Patent Publication Number: US-7219512-B1

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

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application is a Continuation of U.S. 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. application Ser. No. 10/086,066, filed Feb. 27, 2002, now issued U.S. Pat. No. 6,581,409 for Apparatus for the Liquefaction of Natural Gas and Methods Relating to Same, which claims the benefit of U.S. Provisional Patent Application No. 60/288,985, filed May 4, 2001 for Small Scale Natural Gas Liquefaction Plant. 
    
    
     GOVERNMENT RIGHTS 
     The United States Government has rights in the following invention pursuant to Contract No. DE-AC07-99ID13727 and Contract No. DE-AC07-05ID14517 between the U.S. Department of Energy and Battelle Energy Alliance, LLC. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates generally to the compression and liquefaction of gases, and more particularly to the 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. 
     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 cycles for the liquefaction of natural gases are referred to as the “cascade cycle” and the “expansion cycle.” 
     Briefly, the cascade cycle consists of a series of heat exchanges with the feed gas, 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, 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 problem 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 70,600 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 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-liquid mixture therefrom. A first gas-liquid separator is configured to receive the gas-solid-liquid 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. 
    
    
     
       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 an embodiment of the present invention; 
         FIGS. 5A and 5B  show a heat exchanger according to one 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 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 elevation view 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 an exemplary CO 2  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. 11A  is a process schematic showing a differential pressure circuit incorporated in the plant and process of  FIG. 10 ; 
         FIG. 11B  is a process schematic showing a preferred differential pressure circuit incorporated in the 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 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; and 
         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. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     Referring to  FIG. 1 , a schematic overview of a portion of a liquefied natural gas (LNG) station  100  is shown according to one embodiment of the present invention. It is noted that, while the present invention is set forth in terms of liquefaction of natural gas, the present invention may be utilized for the liquefaction of other gases as will be appreciated and understood by those of ordinary skill in the art. 
     The liquefaction station  100  includes a “small scale” natural gas liquefaction plant  102  which is coupled to a source of natural gas such as a pipeline  104 , although other sources, such as a well head, are contemplated as being equally suitable. The term “small scale” is used to differentiate from a larger scale plant having the capacity of producing, for example 70,000 gallons of LNG or more per day. In comparison, the presently disclosed liquefaction plant may have capacity of producing, for example, approximately 10,000 gallons of LNG a day but may be scaled 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 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 exemplary and may vary depending on the particular pipeline  104  and the needs of the downstream customers. It is further noted that the available pressure of the upstream gas in the pipeline  104  (i.e., at plant entry  112 ) is not critical as the pressure thereof may be raised, for example by use of an auxiliary booster pump and heat exchanger, prior to the gas entering the liquefaction process described herein. 
     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 below herein. A portion of the feed gas entering the liquefaction plant  102  becomes LNG and exits the plant  102  at a plant outlet  114  for storage in a suitable tank or vessel  116 . The vessel  116  is preferably 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 depending on specific output requirements of the plant  102 . 
     A vessel outlet  118  is coupled to a flow meter  120  in association with dispensing the LNG from the vessel  116 , such as to a vehicle which is powered by LNG, or into a transport vehicle as may be required. A vessel inlet  122 , coupled with a valve/meter set  124  which could include flow and or process measurement devices, allows for 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 connecting with a second plant inlet  128  provides flexibility in controlling the flow of LNG from the liquefaction plant  102  and 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 points  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 the gas therethrough. The valve/meter sets  124  and  138  as well as the flow meters  110  and  120  may be positioned outside of the plant  102  and/or inside the plant as may be desired. Thus, flow meters  110  and  126 , when the outputs thereof are compared, help to determine the net amount of feed gas removed from the pipeline  104  as the upstream flow meter  110  measures the gross amount of gas removed and the downstream flow meter  130  measures the amount of gas placed back into the pipeline  104 , the difference being the net amount of feed gas removed from pipeline  104 . Similarly, optional flow meters  120  and  124  indicate the 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, 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, alternative instrument controls, such as electrical actuation, may likewise be implemented. 
     Upon entry into the liquefaction plant  102 , the feed gas 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. One exemplary 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. 
     The filter  146  may be provided with an optional drain  148  which discharges into piping near the plant exit  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 flows through the filter  146  (or alternatively around the filter by way of piping  150 ) the feed gas 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 atmospheric pressure and approximately 100 psia, 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  is determined by the power requirements of the compressor  158  as well as the flow and pressure drop across the turbo expander  156 . Vane control valves within the turbo expander  156  may be used to control the proportion of gas between the cooling and process lines  152  and  154  as is required according to the above stated parameters. 
     An exemplary turbo expander  156  and compressor  158  system includes a frame size ten (10) system available from GE Rotoflow, located in Gardona, Calif. The expander  156  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. 
     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. Without bypass piping  162  and  164 , thermal shock might result from the immediate flow of gas from the turbo expander  156  and compressor  154 . 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 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 as much as 1.8° F. per minute until a defined temperature limit is achieved. During start-up of the liquefaction plant, the temperature of the heat exchanger  166  may be monitored as it incrementally drops. 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 process stream  154 ′ which ultimately controls the cooling rate of heat exchanger  166  and/or other components of the liquefaction plant. 
     Also, during start-up, it may be desirable to have an amount of LNG already present in the tank  116  ( FIG. 1 ). Some of the cold vapor taken from the LNG present in the tank, or cold vapor or gas from another source, may be cycled through the system in order to cool various components is 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 . An exemplary ratio of the outlet to inlet pressures of a rotary compressor is approximately 1.5 to 2.0, with an average ratio being around 1.7. The compression process is not 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 exemplary heat exchanger  166  depicted in  FIG. 2  is a type utilizing countercurrent flow, as is known by those of ordinary skill in the art. 
     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 atmospheric and approximately 100 psia, 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 ). 
     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 piping  182  and added to the combined cooling stream  178  upstream of the heat exchanger  166 . The liquid component in the separator 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  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. 
     The liquefaction process depicted and described with respect to  FIG. 2  provides for low cost, efficient, and effective means of producing LNG when water and/or carbon dioxide are not present in the source gas that is to be subjected to the liquefaction cycle. 
     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 plant  102  and process depicted in  FIG. 2 , like components are identified with like reference numerals for sake of clarity. 
     Liquefaction plant  102 ′ as shown in  FIG. 3  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. As illustrated in  FIG. 3  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 into the gas stream preferably via at least one of an atomizing or a vaporizing nozzle. Alternatively, valving  203  may be used to accommodate multiple types of nozzles such that an appropriate nozzle may be used depending on the flow characteristics of the feed gas. Preferably, a single nozzle is used without valving  203  when water content in the source gas does not significantly flucuate. 
     A suitable pump  202  for injecting the methanol may include variable flow control in the range of 0.4 to 2.5 gallons per minute (GPM) at a design pressure of approximately 1000 psia for a water content of approximately 2 to 7 pounds mass per millions of standard cubic feet (lbm/mmscf). The variable flow control may be accomplished through the use of a variable frequency drive coupled to a motor of the pump  202 . Such an exemplary pump is available from America LEWA located in Holliston, Mass. 
     The methanol is mixed with the gas stream to lower the freezing point of any water which may be contained therein. The methanol mixes with the gas stream and binds with the water to prevent the formation of ice in the cooling stream  152  during expansion in the turbo expander  156 . Additionally, as noted above, the methanol is present in the process stream  154  and passes therewith through the compressor  158 . About midway through the heat exchange process (i.e., between approximately −60° F. and −90° F.) the methanol and water form a 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 plant exit  132  for discharge into the downstream section  130  of the pipeline  104  (see  FIG. 1 ). 
     An exemplary 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. 
     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 turbine 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 plant  102 ″ and process carried out therein share a number of similarities with 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 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 plant  102 ″ and process of  FIG. 4  are shown to include the water clean-up cycle described in reference to plant  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 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 . 
     An exemplary 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. 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 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, heat exchanger  224  allows the CO 2  to be reintroduced into the gas pipeline  104  at the downstream section by subliming the removed solid CO 2  in anticipation of its discharge back into the pipeline  104 . The sublimation of solid CO 2  in 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. 
     One exemplary heat exchanger  224  used for processing the solid CO 2  may include a tube-in-shell type heat exchanger. Referring to  FIG. 5A , an exemplary tube-in-shell heat exchanger  224  constructed in accordance with the present invention 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 exemplary cooling coil, or coiled bundle  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  240  for distribution among the plurality of tubing coils  242  and pass from the tubing coils  242  into the second inlet/outlet pipe  238  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. 
     An exemplary 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 inches. 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  232  are available from the Graham Corporation located at 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 coiling tubes  232 A- 232 C 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. The coil inlets  248 A and  250 A may be designed, for example, to accommodate a flow of high density gas of at least 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. Each tube outlet  248 B and  250 B may be designed, for example, to accommodate a flow of high density fluid of at least 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, as shown in  FIG. 6A  of the drawings, an outermost interior shell or splash jacket  292  may be formed about the cooling coils  232 A- 232 C such that an annulus may be formed between the interior shell and the tank shell  244 . 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 tank shell  244  of the heat exchanger  224 . Additionally, an innermost interior shell or splash jacket  294  may be formed within the cooling coils  232 A- 232 C such that an annulus may be formed between the interior of the coils and the inlet/outlet pipe  240 . Stainless steel, such as 304L or other corrosive resistant materials are suitable for use in forming jackets  292  and/or  294 . 
     A tank outlet  254  allows for discharge of the cooling streams  253  and  255  after they have passed over one or more 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. 
     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 tube 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 or  250 B. Flow through the first coil  232 A, appropriate piping will allow the process stream  154 ′″ to exit through associated tubing 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 tubing outlet  248 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 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 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 and/or coil outlet  250 A. 
     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 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 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 cause 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  until it encounters the third diverter  251 C. The third diverter will cause the process stream  154 ′″ to flow through the third coil  232 C and then through the inlet/outlet pipe  238  exiting the coil outlet  250 B. Thus, depending on the placement of the diverters  251 A- 251 C, the capacity of the heat exchanger 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 diverters  251 A and  251 B adjacent the first and second coils respectively). An exemplary plug  251  is shown in  FIGS. 8A and 8B . The plug  251  may be 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/outset pipes  238  and  240 . Additionally, a set of interior threads  294  may be formed in the keyed head so as to lockingly engage the installation/removal tool therewith such that the plug may be disposed in an inlet/outlet pipe  238  and  240  of substantial length. Furthermore, the configuration, quantity, and placement of the flow diverters and cooling coils as discussed and illustrated are exemplary. Thus, it will be understood that a wide variety of alternative flow diverters and cooling coil arrangements can be used in accordance with the present invention. 
     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 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 , therein, forming a slurry of natural gas and CO 2 . This CO 2  rich slurry enters heat exchanger  224  through one or more of the tank inputs  252 A- 252 I to pass over one or more 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 piping  182 ′ and added to a combined cooling stream  257  for use as a refrigerant in 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 . That is pump  260  manages vapor by taking the cold slurry and pressurizing it to a subcooled state. Upon the subcooled slurry passing through hydrocyclone  258 , the slurry returns to a state of equilibrium thus preventing fuel product vapor and/or vaporized CO 2  formation as result of the slurry experiencing a pressure drop while passing through the hydrocyclone. 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 . 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. Such an exemplary pump is available from Barber-Nichols located in Arvada, Colo. 
     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. An exemplary 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, approximately 0.5 psi, exists between the underflow  262  and the overflow  264  of the hydrocyclone. Thus, for example, the thickened slush may exit the underflow  262  at approximately 40.5 psia with the liquid natural gas exiting the overflow  264  at approximately 40 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  258  is available, for example, from Krebs Engineering of Tucson, Ariz. An exemplary hydrocyclone 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, an exemplary hydrocyclone desirably includes an interior which is micro-polished to an 8-12 micro inch finish or better. 
     The liquid natural gas passes 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 , an exemplary screen filter  266  may be formed 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, two of the filter screens  270  and  274  may be formed of the same grade of mesh, for example 40 mesh stainless steel or finer, and packed in a less dense or more dense manner to get the desired effect. That is, filter screen  270  can be fabricated from a mesh blanket or screen that is rolled relatively loosely to provide a less dense, or less surface area, packing and filter screen  274  can be fabricated from the same mesh blanket or screen material but rolled more tightly to produce a more dense, or higher surface area packing. 
     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 points  276 C and  276 B 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, the 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 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 and outlet as a fail safe device in case of upset conditions either within the 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  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 back pressure control valve  280 A 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  flowing through line  259  further serves as “make-up” to keep eductor  282  working correctly if the flow rate through back pressure control valve  280 A is too low. Back pressure control valve  280 B is preferably set a couple to a few psi higher than pressure control valve  280 A to keep combined cooling stream  257  moving in the correct direction. 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 and serves to draw the combined cooling stream  257  into one or more of the tank inlets  252 A- 252 I ( FIG. 5B ). An exemplary 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 69 psia. Such an eductor is available from Fox Valve Development Corp. of Dover, N.J. 
     The CO 2  slurries introduced into heat exchanger  224 , either via cooling stream  170 ′, combined cooling stream  257  or underflow stream  278 , flow downwardly through the heat exchanger 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 heat exchanger  224  is combined with the expanded cooling stream  152 ′ from the turbo  156  expander 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 ). 
     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 heat exchanger  224 . 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 back pressure control valve  280 A and then through an eductor  282 . A motive stream  284 ′, drawn from the process stream between heat exchanger  222  and heat exchanger  224 , also flows through the eductor and serves to draw the combined cooling stream  158  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 heat exchanger  224 , either via cooling stream  170 ′ or combined cooling stream  257 , flow downwardly through the heat exchanger  224  over one or more 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  156  expander 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 point  276 C and enter into interface point  276 A or  276 B to flow through and clean CO 2  screen filters  266 A or  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 E or  136 F and  136 A. 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 plant  102 ″ for storage as described above herein. 
     Referring now to  FIGS. 11A and 12 , a differential pressure circuit  300  of plant  102 ′″ is shown. 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 . 
     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 (i.e., 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 exemplary 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 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 less 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, 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. 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. 11B , a preferred circuit  300 ′ is shown. The operation of circuit  300 ′ is generally the same as circuit  300  described above, however instead of using mechanical control, circuit  300 ′ is electrical-pneumatically controlled. The primary differences between circuit  300  and  300 ′ include replacing pressure sense lines  370  and  372  with pressure sensors  374  and  376  and electrical leads  370 ′ and  372 ′. Furthermore, the differential pressure regulator  302  and control line  304  are replaced by an electrical controller  302 ′ and an electro-pneumatic sense line  304 ′ and pilot is replaced with a current-to-pneumatic (I/P) pilot control  308 ′. It should be noted that when using circuit  300  or circuit  300 ′ will work with any number of heat exchangers that would provide a pressure drop from  154 ′ to  172 ′. 
     Referring now to  FIG. 12 , a liquefaction plant  102 ″″ and process is 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 plant  102 ″″ eliminates the need for an additional heat exchanger (i.e.,  222  of  FIG. 10 ). However, flow of the thickened CO 2  slush may be limited by the capacity of the pump and the density of the thickened slush in the configuration shown in  FIG. 10 . 
     Referring now to  FIG. 13 , an exemplary physical configuration of plant  102 ″ described in reference to  FIG. 4  is according to one embodiment thereof. Plant  102 ″ is shown without siding or a roof for viewability. Substantially an entire plant  102 ″ may be mounted on a supporting structure such as a skid  330  such that the plant  102 ″ may be moved and transported as needed. Pointing out some of the major components of the 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, 17 feet high and 8½ feet wide. However, the overall plant may be sized smaller or larger as desired. 
     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 might 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 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 minimizing unwanted heat transfer. Alternatively, or in combination with insulated pipes and selected components, an insulated wall  346  may separate section  342  from section  344  and from the external environs of the plant  102 ″. Additionally, insulated walls may be placed on the framework  340  about the exterior of the plant  102 ″ to insulate at least a portion of the plant  102 ″ from ambient temperature conditions which might reduce the efficiency of the plant  102 ″. Furthermore, various components may be individually insulated in addition to interconnecting piping, including but not limited to, separation tank  180 , filter modules  266 A,B, and heat exchangers  166  and  224 . 
     Referring now to  FIG. 14 , the 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  configured with wheels, suspension and a hitch to mount to the truck tractor  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 plant 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 plant  102 - 102 ″″ 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. 
     EXAMPLE 
     Referring now to  FIGS. 4 and 15 , an example of the process carried out in the liquefaction plant  102 ″ is set forth. It is noted that  FIG. 14  is the same process flow diagram as  FIG. 4  (combined with the additional components of FIG.  3 —e.g. the compressor  154  and 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 exemplary 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 plant  102 ″. 
     At state point  400 , as the gas leaves distribution pipeline and enters the liquefaction plant the gas will be approximately 60° F. at a pressure of approximately 440 psia with a flow of approximately 10,00 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 turboexpander  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 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 CO2 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 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 −240° F. at a pressure of approximately 35 psia with a flow rate of approximately 1,059 lbm/hr. The state of the liquid natural gas will remain substantially the same as it exits the plant  102 ″ into a storage vessel. 
     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 entering into the eductor 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, 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. 
     In light of the above disclosure it will be appreciated that the liquefaction process depicted and described herein provides 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 allows the use of relatively “dirty” gas typically found in residential and industrial service lines, and 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 which have been shown by way of example in the drawings and have been described in detail herein, 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.