual cooling coil, for example coil  232 B, are sealingly and structurally coupled to the corresponding inlet/outlet pipes  238  and  240  of each adjacent coil, i.e.,  232 A and  232 C. Such connection may be made, for example, by welding or by other mechanical means. 
     Referring now to  FIG. 5B , the tank  230  includes a shell  244  and end caps  246  with a plurality of inlets and outlets coupled therewith. The shell  244  and end caps  246  may be formed of, for example, 304 or 304L stainless steel such that the tank  230  has a design pressure of approximately 95 psia for operating temperatures of approximately −240° F. Desirably, the tank  230  may be designed with adequate corrosion allowances for a minimum service life of 20 years. 
     Fluid may be introduced into the cooling coils  232 A- 232 C (not shown) through one of a pair of coil inlets  248 A and  250 A which are respectively coupled with the inlet/outlet pipe(s)  238  and  240  of a cooling coil  232 A (not shown). The coil inlets  248 A and  250 A may be designed, for example, to accommodate a flow of high density gas at approximately 5000 lbm/hr having a pressure of approximately 750 psia at a temperature of approximately −102° F. 
     A set of coil outlets  248 B and  250 B are respectively associated with, and sealingly coupled to, the inlet/outlet pipes  238  and  240  of a coil  232 C (not shown). Each coil outlet  248 B and  250 B may be designed, for example, to accommodate a flow of high density fluid of approximately 5000 lbm/hr having a pressure of approximately 740 psia at a temperature of approximately −205° F. 
     A plurality of tank inlets  252 A- 252 I are coupled with the tank  230  allowing the cooling streams  253  and  255  ( FIG. 4 ), including removed solid CO 2 , to enter into the tank  230  and flow over one or more coils  232 A- 232 C. For example, tank inlets  252 A- 252 C allow one or more of the cooling streams  253  and  255  to enter the tank  230  and flow over coil  232 A, while tank inlets  252 D- 252 F allow one or more of the cooling streams  253  and  255  to enter the tank  230  and flow first over coil  232 B and then over coil  232 A. The tank inlets  252 A- 252 I may be positioned about the periphery of the shell  244  to provide a desired distribution of the cooling streams  253  and  255  with respect to the coils  232 A- 232 C. 
     Each tank inlet  252 A- 252 I may be designed to accommodate flows having varying characteristics. For example, tank inlet  252 G may be designed to accommodate a slurry of liquid methane having approximately 10% solid CO 2  at a mass flow rate of approximately 531 lbm/hr having a pressure of approximately 70 psia and a temperature of approximately −238° F. Tank inlet  252 H may be designed to accommodate a flow of mixed gas, liquid and solid CO 2  at a flow rate of approximately 1012 lbm/hr exhibiting a pressure of approximately 70 psia and a temperature of approximately −218° F. Tank inlet  252 I may be designed to accommodate a flow of mixed gas, liquid and solid CO 2  at a flow rate of approximately 4100 lbm/hr exhibiting a pressure of approximately 70 psia and a temperature of approximately −218° F. 
     It is also noted that, while not shown in the drawings, an interior shell may be formed about the cooling coils  232 A- 232 C such that an annulus may be formed between the interior shell and the shell  244  of tank  230 . The interior shell may be configured to control the flow of the entering cooling streams through the various tank inlets  252 A- 252 I such that the cooling streams flow over the cooling coils  232 A- 232 C but do not contact the shell  244  of tank  230  of the heat exchanger  224 . 
     A tank outlet  254  allows for discharge of the cooling streams  253  and  255  after they have passed over one or more cooling coils  232 A- 232 C. The tank outlet  254  may be designed, for example, to accommodate a flow of gas at a mass flow rate of approximately 5637 lbm/hr having a pressure of approximately 69 psia and a temperature of approximately −158° F. In some designs, the tank outlet  254  may be designed to service at a temperature of approximately −70° F. 
     Referring now to  FIGS. 7A through 7C , a schematic is shown of various flow configurations possible with the heat exchanger  224 . The heat exchanger  224  may be configured such that the process stream  154 ″ entering through the coil inlet  248 A may pass through less than the total number of cooling coils  232 A- 232 C. Thus, if it is desired, the process stream  154 ″ may flow through all three cooling coils  232 A- 232 C, only two of the cooling coils  232 A and  232 B, or through just one of the cooling coils  232 A. For flow through the first coil  232 A, appropriate piping will allow the process stream  154 ″ to exit through associated coil outlet  250 A. Similarly, if it is desired that the process stream  154 ″ flow through coils  232 A and  232 B, it may exit through associated coil outlet  250 B. 
     For example, referring to  FIG. 7A , the process stream  154 ″ may enter coil inlet  248 A to flow, initially, through the inlet/outlet pipe  240 . At a location above where the first cooling coil  232 A is coupled with the inlet/outlet pipe  240 , a flow diverter  251 A blocks the process stream  154 ″ forcing it to flow through the first cooling coil  232 A. While there may be some transitory flow into the other cooling coils  232 B and  232 C, the steady state flow of the process stream  154 ″ will be through the inlet/outlet pipe  238  exiting the coil outlet  250 B. 
     Referring to  FIG. 7B , it can be seen that the use of two flow diverters  251 A and  251 B will cause the process stream  154 ″ to traverse through the first cooling coil  232 A, as was described with respect to  FIG. 7A , and then flow through inlet/outlet pipe  238  until it encounters the second diverter  251 B. The second diverter will cause the process stream  154 ″ to flow through the second cooling coil  232 B and then through the inlet/outlet pipe  240  through the coil outlet  248 B. 
     Referring to  FIG. 7C , it is shown that the use of three flow diverters  251 A- 251 C will caused the process stream  154 ″ to traverse through the first two coils, as was described with respect to  FIG. 7B , and then through inlet/outlet pipe  240  (coil inlet  250 A being capped off) until it encounters the third flow diverter  251 C. The third flow diverter  251 C will cause the process stream  154 ″ to flow through the third cooling coil  232 C and then through the inlet/outlet pipe  238  exiting the coil outlet  250 B. Thus, depending on the placement of the flow diverters  251 A- 251 C, the capacity of the heat exchanger  166  is readily adapted to various processing conditions and output requirements. 
     The flow diverters  251 A- 251 C may comprise plugs, valves or blind flanges as may be appropriate. While valves or blind flanges may be easily adapted to the process when located externally to the heat exchanger  224  (e.g., at coil outlet  248 B) it is desirable that plugs be used in the internal locations (e.g., for the flow diverters  251 A and  251 B adjacent the first and second coils, respectively). An example of a plug  251  is shown in  FIGS. 8A and 8B . The plug  251  may include a threaded exterior portion  290  for engagement with a cooperatively threaded structure within the inlet/outlet pipes  238  and  240 . A keyed head  292  is configured to cooperatively mate with a tool for rotating the plug  251  in association with the plugs&#39; installation or removal from the inlet/outlet pipes  238  and  240 . Additionally, a set of interior threads  294  may be formed in the keyed head  292  so as to lockingly engage the installation/removal tool therewith such that the plug  251  may be disposed in an inlet/outlet pipe  238  and  240  of substantial length. 
     In conjunction with controlling the flow of the process stream  154 ″ through the cooling coils  232 A- 232 C, the cooling stream(s) entering through the tank inlets  252 A- 252 I may be similarly controlled through appropriate valving and piping. 
     Referring briefly to  FIG. 16 , an apparatus for controlling flow within the cooling coils  232 A- 232 C in accordance with another embodiment of the present invention is shown. As seen in  FIG. 16 , a first apparatus  454 A is disposed within the first tube  248  coupled to the cooling coils  232 A- 232 C and a second apparatus  454 B is disposed within the second tube  250  coupled to the cooling coils  232 A- 232 C. Each apparatus  454 A and  454 B includes a structural member  456  coupled to one or more diverter discs  458  at select locations along the longitudinal extent of their respective structural member  456 . It is noted that the diverter discs  458  of the first apparatus  454 A may be disposed at different longitudinal locations (or elevations, as viewed in  FIG. 16 ) than the diverter discs  458  of the second apparatus  454 B. The location of each diverter disc  458  may be selected so as to effect one of a plurality of desired flow paths such as, for example, has been described hereinabove with respect to  FIGS. 7A-7C . 
     Referring to  FIG. 17 , in conjunction with  FIG. 16 , an exploded view of a portion of an apparatus  454 A is shown. The structural member  456  of the apparatus  454 A includes a substantially elongated member such as, for example, a stainless steel threaded rod. The diverter discs  458  may be formed as discrete components or as an assembly of multiple components. In one particular example, a diverter disc  458  may include a first disc component  460  formed of, for example, stainless steel, a second disc component  462  formed of, for example, polyethylene, a third disc component  464  formed of, for example, stainless steel, and a structural reinforcing component  466  which may also be formed of, for example, stainless steel. When assembled, the various components may be pressed against each other such that the second disc component  462  is sandwiched between the first and third disc components  460  and  464 . Appropriate stop members  468 A and  468 B may be used to fix the disc diverter components  460 ,  462  and  464 , as well as the structural reinforcing member  466 , relative to the structural member  456 . For example, in the case that the structural member  456  includes a threaded rod, the stop members  468 A and  468 B may include nuts configured for threaded engagement with the threaded rod. Thus, the diverter discs  458  may be positioned and repositioned as desired by adjusting the stop members  468 A and  468 B. 
     In a more specific embodiment, the structural member  456  may include a ½-13, 304 stainless steel threaded rod, the first disc component  460  may include 0.005 inch thick 300 series stainless steel, the second disc component  462  may include polyethylene exhibiting a thickness of 0.003 inch to 0.005 inch, the third disc component  464  may include 0.008 inch thick 300 series stainless steel, the reinforcing component  466  may include 1/16 inch thick 304L stainless steel, the first stop member  468 A may include a ½-20 304 stainless steel, pass-through, acorn nut, and the second stop member  468 B may include a ½-20 304 stainless steel nut. Of course, other components and other materials may be used to form the apparatus  454 A, if desired. In another example, the diverter discs  458  may be coupled structural member  456  by other means such as, for example, welding, adhesive, or with other mechanical fasteners. 
     Referring back to  FIG. 4 , as the process stream  154 ″ exits the heat exchanger  224  through line  256 , it is divided into a cooling stream  170 ′ and a product stream  172 ′. The cooling stream  170 ′ passes through a JT valve  174 ′ which expands the cooling stream  170 ′ producing various phases of CO 2 , including solid CO 2 , thereby forming a slurry of natural gas and CO 2 . This CO 2  rich slurry enters the CO 2  heat exchanger  224  through one or more of the tank inputs  252 A- 252 I to pass over one or more cooling coils  232 A- 232 C (see  FIGS. 5A and 5B ). 
     The product stream  172 ′ passes through a JT valve  176 ′ and is expanded to a low pressure, for example approximately 35 psia. The expansion via JT valve  176 ′ also serves to lower the temperature, for example to approximately −240° F. At this point in the process, solid CO 2  is formed in the product stream  172 ′. The expanded product stream  172 ″, now containing solid CO 2 , enters the liquid/vapor separator  180  wherein the vapor is collected and removed from the separator  180  through line  182 ′ and added to a combined cooling stream  257  for use as a refrigerant in the CO 2  heat exchanger  224 . The liquid in the liquid/vapor separator  180  will be a slurry comprising the LNG fuel product and solid CO 2 . 
     The slurry may be removed from the separator  180  to a hydrocyclone  258  via an appropriately sized and configured pump  260 . Pump  260  is primarily used to manage vapor generation resulting from a pressure drop through the hydrocyclone  258 . While the pump  260  is schematically shown in  FIG. 4  to be external to the liquid/vapor separator  180 , the pump may be physically located within the liquid/vapor separator  260  if so desired. In such a configuration, the pump may be submersed in the lower portion of the separator  180 . The pump  260  may include a thin wall tube liner, such as a thin wall stainless steel tube, in the outlet portion of the pump  260  to provide a relatively unrestricted flow path leaving the pump  260  in an effort to reduce or eliminate potential plugging that may occur at the exit of the pump with the solid CO 2 . A suitable pump may be configured to have an adjustable flow rate of approximately 2 to 6.2 gallons per minute (gpm) of LNG with a differential pressure of 80 psi while operating at −240° F. The adjustable flow rate may be controlled by means of a variable frequency drive. An example of one such pump is available from Barber-Nichols located in Arvada, Colo. 
     In another embodiment, the pump  260  may be eliminated and flow between the separator  180  and the hydrocyclone  258  may be effected through proper pressure management, such as by controlling the pressure differential between the separator  180  and the storage tank  116 . Such pressure management may include maintaining a steady state pressure differential between desired components or it may include the development of periodic, or pulsed, pressure differentials to effect the desired flow of slurry from the separator  180 . 
     When using a pump  260 , a recirculation line may be directed from the pump  260  back to the separator  180  so that the pump  260  may be operated without pushing liquid through the remainder of the system downstream from the pump  260  (such as the hydrocyclone  258  and polishing filters  266 A and  266 B). Appropriate piping and valving may also be used to enable a slow and moderate transition, for example, from the slurry flowing completely through the recirculation loop to a partial or full flow of the slurry to the downstream components. 
     The separator  180  may also include a vortex breaker to prevent or limit the development of a vortex within the separator  180  as may occur due to the operation of the pump  260 . In one example, a vortex breaker may be installed at approximately 2 inches above the pump inlet, extend the entire diameter of the separator  180  and exhibit a height of approximately 12 inches. 
     The hydrocyclone  258  acts as a separator to remove the solid CO 2  from the slurry allowing the LNG product fuel to be collected and stored. In one embodiment, the hydrocyclone  258  may be designed, for example, to operate at a pressure of approximately 125 psia at a temperature of approximately −238° F. The hydrocyclone  258  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  258  through an underflow  262 . The remainder of the liquid natural gas is passed through an overflow  264  for additional filtering. A slight pressure differential, for example, between approximately 0.5 psi and 1.5 psi, exists between the underflow  262  and the overflow  264  of the hydrocyclone  258 . Thus, for example, the thickened slush may exit the underflow  262  at approximately 65 psia with the liquid natural gas exiting the overflow  264  at approximately 64.5 psia. However, other pressure differentials may be more suitable depending of the specific hydrocyclone  258  utilized. A control valve  265  may be positioned at the overflow  264  of the hydrocyclone  258  to assist in controlling the pressure differential experienced within the hydrocyclone  258 . 
     A suitable hydrocyclone is available, for example, from Krebs Engineering of Tucson, Ariz. In one example, the hydrocyclone  258  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  258  may desirably include an interior surface which is micro-polished to an 8to 12 micro inch finish or better. 
     The liquid natural gas passes through the overflow  264  of the hydrocyclone  258  and may flow through one of a plurality, in this instance two, CO 2  screen filters  266 A and  266 B placed in parallel. The screen filters  266 A and  266 B capture any remaining solid CO 2  which may not have been separated out in the hydrocyclone  258 . Referring briefly to  FIG. 9 , a screen filter  266  may be formed, in one embodiment, of 6-inch schedule 40 stainless steel pipe  268  and include a first filter screen  270  of coarse stainless steel mesh, a second conical shaped filter screen  272  of stainless steel mesh less coarse than the first filter screen  270 , and a third filter screen  274  formed of fine stainless steel mesh. For example, in one embodiment, the first filter screen  270  may be formed of 50- to 75-mesh stainless steel, the second filter screen  272  may be formed of 75- to 100-mesh stainless steel and the third filter screen  274  may be formed of 100- to 150-mesh stainless steel. In another embodiment, all three filter screens  270 ,  272  and  274  may be formed of the same grade of mesh, for example, 40-mesh stainless steel or finer. 
     The CO 2  screen filters  266 A and  266 B may, from time to time, become clogged or plugged with solid CO 2  captured therein. Thus, as one filter, i.e.,  266 A, is being used to capture CO 2  from the liquid natural gas stream, the other filter, i.e.,  266 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 after the water clean-up cycle through a fourth heat exchanger  275  as indicated at interface connection  276 C to flow through and clean the CO 2  screen filter  266 B. Gas may be flowed through one or more pressure regulating valves  277  prior to passing through the heat exchanger  275  and into the CO 2  screen filter  266 B as may be dictated by pressure and flow conditions within the process. 
     During cleaning of the filter  266 B, a cleaning gas may be discharged back to coil-type heat exchanger  224  as is indicated by interface connections  301 B and  301 C. Appropriate valving and piping allows for the filters  266 A and  266 B to be switched and isolated from one another as may be required. Other methods of removing CO 2  solids that have accumulated on the filters are readily known by those of ordinary skill in the art. 
     The filtered liquid natural gas exits the liquefaction plant  102 ″ for storage as described above herein. A fail open-type valve  279  may be placed between the lines coming from the plant inlet  128  and outlet  114  as a fail safe device in case of upset conditions either within the liquefaction plant  102 ″ or from external sources, such as the tank  116  ( FIG. 1 ). 
     The thickened slush formed in the hydrocyclone  258  exits the underflow  262  and passes through piping or underflow stream  278  to heat exchanger  224  where it helps to cool the process stream  154 ′ flowing therethrough. Vapor passing through line  182 ′ from the liquid/vapor separator  180  passes through a pressure control valve and is combined with a portion of gas drawn off heat exchanger  224  through line  259  to form a combined cooling stream  257 . The combined cooling stream  257  then passes through an eductor  282 . A motive stream  284 , drawn from the process stream between the high efficiency heat exchanger  166  and coil-type heat exchanger  224 , also flows through the eductor  282  and serves to draw the combined cooling stream  257  into one or more of the tank inlets  252 A- 252 I ( FIG. 5B ). In one example, the eductor  282  may be configured to operate at a pressure of approximately 764 psia and a temperature of approximately −105° F. for the motive stream, and pressure of approximately 35 psia and temperature of approximately −240° F. for the suction stream with a discharge pressure of approximately 65 psia. Such an eductor is available from Fox Valve Development Corp. of Dover, N.J. 
     The CO 2  slurries introduced into the CO 2  heat exchanger  224 , either via cooling stream  170 ′, combined cooling stream  257  or underflow stream  278 , flow downwardly through the heat exchanger  224  over one or more or cooling coils  232 A- 232 C causing the solid CO 2  to sublime. This produces a cooling stream  286  that has a temperature high enough to eliminate solid CO 2  therein. The cooling stream  286  exiting the CO 2  heat exchanger  224  is combined with the expanded cooling stream  152 ′ from the turbo expander  156  to form combined cooling stream  178 ′ which is used to cool the compressed process stream  154 ′ in the high efficiency heat exchanger  166 . Upon exiting the heat exchanger  166 , the combined cooling stream  178 ′ is further combined with various other gas components flowing through interface connection  136 A, as described throughout herein, for discharge into the downstream section  130  of the pipeline  104  ( FIG. 1 ). 
     It is noted that, while not specifically shown, a number of valves may be placed throughout the liquefaction plant  102 ″ (or in any other embodiment described herein) for various purposes such as facilitating physical assembly and startup of the liquefaction 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. 
     Referring now to  FIG. 10 , a liquefaction plant  102 ′″ according to another embodiment of the invention is shown. The liquefaction plant  102 ′″ operates essentially in the same manner as the liquefaction plant  102 ″ of  FIG. 4  with some minor modifications. 
     A fourth heat exchanger  222  is located along the flow path of the process stream sequentially between high efficiency heat exchanger  166 ′ and the CO 2  heat exchanger  224 . The fourth heat exchanger  222  is associated with the removal of CO 2  and serves primarily to heat solid CO 2  which is removed from the process stream at a later point in the cycle, as shall be discussed in greater detail below. The fourth heat exchanger  222  also assists in cooling the gas in preparation for liquefaction and CO 2  removal. 
     The thickened slush formed in the hydrocyclone  258  exits the underflow  262  and passes through piping  278 ′ to heat exchanger  222 , wherein the density of the thickened sludge is reduced. As the CO 2  slurry exits heat exchanger  222  it combines with any vapor entering through plant inlet  128  (from tank  116  shown in  FIG. 1 ) as well as vapor passing through line  182 ′ from the liquid/vapor separator  180  forming combined cooling stream  257 ′. The combined cooling stream  257 ′ passes through a pressure control valve  280 A and then through an eductor  282 . A motive stream  284 ′, drawn from the process stream between the fourth heat exchanger  222  and the CO 2  heat exchanger  224 , also flows through the eductor  282  and serves to draw the combined cooling stream  257 ′ into one or more of the tank inlets  252 A- 252 I ( FIG. 5B ). 
     As with the embodiment described in reference to  FIG. 4 , the CO 2  slurries introduced into the CO 2  heat exchanger  224 , either via cooling stream  170 ′ or combined cooling stream  257 ,  257 ′ flow downwardly through the heat exchanger  224  over one or more or cooling coils  232 A- 232 C causing the solid CO 2  to sublime. This produces a cooling stream  286  that has a temperature high enough to eliminate solid CO 2  therein. The cooling stream exiting heat exchanger  224  is combined with the expanded cooling stream  152 ′ from the turbo expander  156  to form combined cooling stream  178 ′ which is used to cool compressed process stream  154 ′ in the high efficiency heat exchanger  166 ′. Upon exiting the heat exchanger  166 ′, the combined cooling stream  178 ′ is further combined with various other gas components flowing through interface connection  136 A, as described throughout herein, for discharge into the downstream section  130  of the pipeline  104  ( FIG. 1 ). 
     As with embodiments discussed above, the CO 2  screen filters  266 A and  266 B may require cleaning or purging from time to time. However, in the embodiment shown in  FIG. 10 , gas may be drawn after the water clean-up cycle at interface connection  276 C′ and enter into interface connection  276 B to flow through and clean CO 2  screen filter  266 B. During cleaning of the filter  266 B, the cleaning gas may be discharged back to the pipeline  104  ( FIG. 1 ) as is indicated by interface connections  136 F and  136 E. Appropriate valving and piping allows for the filters  266 A and  266 B to be switched and isolated from one another as may be required. Other methods of removing CO 2  solids that have accumulated on the filters are readily known by those of ordinary skill in the art. The filtered liquid natural gas exits the liquefaction plant  102 ′″ for storage as described above herein. 
     Referring now to  FIG. 11 , a differential pressure circuit  300  of liquefaction plant  102 ′″ is shown (see  FIG. 10 ). The differential pressure circuit  300  is designed to balance the flow entering the JT valve  176 ′ just prior to the liquid/vapor separator  180  based on the pressure difference between the compressed process stream  154 ′ and the product stream  172 ′. The JT valve  174 ′ located along cooling stream  170 ′ acts as the primary control valve passing a majority of the mass flow exiting from heat exchanger  224  in order to maintain the correct temperature in the product stream  172 ′. During normal operating conditions, it is assumed that gas will always be flowing through JT valve  174 ′. Opening up JT valve  174 ′ increases the flow back into heat exchanger  224  and consequently decreases the temperature in product stream  172 ′. Conversely, restricting the flow through JT valve  174 ′ will result in an increased temperature in product stream  172 ′. 
     JT valve  176 ′ located in the product stream  172 ′ serves to balance any excess flow in the product stream  172 ′ due to variations, for example, in controlling the temperature of the product stream  172 ′ or from surges experienced due to operation of the compressor  158 . JT valve  176 ′ is a pilot modulating action pressure relief valve such as, for example, an Iso-Dome Series 400 valve available from Anderson Greenwood located in Stafford, Tex. 
     A pressure differential control (PDC) valve  302  is disposed between, and coupled to the compressed process stream  154 ′ and the product stream  172 ′ (as is also indicated by interface connections  301 A and  301 B in  FIG. 4 ). A pilot line  304  is coupled between the low pressure side  306  of the PDC valve  302  and the pilot  308  of JT valve  176 ′. Both the PDC valve  302  and the pilot  308  of JT valve  176 ′ are biased (e.g., with springs) for pressure offsets to compensate for pressure losses experienced by the flow of the process stream  154 ′ through the circuit containing heat exchangers  166 ,  222  (if used) and  224 . 
     The following are examples of how the differential pressure circuit  300  may behave in certain operating situations. 
     In one situation, the pressure and flow increase in the compressed process stream  154 ′ due to fluctuations in the compressor  158 . As pressure increases in the compressed process stream  154 ′, the high pressure side  310  of the PDC valve  302  causes the PDC valve  302  to open, thereby increasing the pressure within the pilot line  304  and the pilot  308  of JT valve  176 ′. After flowing through the various heat exchangers, a new pressure will result in the product stream  172 ′. With flow being maintained by JT valve  174 ′, excessive process fluid built up in the product stream  172 ′ will result in a reduction of pressure loss across the heat exchangers, bringing the pressure in the product stream  172 ′ closer to the pressure exhibited by the compressed process stream  154 ′. The increased pressure in the product stream  172 ′ will be sensed by the PDC valve  302  and cause it to close, thereby overcoming the pressure in the pilot line  304  and the biasing element of the pilot  308 . As a result, JT valve  176 ′ will open and increase the flow therethrough. As flow increases through JT valve  176 ′ the pressure in the product stream  172 ′ will be reduced. 
     In a second scenario, the pressure and flow are in a steady state condition in the compressed process stream  154 ′. In this case, the compressor will provide more flow than will be removed by JT valve  174 ′, resulting in an increase in pressure in the product stream  172 ′. As the pressure builds in the product stream  172 ′, the PDC  302  valve and JT valve  176 ′ will react as described above with respect to the first scenario to reduce the pressure in the product stream  172 ′. 
     In a third scenario, JT valve  174 ′ suddenly opens, magnifying the pressure loss across the heat exchangers  224  and  166  and thereby reducing the pressure in the product stream  172 ′. The loss of pressure in the product stream  172 ′ will be sensed by the PDC valve  302 , thereby actuating the pilot  308  such that JT valve  176 ′ closes until the flow comes back into equilibrium. 
     In a fourth scenario, JT valve  174 ′ suddenly closes, causing a pressure spike in the product stream  172 ′. In this case, the pressure increase will be sensed by the PDC valve  302 , thereby actuating the pilot  308  and causing JT valve  176 ′ to open and release the excess pressure/flow until the pressure and flow are back in equilibrium. 
     In a fifth scenario, the pressure decreases in the compressed process stream  154 ′ due to fluctuations in the compressor  158 . This will cause the circuit  300  to respond such that JT valve  176 ′ momentarily closes until the pressure and flow balance out in the product stream  172 ′. 
     The JT valve  174 ′ is a significant component of the differential pressure circuit  300  as it serves to maintain the split between cooling stream  170 ′ and product stream  172 ′ subsequent the flow of compressed process stream  154 ′ through heat exchanger  224 . JT valve  174 ′ accomplishes this by maintaining the temperature of the stream in line  256  exiting heat exchanger  224 . As the temperature in line  256  (and thus in cooling stream  170 ′ and process stream  172 ′) drops below a desired temperature, the flow through JT valve  174 ′ may be adjusted to provide less cooling to heat exchanger  224 . Conversely as the temperature in line  256  raises above a desired temperature, the flow through JT valve  174 ′ may be adjusted to provide additional cooling to heat exchanger  224 . 
     Referring now to  FIG. 12 , a liquefaction plant  102 ″″ and process are shown according to another embodiment of the invention. The liquefaction plant  102 ″″ operates essentially in the same manner as the liquefaction plant  102 ′″ of  FIG. 10  with some minor modifications. Rather than passing the thickened CO 2  slush from the hydrocyclone  258  through a heat exchanger  222  ( FIG. 10 ), a pump  320  accommodates the flow of the thickened CO 2  slush back to heat exchanger  224 . The configuration of liquefaction plant  102 ″″ eliminates the need for an additional heat exchanger (i.e., heat exchanger  222  of  FIG. 10 ). However, flow of the thickened CO 2  slush may be limited by the capacity of the pump  320  and the density of the thickened slush in the configuration shown in  FIG. 10 . 
     Referring now to  FIG. 13 , the physical configuration of liquefaction plant  102 ″ described in reference to  FIG. 4  is shown according to one embodiment thereof. Substantially an entire liquefaction plant  102 ″ may be mounted on a supporting structure such as a skid  330  such that the liquefaction plant  102 ″ may be moved and transported as needed. Pointing out some of the major components of the liquefaction plant  102 ″, the turbo expander  156 /compressor  158  is shown on the right hand portion of the skid  330 . A human operator  332  is shown next to the turbo expander  156 /compressor  158  to provide a general frame of reference regarding the size of the plant  102 ″. Generally, the overall plant may be configured, for example, to be approximately 30 feet long, 16 feet high and 8½ feet wide. 
     The high efficiency heat exchanger  166  and the heat exchanger  224  used for sublimation of solid CO 2  are found on the left hand side of the skid  330 . The parallel CO 2  filters  266 A and  226 B can be seen adjacent heat exchanger  224 . Wiring  334  may extend from the skid  330  to a remote location, such as a separate pad  335  or control room, for controlling various components, such as, for example, the turbo expander  156 /compressor  158 , as will be appreciated and understood by those of skill in the art. Additionally, pneumatic and/or hydraulic lines may extend from the skid  330  for control or external power input as may be desired. It is noted that by remotely locating the controls, or at least some of the controls, costs may be reduced as such remotely located controls and instruments need not have, for example, explosion proof enclosures or other safety features as would be required if located on the skid  330 . 
     It is also noted that a framework  340  may be mounted on the skid  330  and configured to substantially encompass the liquefaction plant  102 ″. A first section  342 , exhibiting a first height, is shown to substantially encompass the volume around the turbo expander  156  and compressor  158 . A second section  344  substantially encompasses the volume around the heat exchangers  166 ,  224 , filters  266 A and  266 B and other components which operate at reduced temperatures. The second section  344  includes two subsections  344 A and  344 B with subsection  344 A being substantially equivalent in height to section  342 . Subsection  344 B extends above the height of section  342  and may be removable for purposes of transportation as discussed below. The piping associated with the plant  102 ″ may be insulated for purposes of minimizing unwanted heat transfer. Alternatively, or in combination with insulated pipes, an insulated wall  346  may separate first section  342  from second section  344  and from the external environs of the plant  102 ″. Additionally, insulated walls  346  may be placed on the framework  340  about the exterior of the liquefaction plant  102 ″ to insulate at least a portion of the liquefaction plant  102 ″ from ambient temperature conditions which might reduce the efficiency of the liquefaction plant  102 ″. 
     In one embodiment, the liquefaction liquefaction plant  102 ″ may be strategically designed such that the plant may be separated into two or more sections. For example, sections or subsections of the liquefaction plant  102 ″ may be designed for physical separation from one another such that one section or subsection may be transported independent of the other sections or subsections. In one embodiment, the liquefaction plant  102 ″ may be divided into sections or subsections such that, for example, one section includes so called “hot” components (e.g., those components not being thermally insulated from ambient conditions) and one section includes so called “cold” components (e.g., those components that are to be thermally insulated from ambient conditions). 
     Referring now to  FIG. 14 , the liquefaction plant  102 ″, or a substantial portion thereof, may, for example, be loaded onto a trailer  350  to be transported by truck  352  to a plant site. Alternatively, the supporting structure may serve as the trailer with the skid  330  ( FIG. 13 ) configured with wheels, suspension and/or a hitch to mount to the truck  352  at one end, and a second set of wheels  354  at the opposing end. Other means of transport will be readily apparent to those having ordinary skill in the art. 
     It is noted that upper subsection  344 B has been removed, and, while not explicitly shown in the drawing, some larger components such as the high efficiency heat exchanger  166  and the solid CO 2  processing heat exchanger  224  have been removed. This potentially allows the liquefaction plant  102 ″ to be transported without any special permits (i.e., wide load, oversized load, etc.) while keeping the plant substantially intact. 
     It is further noted that the plant may include controls such that minimal operator input is required. Indeed, it may be desirable that any of the plants discussed herein 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. 
     While the invention has been disclosed primarily in terms of liquefaction of natural gas, it is noted that 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 may be processed and other gas components, such as, for example, nitrogen, may be removed. Thus, the present invention is not limited to the liquefaction of natural gas and the removal of CO 2  therefrom. 
     Referring now to  FIG. 18 , a process flow diagram is shown depicting a liquefaction process performed in accordance with another embodiment of the liquefaction plant  502 . As the liquefaction plant  502  and the process carried out thereby share a number of similarities with other embodiments described herein, including liquefaction plants  102 ,  102 ′,  102 ″ and  102 ′″ and the processes depicted in  FIGS. 2 ,  3 ,  4  and  10 , respectively, like components are again identified with like reference numerals for sake of clarity. Additionally, for sake of clarity, a portion of the cycle between the plant inlet  112  and the expander  156 /compressor  158  is omitted in  FIG. 18 , but may be incorporated into the liquefaction plant  502  and process shown and described with respect to  FIG. 18 . 
     In the embodiment shown in  FIG. 18 , appropriate valving and piping may be provided to divert a portion of the compressed process stream  154 ′ from the high efficiency heat exchanger  166 . For example, the compressed process stream  154 ′ may be split into paths  154 A and  154 B wherein the first path  154 A represents the cooling stream flowing through the entirety of the heat exchanger  166  while the second path  154 B represents the cooling stream being diverted from the heat exchanger  166  so as to effectively bypass, for example, the last half or third of the heat exchanger  166 . Thus, the amount of cooling provided by the heat exchanger  166  to the compressed process stream  154 ′ could be selectively managed by directing the compressed process stream  154 ′ through the first path  154 A, the second path  154 B or through both simultaneously at selected flow rates depending on the settings of the associated valves for inlets  504 A and  504 B. 
     The cooling stream  152 ″ leaves the expander  156  and directly enters the CO 2  heat exchanger  224  on the shell side thereof (so as to flow over one or more of the coils disposed within the heat exchanger  224 ) and ultimately combines with the cooling stream  286  that provides cooling to the high efficiency heat exchanger  166 . The cooling stream  152 ″ may be split into multiple streams (e.g., streams  152 A and  152 B) so that the cooling stream  152 ″ may be selectively discharged into the CO 2  heat exchanger  224 . Thus, depending on the amount of cooling that needs to be supplied to the cooling coils  232 A- 232 C ( FIG. 5A ) of the CO 2  heat exchanger  224 , the cooling stream  152 ″ may be diverted through one path (e.g., stream  152 A) that corresponds to flowing the cooling stream  152 ″ over multiple coils, through another path (e.g., stream  152 B) that corresponds to flowing the cooling stream  152 ″ over a single coil, or the cooling stream may be distributed simultaneously through multiple paths to a plurality of locations within the CO 2  heat exchanger  224 . Appropriate valving and piping may be used to selectively direct the flow of the cooling stream  152 ″ into the CO 2  heat exchanger  224  in any number of desired configurations. In one embodiment, an appropriate separator such as, for example, a cyclonic type separator may be disposed in the flow of the cooling stream  152 ″ to remove methanol and water from the stream prior to its entrance into the CO 2  heat exchanger  224 . The introduction of cooling stream  152 ″ into the shell side of the CO 2  heat exchanger  224  not only assists with cooling of any material flowing through the coils thereof, but may also assist in the sublimation of any solid CO 2  that is being flowed through the shell side of the heat exchanger  224 . 
     Referring briefly to  FIG. 5C , an example is shown of inlets  505 A and  505 B to the CO 2  heat exchanger  224  as may be associated with flow paths  152 A and  152 B ( FIG. 18 ), respectively. It is noted that the shell or tank portion of the heat exchanger  224  is shown in phantom or dashed lines for purposes of convenience and clarity. In the example shown in  FIG. 5C , one inlet  505 A may be located and configured to discharge the cooling stream  152 ″, or a portion thereof, within the CO 2  heat exchanger  224  at a location between the second and third cooling coils  232 B and  232 C while the other inlet  505 B may be located and configured to discharge the cooling stream  152 ″, or a portion thereof, within the CO 2  heat exchanger  224  at a location between the first and second cooling coils  232 A and  232 B. 
     The inlets  505 A and  505 B may include one or more discharge ports  507 , which may include openings or nozzles, configured to discharge the cooling stream  152 ″ in a desired direction. Thus, for example, the discharge ports  507  of the first inlet  505 A may be configured to discharge the cooling stream  152 ″ in an initial direction towards the third cooling coil  232 C while the discharge ports  507  of the second inlet  505 B may be configured to discharge the cooling stream  152 ″ in an initial direction towards the second cooling coil  232 B. Of course, the inlets  505 A and  505 B and the discharge ports  507  may exhibit different configurations and locations depending, for example, on the desired operational parameters of the CO 2  heat exchanger  224 . 
     The cooled process stream  256  leaves the CO 2  heat exchanger  224  and splits into cooling and product streams  170 ′ and  172 ′. The process stream  172 ′ passes through a JT valve  176 ′ and is expanded to a low pressure, for example approximately 35 psia. The expansion via the JT valve  176 ′ also serves to lower the temperature and introduces solid CO 2  formed in the product stream  172 ′, as previously discussed herein. The expanded product stream  172 ″, now containing solid CO 2 , enters the liquid/vapor separator  180  wherein the vapor is collected and removed from the separator  180  through piping  182 ″ and directed to the CO 2  heat exchanger  224  for use as a refrigerant in the shell side thereof. 
     The liquid in the liquid/vapor separator  180  is a slurry comprising the LNG fuel product and solid CO 2 . Because the solid CO 2  may have a tendency to settle within the separator  180 , a vapor line  506  may be used to introduce a desired amount of vapor into the separator  180  at the bottom side thereof such that the vapor bubbles through the slurry and causes the solid CO 2  to be suspended within the liquid. For example, vapor may be drawn from a location after the coalescing filter  208  of the water/methanol clean-up cycle as indicated by interface connections  507 A and  507 B. A plurality of valves  508 A and  508 B may be located and configured such that vapor may flow directly into the separator  180  (i.e., through valve  508 A) or may flow to the separator  180  by way of the piping  510  connecting the separator  180  and the hydrocyclone  258 , so as to provide a backflushing action and prevent or remove the build-up of solid CO 2  in the piping  510  between transfers of slurry from the separator  180  to the hydrocyclone  258 . 
     Of course, vapor may be drawn off from other locations within the plant or may be provided from a separate source of gas. In another embodiment, other means of agitating the slurry within the tank may be used, such as mechanical agitators, so as to prevent settling of the solid CO 2  within the separator  180 . Additionally, nucleate boiling may be utilized to provide agitation of the slurry within the separator  180 . 
     Additionally, a converging nozzle  542  or funnel may be installed at the slurry exit of the separator  180  to direct the slurry into the piping  510 . The nozzle  542  or funnel provides a means for bubbles, which may exist in the slurry that is being transferred, to escape from the slurry and avoid being trapped in the moving liquid transferred to the piping  510 . As slurry enters into the nozzle  542 , bubbles are allowed to escape along the inclined surfaces of the converging structure as the slurry accelerates due to the converging structure of the nozzle  542 . In one embodiment, such a nozzle  542  may be substantially horizontally oriented, located approximately in the center of the separator  180  and coupled to a transfer tube that directs the slurry to the associated piping  510 . 
     The flow of the slurry between the separator  180  and the hydrocyclone  258  may be effected through proper pressure management, such as by controlling the pressure differential between the separator  180  and the storage tank  116 . Such pressure management may include maintaining a steady state pressure differential between desired components or it may include the development of periodic, or pulsed, pressure differentials to effect the desired flow of slurry from the separator  180 . 
     The hydrocyclone  258  acts as a separator to remove the solid CO 2  from the slurry allowing the LNG product fuel to be collected and stored substantially, as discussed previously herein. The underflow  262  of the hydrocyclone  258 , which comprises a flow of thickened slush, may be directed to the CO 2  heat exchanger  224  such that it enters the shell side thereof at a desired elevation. Placing the entrance of the thickened slush at a specific elevation, relative to the physical location of the hydrocyclone&#39;s underflow  262 , enables management of the head or pressure required to flow the thickened slush into the CO 2  heat exchanger  224  from the hydrocyclone  258 . Thus, a smaller elevation differential between the underflow  262  of the hydrocyclone  258  and the entry into the CO 2  heat exchanger  224  results in reduced head requirements to effect the flow of the thickened slush. An appropriate valve, such as a ball valve  512 , may be coupled to the piping  278  extending between the hydrocyclone  258  and the heat exchanger  224  to provide isolation capability, such as may be desired, for example, during start-up operations, so as to help prevent CO 2  from forming in undesired locations. 
     The liquid natural gas passes through the overflow  264  of the hydrocyclone  258  and may flow through one of a plurality, in this instance two, CO 2  screen filters  266 A and  266 B placed in parallel. The screen filters  266 A and  266 B capture any remaining solid CO 2  which may not have been separated out in the hydrocyclone  258 . The filters  266 A and  266 B may be configured, for example, as has been described hereinabove with respect to  FIG. 9 . Additionally, when the filters  266 A and  266 B need to be purged of accumulated CO 2  a higher temperature gas may be flowed therethrough as indicated by interface connections  276 A and  276 B ( FIG. 4 ). It is noted, that in the embodiment shown in  FIG. 18  that gas is drawn from a location downstream of the water clean-up cycle after the coalescing filter  208  as indicated by interface points  514 A and  514 B and passed through a heat exchanger  275  prior to being passed to the filters  266 A and  266 B. 
     As discussed hereinabove, during cleaning of the filter  266 B, the cleaning gas may be discharged back to the CO 2  heat exchanger  224 , as is indicated by interface connections  301 A,  301 B and  301 C. Appropriate valving and piping allows for the filters  266 A and  266 B to be switched and isolated from one another as may be required. Other methods of removing CO 2  solids that have accumulated on the filters may be used as will be appreciated by those of ordinary skill in the art. 
     In the embodiment shown in  FIG. 18 , a high-flow loop is provided for assisting in the start-up of the liquefaction plant  502  by redirecting a portion of the process stream through the CO 2  heat exchanger  224  during the start-up process. The high-flow gas loop includes a line  516  coupled to the coil side of the CO 2  heat exchanger  224  and short circuits one or more of the coils contained therein by directing flow of the process stream, or a desired portion thereof, through a control valve  518  and back into the shell side of the CO 2  heat exchanger  224  at a desired location, such as between the bottom and middle coil sets. 
     In one embodiment, the control valve  518  may be tied, in a control sense, with the JT valve  174 ′ so as to operate as a single valve. In other words, the control valve  518  remains closed until the JT valve  174 ′ is fully open. Thus, the high-flow loop provides increased flow into the shell side of the CO 2  heat exchanger  224  when needed by adding to the flow already entering by way of JT valve  174 ′. For example, a PID (proportional, integral, derivative) controller may be used to control the two valves  174 ′ and  518 , wherein a bottom half of a signal produced by the PID controller effects actuation of the JT valve  174 ′ while the upper half of the signal produced by the PID controller effects actuation of the control valve  518 . In one particular embodiment, the selected ranges of a signal from the PID controller may be selectively defined to overlap with respect to the control of each of the valves  174 ′ and  518  in order to account for opening and closing hysteresis in the valve actuators and thereby effect a substantially seamless cooperative operation of the two valves  174 ′ and  518  as if they were a single valve. 
     A check valve  520  may couple the high-flow loop with the vapor line that extends between the plant inlet  128  (from tank  116  shown in  FIG. 1 ) and the combined cooling stream  257  entering the eductor  282 . The check valve  520  provides an escape route for high flow gas conditions where the eductor  282  cannot accommodate the flow (such as may be determined by an associated pressure regulator). The check valve  520  enables excess flow in the vapor line and the combined cooling stream  257  may be released into the high-flow loop when the pressure builds to a point that it exceeds the cracking pressure of the check valve  520 . In one embodiment, the check valve  520  may include a one-inch check valve having a swing check wherein nothing prevents the valves&#39; opening, except for the back pressure on the check, valve  520 , and the weight of a check gate. Thus, the pressure on one side of the check valve  520  may be limited, for example, to 1-3 psig over the pressure on the other side thereof. 
     As with other embodiments described herein, the liquefaction plant  502  may include an ejector or an eductor  282  through which passes a combined cooling stream  257 . The motive stream  284  may be drawn from the process stream at one or more of a plurality of locations. For example, the motive stream  284 , or a portion thereof, may be drawn from a location between the high efficiency heat exchanger  166  and the CO 2  heat exchanger  224 . Additionally, the motive stream  284 , or a portion thereof, may be drawn from a location between the compressor  158  (or the bypass loop  164 , if the compressor is not in operation) and the ambient heat exchanger  220  as indicated by interface connections  530 A and  530 B. As discussed hereinabove, the motive stream  284  flows through the eductor  282  and serves to draw the combined cooling stream  257  into one or more of the tank inlets  252 A- 252 I ( FIG. 5B ). The ability to draw the motive stream  284  from multiple locations, including from multiple locations simultaneously, using appropriate valving and piping, provides additional flexibility in controlling the pressure and temperature of the motive stream  284  such that, for example, solid CO 2  or other constituents may be prevented from building up on the internal surfaces of the eductor  282 . 
     The liquefaction plant  502  also includes a surge protection line  532  to protect the compressor  158  from insufficient flows which would result in an undesirable acceleration of the compressor  158 . The surge protection line  532  ties into the compressed process stream  154 ′ at a location between the ambient heat exchanger  220  and the high efficiency heat exchanger  166  and returns the flow through control valve  534  to the inlet of the compressor  158 . A flow meter may be used to monitor the flow rate of material entering the compressor  158  and, if necessary, actuate the control valve  534  so as to alter the flow therethrough. It is noted that the surge protection line  532  might be located and configured to draw gas from a different location such as at essentially any location downstream from the check valve  535  following the compressor  158  and prior to a reduction of pressure of the compressed gas. 
     As also indicated in  FIG. 18 , besides splitting the inlet flow into a cooling stream  152  and a process stream  154 , an additional stream of gas  536  may be drawn of for operation of gas bearings associated with the expander  156 /compressor  158  such as has been discussed hereinabove. As will also be appreciated by those of ordinary skill in the art, this additional stream of gas  536  (or yet another stream of gas) may be used as seal gas to provide a noncontacting seal between the compressor  158 , the expander  156  and a center bearing disposed therebetween. 
     In operating the liquefaction plant  502 , various parameters may be monitored and various adjustments implemented in order to maintain operation of the expander  156 /compressor  158  within a desired range and in order to produce LNG at a desired rate with specified temperature and pressure characteristics. Control of the liquefaction plant  502  may be fully or partially automated, such as, for example, by using an appropriate computer, a programmable logic circuit (PLC), using closed-loop and open-loop schemes, using proportional, integral, derivative (PID) control, or other appropriate control and programming tools as will be appreciated by those of ordinary skill in the art. Additionally, if desired, the liquefaction plant  502  may be operated manually. The following discussion describes examples of logic that may be used in controlling the liquefaction plant  502 . 
     In order to efficiently run the expander  156 /compressor  158  within desired speed and flow parameters, certain flow criteria should be met. If control is being automated, the control system may be configured to set and maintain these flow requirements automatically, by equation. The equation may also automatically calculate a flow set-point that meets the flow requirements of the expander  156 /compressor  158 . The equation may start calculating flow values as soon as the expander  156 /compressor  158  is started. 
     Under one control scheme, the “back-end flow loop,” which is generally the flow starting with the cooled process stream  256  and includes the flow through the JT valve  174 ′ back into the CO 2  heat exchanger  224 , as well as the flow through the JT valve  176 ′ to the separator  180 , may be used as a primary control mechanism in operating the liquefaction plant  502 . A desired “set-point” is initially determined for the back-end flow. This set-point represents a flow rate that is sufficient to ensure that adequate flow is provided to the expander  156 /compressor  158  and is sufficient to activate flow sensors that may be positioned throughout the liquefaction plant  502  at desired locations. 
     It is noted that, depending on the type of flow meters or flow sensors being used, the calculated flow set-point may be insufficient during slow speed operation of the expander  156 /compressor  158  to maintain detection of the flow(s) throughout the liquefaction plant  502 . Thus, it may be desirable to utilize a manual set point (i.e., one that is not determined by the automatic calculation) until the turbo speed is sufficiently high such that any automatic flow calculation set-point matches or exceeds the manual set point. Once the manual and calculated set-points match, the system can be switched from manual to automatic set-point generation. From this point on, the automatic set-point may be used to maintain the appropriate flows required by the expander  156 /compressor  158  for proper operation. 
     The calculated back-end flow (CBEF) is derived by indirectly determining the flow through the compressor  158  (i.e., the process stream  154 ). Referring to  FIG. 18 , the flow is calculated as follows:
 
CBEF= F 112−( F 152 +F 536)  EQ 1
 
     Where CBEF is the calculated backend flow (lbm/hr); F112 is the flow coming into the liquefaction plant  502  through the inlet  112  (lbm/hr); F152 is the flow through the expander  156  (lbm/hr); and F536 is the flow to the stream of gas bearings  536 . The flow to the gas bearings  538  may be a fixed value and considered a constant. 
     The CBEF is the actual flow feedback value used to determine if the system is responding correctly and causing the flow to progress towards the set-point. The CBEF value is basically the same value as that which is measured by a flow meter as it flows through the compressor  158  (although independently derived) and is only different due to minor flows within the system. However, having two independent flow values representative of the flow through the compressor  158  may be important when considering surge flows as discussed hereinbelow. 
     The automatic calculated flow set-point is determined by the following equation: 
     
       
         
           
             EQ 
             ⁢ 
             
                 
             
             ⁢ 
             2 
             ⁢ 
             
               : 
             
           
         
       
       
         
           
             ABEF 
             = 
             
               6000 
               ⁢ 
               
                   
               
               ⁢ 
               
                 ( 
                 
                   RPM 
                   85000 
                 
                 ) 
               
               ⁢ 
               
                 ( 
                 
                   
                     P 
                     ⁢ 
                     
                         
                     
                     ⁢ 
                     112 
                   
                   440 
                 
                 ) 
               
               ⁢ 
               BESF 
             
           
         
       
     
     Where ABEF is the Automatic Calculated Backend flow set-point (lbm/hr); 6000 is a constant and is the maximum design flow through the compressor  158  at 85000 RPM, and 440 psia, (lbm/hr); RPM is the current revolutions per minute of the compressor  158 ; 85000 is a constant and is the design speed (RPM) of compressor  158 ; P112 is the current pressure (psia) at the inlet  112  of the liquefaction plant  502 ;  440  is a constant and is the design pressure (psia) for the inlet  112 ; and BESF is the back-end flow safety factor (a dimensionless multiplier). 
     Referring to  FIG. 19A , a block diagram of a closed-loop control scheme is shown as an example for back-end flow control. The JT valve  174 ′ discharges the compressed cooling stream  256  (or a portion thereof) into the shell side of the CO 2  heat exchanger  224  and is the controlled element in this scheme. During start-up, the control valve  518  of the high-flow loop may be used to accommodate additional flow if the JT valve  174 ′ goes to a fully open position. 
     One specific method of controlling the valves in the back-end flow, either in conjunction with the logic set forth above or with some other logic, includes a process referred to herein as valve abstraction. Valve abstraction allows any number of valves, “N,” to be viewed as a single valve from the perspective of a controlling loop. The valves are arranged by Cv size (the flow coefficient of a valve) with appropriate scaling and zones using the output of a control loop to operate all valves incorporated in the loop. In other words, valves with smaller flow coefficients (Cv) will be actuated first with the relative weight of those valves taken into account. 
     In one more specific example, a system with two valves may be considered. A first valve has Cv of 3 and a second valve has a Cv of 1. The control output has a resolution of 4096. The output of the control loop is divided into two zones. The first zone is assigned to the second valve, as it is the smaller valve (Cv=1). This zone would be a ratio of the second valves Cv in relation to the total resulting Cv when both valves are open. This ratio, when applied to the output resolution of the “combined” valve, would result in the second valve&#39;s zone ranging from 0 to 1023. The first valve would, therefore, have a zone associated with the output range of 1024 to 4095. This arrangement enables the valves to act as one valve. If the valves have nonlinear Cv curves, then the resulting zones would have to be curve fitted for appropriate valve actuation.  FIG. 20  shows a flow diagram showing the logic of such valve control schematically. 
     It is noted that such a method may be appropriately incorporated into the control of the JT valve  174 ′ and the control valve  518  of the high flow loop as has been discussed hereinabove. 
     Another technique that may be used, and which may be advantageously combined with the process of valve abstraction, includes what may be referred to as dynamic gain manipulation. Dynamic gain manipulation may be used to modify the proportional gain of a PID loop used, for example, to control the back-end flow. The upper and lower gain values are mapped against the physical parameters associated with a material transition (e.g., a gas-to-liquid or a liquid-to-gas transition). For example, considering a transition from a gaseous phase to a liquid phase, the physical parameters that provide an impetus for such a phase change include pressure and temperature. After determining which physical parameters have the most significant contribution to a phase change are identified, then these parameters may be mapped against the gain used in a PID control loop. It is noted that different dynamic gain maps may be used at different stages of plant operation. For example, one dynamic gain map may be used during the start-up of the plant while another dynamic gain map may be used during steady-state operation of the plant. The use of different dynamic gain maps may be useful because, for example, during start-up, the gas is less dense than during normal operations. As the density of the gas increases (and the temperature of the gas is correspondingly colder), the velocity of the gas increases. Thus, such variables may be taken into account in controlling the plant. 
     For example, if natural gas begins to change density toward a liquid state at roughly −140° F. at 700 PSIG and is fully a liquid at approximately −200° F. at 700 PSIG, then, the gain may be mapped against this range as shown in  FIG. 21 . Once the values have been mapped, the gain on the PID loop can be modified according to the curve of the phase transition of the material being handled. This will allow the loop to remain stable during phase transitions. While the technique of using dynamic gain may be used with integral and derivative gains, the technique appears to work particularly well with proportional gain when combined with the technique of valve abstraction as discussed hereinabove. 
     The use of both valve abstraction and dynamic gain manipulation to maintain stability during a phase transition from a gas to a liquid (or a liquid to a gas) may be particularly suited for implementation during startup of a plant, but may be utilized with any process that requires flow control across material phase transitions. 
     Still referring to  FIG. 18 , the cooling stream  253  is designed to regulate the temperature of the compressed product stream  154 ′ by altering the flow volume entering the shell side of the CO 2  heat exchanger  224 . As the compressed product stream  154 ′ cools to a desired set-point, the JT valve  176 ′ valve leading to the separator  180  is opened, thereby reducing the flow to the CO 2  heat exchanger  224  and preventing it from overcooling the compressed product stream  154 ′. 
     As discussed hereinabove, the flow of the cooling stream  253  into the shell of the CO 2  heat exchanger  224  acts as a refrigerant to cool the compressed product stream  154 ′. When the flow of the cooling stream  253  is reduced, the temperature can be balanced to the desired set-point. A reduction in the flow of the cooling stream  253  also results in the increased production of liquid in the separator  180 . Excess flow not required for cooling stream  253  is thus removed from the system as liquid product. 
     During start-up of the liquefaction plant  502 , the JT valve  176 ′ is closed due to the relatively warm temperatures of the compressed product stream  154 ′ and associated components. Therefore, all the flow is directed into cooling stream  253 . One or more appropriate temperature sensors may be used to monitor the temperature of the back end flow at one or more locations. For example, the temperature may be monitored at a location such as in the cooled product stream  256  which exits the CO 2  heat exchanger  224 . If the sensed temperature exceeds (i.e., gets colder than) the set point, or the target temperature, the JT valve  176 ′ leading to the separator  180  will begin to open. This can be controlled, for example, with a PLC using a PID closed loop control scheme, such as shown in  FIG. 19B . 
     In one embodiment of the invention, the relationship of the various valves (which includes the JT valve  174 ′ and the JT valve  176 ′ (although it may include others such as the control valve  518  of the high-flow loop) may be used to control the liquefaction plant  502 , including control of liquid production. In such an embodiment, during the startup and early operation of the liquefaction plant  502 , all the high pressure flow is managed through control of the back-end flow. Initially, it is desirable to manage the flow requirements of the compressor  158  and provide necessary cooling to the product stream. Cooling is maximized by directing all of the high pressure mass flow into the shell side of the CO 2  heat exchanger  224 . 
     During the initial cooling phase of the CO 2  heat exchanger  224  and the compressed product stream  154 ′, the temperature control loop is dormant or inactive. This is due to the fact that the temperature of the process stream, such as the cooled process stream  256 , is much warmer than the set-point or the target temperature. This relatively warm process fluid keeps the JT valve  176 ′ closed. As the temperature approaches the set-point, the JT valve  176 ′ begins to open. In one example, such a set point may be between approximately −175° F. and −205° F. 
     As the JT valve  176 ′ opens (which valve may be considered both the temperature control valve, as well as the liquid production valve in the presently described control scheme), flow is diverted away from cooling the CO 2  heat exchanger  224 . If the process continues cooling and exceeds the temperature set-point, the JT valve  176 ′ opens further, thereby reducing flows to the CO 2  heat exchanger  224 . This action continues to reduce the flow, and thus refrigeration, to the CO 2  heat exchanger  224  until the cooling process reverses. Since the flow set-point is constant, the JT valve  174 ′ (which may be considered the flow valve) begins to close in unison to the JT valve  176 ′ (the temperature control valve) opening, and vice-versa. 
     As the temperature of the product stream  256  warms, the temperature valve/JT valve  176 ′ starts closing and the flow valve/JT valve  174 ′ begins opening. This action of opening and closing the two JT valves  174 ′ and  176 ′ continues until a steady position is reached where both valves are at least partially open such that both flow and temperature conditions (set-points) are met. This back and forth action of opening and closing the JT valves  174 ′ and  176 ′ may be handled by PID control loops as set forth hereinabove. The balanced condition of the JT valves  174 ′ and  176 ′ results in a steady state production of liquid flowing into the SGL tank and a correct refrigeration flow into the CO 2  heat exchanger  224 . 
     In the currently described embodiment, the combination of these two control loops (i.e., the flow loop and the temperature loop) makes the steady state operation possible. The various heat exchangers (e.g., the CO 2  heat exchanger  224 ) may be designed with enough capacity to overdrive their need for refrigeration, thus providing an excess of flow for liquid product production, if desired. 
     As previously discussed with respect to  FIG. 3 , methanol may be added to the process to remove water vapor from the feed gas and prevent water from freezing within the various plant components including, for example, within the turbo expander  156 . As also noted above, this feature is considered to be available for use with the process described with respect to  FIG. 18 . Considering both  FIGS. 3 and 18 , an example of a control scheme regarding the addition of methanol is now considered. Methanol is added to the primary flow entering the liquefaction plant  502  through the plant inlet  112  by way of pump  202  which may include a metering pump. The pump  202  may force the methanol into the flow through a small atomizing nozzle. The amount of methanol injected is equation driven, based on a combination of the flow rate through the plant inlet  112  (such as may be determined by a flow meter  110 ;  FIG. 1 ) and the CO 2  content of the incoming gas. 
     In one embodiment, the pump  202  may include a multi-piston positive displacement piston pump, wherein each stroke measures out a calibrated quantity. Such a pump  202  may be calibrated by running the pump  202  at a constant speed and measuring the quantity of liquid in a beaker over a given time. An equation may utilize the desired methanol flow value, based on mass flow of the incoming natural gas through the plant inlet  112 , and convert the desired flow to motor speed (Hz) based on the calibration of the pump  202 . One such equation is as follows: 
     
       
         
           
             EQ 
             ⁢ 
             
                 
             
             ⁢ 
             3 
             ⁢ 
             
               : 
             
           
         
       
       
         
           
             MF 
             = 
             
               
                 ( 
                 
                   
                     A 
                     ⁢ 
                     
                         
                     
                     ⁢ 
                     0 
                   
                   + 
                   
                     A 
                     ⁢ 
                     
                         
                     
                     ⁢ 
                     1 
                     ⁢ 
                     
                       ( 
                       
                         
                           Meth_H 
                           2 
                         
                         ⁢ 
                         O_Content 
                       
                       ) 
                     
                   
                 
                 ) 
               
               * 
               
                 
                   F 
                   ⁢ 
                   
                       
                   
                   ⁢ 
                   112 
                 
                 
                   10 
                   ⁢ 
                   
                     , 
                   
                   ⁢ 
                   000 
                 
               
               * 
               MSF 
             
           
         
       
     
     Where: A0=0.79 and is a constant based on methanol/water data; A1=0.626 and is a constant based on methanol/water data; MF is the methanol flow; Meth_H 2 O_Content is the content of H 2 O in the gas stream (a constant that must be determined for the particular flow); F112 is the mass flow entering the plant inlet  112 ; MSF is the methanol safety factor (a constant); and 10,000 is a constant based on the design flow of the liquefaction plant  502 . 
     The methanol absorbs the water and both are removed by cyclonic separators, coalescing separators, or both, when the temperature reaches approximately −70° F. in the product stream  154 . The cooling stream  152  (and subsequent flow paths) can get to approximately −100° F. before the methanol mixture is removed. The control of the methanol flow may be effected by, for example, an appropriate open loop control scheme using an equation, such as Equation 3 set forth above, such as shown in  FIG. 19C . 
     As previously discussed, certain situations may occur wherein the flow into the compressor  158  becomes insufficient causing the compressor  158  to quickly accelerate because of lack of load. To prevent this condition, a surge protection line  532  routes flow from the high pressure side of the compressor  158  back to the lower pressure inlet of the compressor  158 . This surge protection line  532  may be controlled by the surge protection circuit to prevent the compressor  158  from going into surge when abnormal conditions are present. 
     In one embodiment, the control of the surge protection line  532  may include closed loop, PID control using the following equation: 
     
       
         
           
             EQ 
             ⁢ 
             
                 
             
             ⁢ 
             4 
             ⁢ 
             
               : 
             
           
         
       
       
         
           
             SF 
             = 
             
               5 
               ⁢ 
               
                 , 
               
               ⁢ 
               000 
               ⁢ 
               
                   
               
               ⁢ 
               
                 ( 
                 
                   RPM 
                   
                     85 
                     ⁢ 
                     
                       , 
                     
                     ⁢ 
                     000 
                   
                 
                 ) 
               
               ⁢ 
               
                 ( 
                 
                   
                     P 
                     ⁢ 
                     
                         
                     
                     ⁢ 
                     112 
                   
                   440 
                 
                 ) 
               
               ⁢ 
               SSF 
             
           
         
       
     
     Where SF is surge flow set-point; 5,000 is a constant, and is the minimum flow through the compressor at 85,000 revolutions per minute and 440 psia, (lbm/hr); RPM is the current revolutions per minute of the compressor  158 ; 85,000 is a constant, and is the design speed (revolutions per minute) of the compressor  158 ; P112 is the pressure at the plant inlet  112  (psia);  440  is the design pressure (psia); and SSF is a surge safety factor for the compressor  158 . 
     Equation 4 may be used, for example, in conjunction with a closed loop PID control scheme, such as shown in  FIG. 19D , wherein a flow meter placed in the process stream  154  may be used as the feedback element, and the control valve  534  may be the controlled element. 
     Since the surge protection line  532  is essentially a safety control loop, the control valve  534  is rarely opened. However, if an aberration in the operation of the liquefaction plant  502  causes the flow through the compressor  158  to fall below the surge flow set point (SF), the control valve  534  will open and cause the flow to circulate back to the inlet of the compressor  158 . It is noted that use of a flow sensor in the process stream line as the feedback for the surge control prevents the use of such a flow sensor for control of the backend flow. When the surge loop is activated, the flow through the compressor  158  is accurately reported by the flow sensor. However, in order for the control of backend flow to adjust for an off-normal or aberrational condition, it will be reading the flow through the compressor  158  indirectly as set forth by EQ 1, set forth hereinabove, which will actually be lower than the reading of a flow sensor in the process stream  154 . If control of the back-end flow were to also rely on the flow sensor in the process stream  154 , the controller would not be able to correct the abnormal condition, because the flow through the compressor  158  would appear to be correct. 
     Still referring to  FIG. 18 , liquid level in the separator  180  is desirably maintained between a minimum and maximum level. A differential pressure transducer may be used for sensing the liquid level within the separator  180 . The minimum level may be determined so as to provide an adequate residence time for the solid CO 2  in the liquid, thereby ensuring a subcooled CO 2  particle. The minimum level also ensures that the majority of the expanding flow (i.e., the flow from the JT valve  176 ′) contacts the fluid surface directly rather than contacting the walls of the separator tank. Subcooling all the CO 2  in the liquid helps to prevent the particles from sticking to one another and plugging up the system. 
     The maximum liquid level is the highest operational fill level and may be used to trigger the liquid transfer through the hydrocyclone  258 . Both levels may be programmed into an appropriate controller as will be appreciated by those of ordinary skill in the art. In one example, the minimum fill level may be set at approximately 30% of the capacity of separator  180  and maximum fill levels may be set at approximately 60% of the capacity of separator  180 , although other values may be used. In one embodiment, a fill level equivalent to 90-100% may be used as a safety level, where if the specified level is reached, an emergency stop of the plant may be triggered. 
     In transferring the slurry to the hydrocyclone  258 , a pressure circuit may be used to pressurize the separator  180  at desired transfer times and effect batch transfers of liquid from the separator  180  to the hydrocyclone  258 . For example, in one embodiment, a vent line  543  may provide communication between the separator  180  and the storage tank  116  ( FIG. 1 ) as indicated by interface connections  544 A and  544 B. An actuated ball valve  545  may be coupled to the vent line  543  to selectively effect such communication. Thus, during times when liquid is being produced within the separator  180  and slurry is not being transferred, the ball valve  545  may be in an open position such that vapor from the separator  180  is directed to the eductor  282  and the separator  180  and storage tank  116  are maintained at common pressures (e.g., 35 psia). However, when it is desired to transfer slurry from the separator  180  to the hydrocyclone  258  (such as when the liquid/slurry level within the separator  180  reaches a specified level), the ball valve  545  may be closed, causing pressure to build in the separator  180  by way of, for example, a back pressure regulator  546  positioned in line  182 ″. The back pressure regulator may be set at, for example, a pressure of approximately 75 psia to approximately 80 psia. The increased pressure in the separator  180  may then be used as a motive force to transfer the slurry from the separator  180  to the hydrocyclone  258 . Once the liquid/slurry level within the separator  180  drops to a specified minimum level, the ball valve  545  may again open such that pressure within the separator  180  is again reduced to a common level with the storage tank  116  ( FIG. 1 ) and liquid/slurry begins to accumulate again within the separator  180 . 
     In controlling the hydrocyclone  258 , two control points may be considered. The first control point is the flow pressure coming into the hydrocyclone  258 . The second control point is the differential pressure across the underflow  262  and the overflow  264 . The incoming pressure may be maintained by the motive stream  284  flow pushing the liquid through the separator  180  and into the hydrocyclone  258 . The differential pressure between the underflow  262  and the overflow  264  may be controlled by restricting the flow with the associated control valve  265 . 
     The underflow  262  (which contains a CO 2  slurry), exits directly into the shell side of the CO 2  heat exchanger  224  and may be used as the reference pressure for controlling the differential pressure within the hydrocyclone  258 . As noted previously, the differential pressure across the hydrocyclone  258  may be maintained between, for example, −0.5 psid and +1 psid. Generally, if the pressure differential is maintained closer to −0.5 psid, more liquid will flow out the overflow  264  while generally poorer separation of liquid and solid will be exhibited. As the pressure differential increases to +1 psid and higher, more product liquid is pushed out the underflow  262  with the CO 2 , but higher separation efficiencies will be exhibited. 
     The control valve  265  coupled with the overflow  264  of the hydrocyclone  258  restricts the flow and may be used to prevent it from dropping below −0.5 psid. The pressure of the storage tank  116  ( FIG. 1 ) is held at a desired set-point, and is generally equal to or higher than the pressure in the separator  180 . For example, a pressure differential between the storage tank  116  and hydrocyclone  258  of about 15 psid may exist. A pressure differential between the hydrocyclone  258  and separator  180  of about 15 psid may also exist except when liquid is being transferred. During liquid transfer, the pressure in separator  180  will be higher than the pressure in hydrocyclone  258 . A closed loop control scheme using PID control may be implemented such as is shown in  FIG. 19D . The control loop may use one or more differential pressure transmitters as control inputs with the control valve  265  being the controlled element. The hydrocyclone  258  differential pressure set point may be manually programmed into the control system, or may be calculated according to various monitored operational parameters as will be appreciated by those of ordinary skill in the art. 
     As previously discussed, the polishing filters  266 A and  266 B may be used to remove any CO 2  that may have escaped the separation process effected by the hydrocyclone  258 . As a filter (e.g., filter  266 A) collects CO 2 , the differential pressure across the filter  266 A will increase. When the differential pressure across the filter  266 A reaches a specific level (i.e., a defined set-point), the flow of liquid will be switched to the other filter  266 B, so that the first filter  266 A may be allowed to warm the collected CO 2  therefrom. The warming/cleaning of a given filter  266 A or  266 B may be user selectable between a passive warming cycle that can take many hours or even days, or an active warming cycle where hot gas is routed through the identified filter until all the filtered or collected CO 2  has sublimed back into the liquefaction plant  502 . The selection of cleaning methods may be determined by the amount of time that it takes for the polishing filter  266 A,  266 B to become filled with CO 2  during normal operation of the plant  502 . Isolation of a given filter  266 A or  266 B for either filtering purposes, or for cleaning purposes, may be effected through control of three-way valves  540 A and  540 B or through other appropriate valving and piping as will be appreciated by those of ordinary skill in the art. 
     Referring briefly to  FIG. 22  in conjunction with  FIG. 18 , a flow diagram is shown describing logic that may be used in managing the polishing filters  266 A and  266 B in accordance with one embodiment of the present invention. As indicated at  550 , a filter  266 A or  266 B is selected for use in filtering liquid passing from the hydrocyclone  258  to the LNG storage tank  116  ( FIG. 1 ). During filtering, the operational filter is monitored to determine whether the differential pressure (dP) across the filter is greater than a desired set-point (SP) as indicated at  552 . If the differential pressure is less than the set-point, the monitoring process continues as indicated by loop  554 . If the differential pressure is greater than the set-point, then it is determined whether the first filter  266 A is being used as indicated at  556 . 
     If the first filter  266 A is not the current filter, it is then determined if the first filter  266 A is available (as it is possible that both filters  266 A and  266 B may be simultaneously unavailable), as indicated at  558 . If the first filter  266 A is not available, an error message may be reported to the controller as shown at  560 . If the first filter  266 A is available, then liquid flow is switched to the first filter  266 A as indicated at  562  and the second filter  266 B is set as being unavailable as indicated at  564 . 
     Warming gas is then introduced into the second filter  266 B, such as by supplying such warming gas from interfacing connection  276 B, through the filter  266 B and out interfacing connection  301 B, as indicated at  566 . The temperature of the second filter  266 B is monitored and compared with a target temperature as indicated at  566 . If the temperature of the filter  266 B is less than the target temperature, the process continues, as indicated by loop  568 . In one embodiment of the present invention, the target temperature may be approximately −70° F. If the temperature of the filter  266 B is greater than the target temperature, indicating that all of the CO 2  has been sublimed from the filter  266 B, then the flow of warming gas is stopped as indicated at  570 . The second filter  266 B is then set as being available as indicated at  572  and the process continues as indicated by loop  574 . 
     Returning back to the decision point at  556 , if the first filter  266 A is the current filter, then it is determined whether the second filter  266 B is available as indicated at  576 . If the second filter  266 B is not available, an error message may be reported as indicated at  560 . If the second filter  266 B is available, then liquid flow is switched to the second filter  266 B as indicated at  578  and the first filter  266 A is set as being unavailable as indicated at  580 . 
     Warming gas is then introduced into the first filter  266 A, such as by supplying such warming gas from interfacing connection  276 A, through the filter  266 A and out interfacing connection  301 A, as indicated at  582 . The temperature of the first filter  266 A is monitored and compared with a target temperature as indicated at  584 . If the temperature of the filter  266 A is less than the target temperature, the process continues, as indicated by loop  586 . If the temperature of the filter  266 A is greater than the target temperature, indicating that all of the CO 2  has been sublimed from the filter  266 A, then the flow of warming gas is stopped as indicated at  588 . The first filter  266 A is then set as being available as indicated at  590  and the process continues as indicated by loop  574 . 
     EXAMPLE 1 
     Referring now to  FIGS. 4 and 15 , an example of the process carried out in the liquefaction liquefaction plant  102 ″ is set forth. It is noted that  FIG. 15  is the same process flow diagram as  FIG. 4  (combined with the additional components of  FIG. 3 , e.g., the compressor  154  and turbo expander  156 , etc.) but with component reference numerals omitted for clarity. As the general process has been described above with reference to  FIG. 4 , the following example will set forth examples of conditions of the gas/liquid/slurry at various locations throughout the plant, referred to herein as state points, according to the calculated operational design of the liquefaction plant  102 ″. 
     At state point  400 , as the gas leaves the supply pipeline and enters the liquefaction plant  102 ″, the gas will be approximately 60° F. at a pressure of approximately 440 psia, with a flow of approximately 10,000 lbm/hr. 
     At state points  402  and  404 , the flow will be split such that approximately 5,065 lbm/hr flows through state point  402  and approximately 4,945 lbm/hr flows through state point  404  with temperatures and pressures of each state point being similar to that of state point  400 . 
     At state point  406 , as the stream exits the turbo expander  156 , the gas will be approximately −104° F. at a pressure of approximately 65 psia. At state point  408 , as the gas exits the compressor  158 , the gas will be approximately 187° F. at a pressure of approximately 770 psia. 
     At state point  410 , after the first heat exchanger  220  and prior to the high efficiency heat exchanger  166 , the gas will be approximately 175° F. at a pressure of approximately 770 psia. At state point  412 , after water clean-up and about midway through the high efficiency heat exchanger  166 , the gas will be approximately −70° F. at a pressure of approximately 766 psia and exhibit a flow rate of approximately 4,939 lbm/hr. 
     The gas exiting the high efficiency heat exchanger  166 , as shown at state point  414 , will be approximately −105° F. at a pressure of approximately 763 psia. 
     The flow through the product stream  172 ′ at state point  418  will be approximately −205° F. at a pressure of approximately 761 psia with a flow rate of approximately 3,735 lbm/hr. At state point  420 , after passing through the Joule-Thomson valve, and prior to entering the separator  180 , the stream will become a mixture of gas, liquid natural gas, and solid CO 2  and will be approximately −240° F. at a pressure of approximately 35 psia. The slurry of solid CO 2  and liquid natural gas will have similar temperatures and higher pressures as it leaves the separator  180 , however, it will have a flow rate of approximately 1,324 lbm/hr. 
     At state point  422 , the pressure of the slurry will be raised, via the pump  260 , to a pressure of approximately 114 psia and a temperature of approximately −236° F. At state point  424 , after being separated via the hydrocyclone  258 , the liquid natural gas will be approximately −235° F. at a pressure of approximately 68 psia with a flow rate of approximately 1,059 lbm/hr. The liquid natural gas will drop in pressure from approximately 68 psia to approximately 42 psia while flowing through piping  278 , and will experience pressure losses as it passes through the CO 2  filters and exits the liquefaction plant  102 ″ into a storage vessel  116  where it will be at a pressure of approximately 35 psia. 
     At state point  426  the thickened slush (including solid CO 2 ) exiting the hydrocyclone  258  will be approximately −235° F. at a pressure of approximately −68.5 psia and will flow at a rate of approximately 265 lbm/hr. 
     At state point  430 , the gas exiting the separator  180  will be approximately −240° F. at a pressure of approximately 35 psia with a flow rate of approximately 263 lbm/hr. 
     At state point  434 , the gas in the motive stream  284  entering into the eductor  282  will be approximately −105° F. at approximately 764 psia. The flow rate at state point  434  will be approximately 1,205 lbm/hr. At state point  436 , subsequent the eductor  282 , the mixed stream will be approximately −217° F. at approximately 70 psia with a combined flow rate of approximately 698 lbm/hr. 
     At state point  438 , prior to JT valve  174 ′, the gas will be approximately −205° F. at a pressure of approximately 761 psia with a flow rate of approximately 2,147 lbm/hr. At state point  440 , after passing through JT valve  174 ′, whereby solid CO 2  is formed, the slurry will be approximately −221° F. with a pressure of approximately 68.5 psia. 
     At state point  442 , upon exiting heat exchanger  224 , the temperature of the gas will be approximately −195° F. and the pressure will be approximately 65 psia. The flow rate at state point  442  will be approximately 3,897 lbm/hr. At state point  444 , after combining two streams, the gas will have a temperature of approximately −151° F. and a pressure of approximately 65 psia. 
     At state point  446 , upon exit from the high efficiency heat exchanger  166 , and prior to discharge into the pipeline  104 , the gas will have a temperature of approximately 99° F. and a pressure of approximately 65 psia. The flow rate at state point  446  will be approximately 8,962 lbm/hr. 
     EXAMPLE 2 
     Referring now to  FIGS. 18 and 23 , an example of the process carried out in the liquefaction plant  502  is set forth. It is noted that  FIG. 23  is the same process flow diagram as  FIG. 18 , but with component reference numerals omitted for clarity. As the general process has been described above with reference to  FIG. 18 , the following example will set forth examples of conditions of the gas/liquid/slurry at various locations throughout the liquefaction plant, referred to herein as state points, according to the calculated operational design of the liquefaction plant  502 . 
     At state point  600 , as the gas leaves the supply pipeline and enters the liquefaction plant  502 , the gas will be approximately 51° F. at a pressure of approximately 464 psia with a flow of approximately 8,672 lbm/hr. 
     At state points  602  and  604 , the flow will be split such that approximately 4,488 lbm/hr flows through state point  602  and approximately 4,184 lbm/hr flows through state point  604  with temperatures and pressures of each state point being similar to that of state point  600 . 
     At state point  606 , as the stream exits the turbo expander  156 , the gas will be approximately −69° F. at a pressure of approximately 66 psia. At state point  608 , as the gas exits the compressor  158 , the gas will be approximately 143° F. at a pressure of approximately 674 psia. 
     At state point  610 , after the first heat exchanger  220  and prior to the high efficiency heat exchanger  166 , the gas will be approximately 128° F. at a pressure of approximately 674 psia. At state point  612 , after water clean-up and about midway through the high efficiency heat exchanger  166 , the gas will be approximately −86° F. at a pressure of approximately 668 psia. 
     The gas exiting the high efficiency heat exchanger  166 , as shown at state point  614 , will be approximately −115° F. at a pressure of approximately 668 psia. 
     The flow through the product stream  172 ′ at state point  618  will be approximately −181° F. at a pressure of approximately 661 psia with a flow rate of approximately 549 lbm/hr. At state point  620 , after passing through the Joule-Thomson valve  176 ′, and prior to entering the separator  180 , the stream will become a mixture of gas, liquid natural gas, and solid CO 2  and will be approximately −215° F. at a pressure of approximately 76 psia. The slurry of solid CO 2  and liquid natural gas will have similar temperatures and pressures as it leaves the separator  180 , however, it will have a flow rate of approximately 453 lbm/hr. 
     At state point  622 , after being separated via the hydrocyclone  258 , the liquid natural gas will be approximately −220° F. at a pressure of approximately 65 psia with a flow rate of approximately 365 lbm/hr. At state point  624 , after flowing through a polishing filter  266 A or polishing filter  266 B, the temperature of the liquid natural gas will be approximately −227° F. and the pressure will be approximately 51 psia. The state of the liquid natural gas will remain substantially the same as it exits the liquefaction plant  502  into a storage vessel or tank  116  ( FIG. 1 ) with the allowance for some variation due to, for example, pressure losses due to piping. 
     At state point  624 , the thickened slush (including solid CO 2 ) exiting the hydrocyclone  258  will be approximately −221° F. at a pressure of approximately −64 psia and will flow at a rate of approximately 89 lbm/hr. 
     At state point  630 , the gas exiting the separator  180  will be approximately −218° F. at a pressure of approximately 64 psia with a flow rate of approximately 96 lbm/hr. 
     At state point  634 , the gas in the motive stream  284  entering into the eductor  282  will be approximately −130° F. at approximately 515 psia. The flow rate at state point  634  will be approximately 1,015 lbm/hr. At state point  636 , subsequent the eductor  282 , the mixed stream  284  will be approximately −218° F. at approximately 64 psia with a combined flow rate of approximately 1,036 lbm/hr. 
     At state point  638 , prior to JT valve  174 ′, the gas will be approximately −181° F. at a pressure of approximately 661 psia with a flow rate of approximately 2,273 lbm/hr. At state point  640 , after passing through JT valve  174 ′, whereby solid CO 2  is formed, the slurry will be approximately −221° F. with a pressure of approximately 64 psia. 
     At state point  642 , upon exiting the CO 2  heat exchanger  224 , the temperature of the gas will be approximately −178° F. and the pressure will be approximately 63 psia. The flow rate at state point  642  will be approximately 7,884 lbm/hr. 
     At state point  644 , upon exit from the high efficiency heat exchanger  166 , and prior to discharge into the pipeline  104 , the gas will have a temperature of approximately 61° F. and a pressure of approximately 62 psia. The flow rate at state point  644  will be approximately 7,884 lbm/hr. 
     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 a process enables the use of relatively “dirty” gas typically found in residential and industrial service lines, eliminates the requirement for expensive pretreatment equipment and provides a significant reduction in operating costs for processing such relatively “dirty” gas. 
     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.