Abstract:
A method and apparatus are described to provide complete gas utilization in the liquefaction operation from a source of gas without return of natural gas to the source thereof from the process and apparatus. The mass flow rate of gas input into the system and apparatus may be substantially equal to the mass flow rate of liquefied product output from the system, such as for storage or use.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    This application is related to U.S. patent application Ser. No. 09/643,420, filed Aug. 23, 2001, for APPARATUS AND PROCESS FOR THE REFRIGERATION, LIQUEFACTION AND SEPARATION OF GASES WITH VARYING LEVELS OF PURITY, 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, for APPARATUS AND PROCESS FOR THE REFRIGERATION, LIQUEFACTION AND SEPARATION OF GASES WITH VARYING LEVELS OF PURITY, now U.S. Pat. No. 6,105,390, issued Aug. 22, 2000, which claims the benefit of U.S. Provisional Patent Application Ser. No. 60/069,698 filed Dec. 16, 1997. This application is also related to U.S. patent application Ser. No. 11/381,904, filed May 5, 2006, for APPARATUS FOR THE LIQUEFACTION OF NATURAL GAS AND METHODS RELATING TO SAME; U.S. patent application Ser. No. 11/383,411, filed May 15, 2006, for APPARATUS FOR THE LIQUEFACTION OF NATURAL GAS AND METHODS RELATING TO SAME; U.S. patent application Ser. No. 11/560,682, filed Nov. 16, 2006, for APPARATUS FOR THE LIQUEFACTION OF GAS AND METHODS RELATING TO SAME; U.S. patent application Ser. No. 11/536,477, filed Sep. 28, 2006, for APPARATUS FOR THE LIQUEFACTION OF A GAS AND METHODS RELATING TO SAME; U.S. patent application Ser. No. 11/674,984, filed Feb. 14, 2007, for SYSTEMS AND METHODS FOR DELIVERING HYDROGEN AND SEPARATION OF HYDROGEN FROM A CARRIER MEDIUM, which is a continuation-in-part of U.S. patent application Ser. No. 11/124,589 filed on May 5, 2005, for APPARATUS FOR THE LIQUEFACTION OF NATURAL GAS AND METHODS RELATING TO SAME, 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 on Apr. 14, 2003, for APPARATUS FOR THE LIQUEFACTION OF NATURAL GAS AND METHODS RELATING TO SAME, now U.S. Pat. No. 6,962,061 issued on Nov. 8, 2005, and U.S. patent application Ser. No. 10/414,883, filed Apr. 14, 2003, for APPARATUS FOR THE LIQUEFACTION OF NATURAL GAS AND METHODS RELATING TO SAME, now U.S. Pat. No. 6,886,362, issued May 3, 2005, which is a divisional of U.S. patent application Ser. No. 10/086,066 filed on Feb. 27, 2002, for APPARATUS FOR THE LIQUEFACTION OF NATURAL GAS AND METHODS RELATED TO SAME, now U.S. Pat. No. 6,581,409 issued on Jun. 24, 2003, and which claims the benefit of U.S. Provisional Patent Application Ser. No. 60/288,985, filed May 4, 2001, for SMALL SCALE NATURAL GAS LIQUEFACTION PLANT. This application is also related to U.S. patent application Ser. No. 11/855,071, filed Sep. 13, 2007, for HEAT EXCHANGER AND Associated METHODS; U.S. patent application Ser. No. ______, filed on even date herewith, for METHODS OF NATURAL GAS LIQUEFACTION AND NATURAL GAS LIQUEFACTION PLANTS UTILIZING MULTIPLE AND VARYING GAS STREAMS (Attorney Docket No. 2939-9179US (BA-350)); and U.S. patent application Ser. No. ______, filed on even date herewith, for NATURAL GAS LIQUEFACTION CORE MODULES, PLANTS INCLUDING SAME AND RELATED METHODS (Attorney Docket No. 2939-9178US (BA-349)). The disclosure of each of the foregoing documents is incorporated herein in its entirety by reference. 
     
    
     GOVERNMENT RIGHTS 
       [0002]    This invention was made with government support under Contract Number DE-AC07-05ID14517 awarded by the United States Department of Energy. The government has certain rights in the invention. 
     
    
     TECHNICAL FIELD 
       [0003]    The present invention relates generally to the compression and liquefaction of gases and, more particularly, to the complete liquefaction of a gas, such as natural gas, by utilizing a combined refrigerant and expansion process in situations where natural gas cannot or is not desired to be returned from the liquefaction process to the source thereof or another apparatus for collection. 
       BACKGROUND 
       [0004]    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 atmosphere and dissipate, rather than settling. 
         [0005]    To be used as an alternative combustion fuel, natural gas 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.” 
         [0006]    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. 
         [0007]    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 that freeze at the temperatures encountered in the heat exchangers, for example, water and carbon dioxide. 
         [0008]    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 70,000 gallons of LNG per day, may cost $16.3 million to $24.5 million, or more, in capital expenses. 
         [0009]    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 from storage. Further, safety may become an issue when larger amounts of LNG fuel product are stored. 
         [0010]    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 relatively small scale. More particularly, it would be advantageous to provide a system for producing liquefied natural gas from a source after the removal of components thereof. 
         [0011]    It would be additionally advantageous to provide a plant for the liquefaction of natural gas that is relatively inexpensive to build and operate, and that desirably requires little or no operator oversight. 
         [0012]    It would be additionally advantageous to provide such a plant that is easily transportable and that may be located and operated at existing sources of natural gas that are within or near populated communities, thus providing easy access for consumers of LNG fuel. 
         [0013]    Because there has been significant interest in liquefying natural gas recently, most technologies have focused on small scale liquefaction where only a small portion of the incoming gas is liquefied with the majority of the incoming gas being returned to the infrastructure and source of the gas. These technologies work well in areas with established pipeline infrastructure for the return of gas from the small scale liquefaction unit. Such small scale units can be very cost effective, with liquefaction efficiencies significantly surpassing any full scale production plant. Since the small scale liquefaction units have a small footprint using little space, they are desirable for use with distributed gas supply systems. Also, small scale liquefaction units typically have initial low capitol cost and low maintenance costs making it easier for such units to be purchased and operated. 
         [0014]    Some locations do not have the benefit of a pipeline infrastructure, but still produce natural gas. Examples of types of such locations are waste disposal sites and coal bed methane wells, which typically produce enough natural gas to consider capturing and selling the gas in a convenient form. When the operators of waste disposal sites capture gas from the site, they can either use the gas for fuel of their equipment, or sell the fuel for other uses thereby reducing costs of the waste disposal site. Coal bed methane wells can be productive over lengthy periods and the gas sold or used in onsite equipment. 
         [0015]    However, without the ability to return natural gas to its source or an equivalent thereof, such as natural gas piping infrastructure, a conventional small scale liquefaction unit is not feasible to use for natural gas liquefaction. Therefore, a compact natural gas liquefaction process and unit is needed that will provide complete liquefaction of the natural gas entering the process and unit, that is 100% of the natural gas entering the process and unit or substantially all of the natural gas entering the process and unit may exit the unit as liquefied natural gas. If a small scale complete liquefaction natural gas process and unit cannot be provided, it may not be feasible to liquefy natural gas from waste disposal sites and coal bed methane wells because conventional small scale liquefaction processes and units require the return of un-liquefied natural gas from the unit to a pipeline infrastructure or other suitable receiving reservoir. 
         [0016]    Complete liquefaction has long been the domain of large, capital intensive LNG plants making it difficult for small natural gas markets to be conveniently supplied with natural gas. The use of complete liquefaction processes and apparatus as described herein facilitates liquefaction of natural gas at waste disposal sites, coal bed methane wells, and other types of single source supplies of natural gas where gas cannot be returned from the liquefaction process and apparatus. Other such instances where the use of the complete liquefaction process and unit described herein includes the liquefaction of natural gas from a pipeline where it is not desirable to return a large volume of natural gas from the liquefaction process and unit back into a pipeline because either the volume of natural gas to be returned to the pipeline is too great, or the pressure of the natural gas being returned to the pipeline is too great, or regulations prevent the return of natural gas from the conventional liquefaction process and unit to the pipeline, or policies prohibit the return of natural gas from the conventional liquefaction process and unit to a pipeline. The complete liquefaction processes and apparatus described herein facilitate the production of natural gas and the transportation thereof at locations previously considered to be unattractive for the production of natural gas. 
       BRIEF SUMMARY 
       [0017]    A method and apparatus are described that may provide complete gas utilization in the liquefaction operation from a source of gas without return of natural gas to the source thereof from the process and apparatus. The mass flow rate of gas input into the system and apparatus may be substantially equal to the mass flow rate of liquefied product output from the system, such as for storage or use. 
         [0018]    In some embodiments, a liquefaction plant having an inlet connected to a source of gas may include a first mixer connected to the source of gas, a first compressor for receiving a stream of gas from the first mixer for producing a compressed gas stream, a first splitter for splitting the compressed gas stream from the first compressor into a cooling stream and a process stream, and a turbo compressor for compressing the cooling stream from the first splitter. The liquefaction plant may further include a heat exchanger for cooling the process stream into a liquid and a gas vapor, a separation tank for separating the gas vapor from the liquid of the process stream, and a storage tank connected to the separation tank for storing the liquid. Additionally, the liquefaction plant may include an apparatus connecting the separation tank to the first mixer, and an apparatus connecting the storage tank to the first mixer. 
         [0019]    In additional embodiments, a method of liquefying natural gas from a source of gas using a liquefaction plant having an inlet for gas may include connecting a first mixer to the source of gas, and compressing a first stream of natural gas from the first mixer for producing a compressed gas stream. The method may further include splitting the process stream using a first splitter into a cooling stream and a process stream, compressing the cooling stream using a turbo expander, expanding the compressed cooling stream using a turbo expander, and cooling the process stream with a heat exchanger. Additionally, the method may include separating vapor from the liquid gas in a separation tank, storing liquid natural gas in a storage tank, flowing vapor from the separation tank and vapor from the storage tank into the first mixer to mix with gas from the source of gas, forming gas from liquid natural gas in the separation vessel using the heat exchanger, and flowing gas from the heat exchanger to the first mixer to mix with gas from the source of gas. 
         [0020]    In yet additional embodiments, a method of liquefying gas from a source of gas using a liquefaction plant having an inlet for gas may include connecting a first mixer to the source of gas, compressing a first stream of gas from the first mixer for producing a process stream, and splitting the process stream using a first splitter into a cooling stream and a process stream. The method may further include compressing the cooling stream using a turbo compressor, expanding the compressed cooling stream using a turbo expander, cooling the process stream in a heat exchanger, and expanding the process stream to further cool the process stream. Also, the method may include directing the process stream into a separation vessel to separate a liquid and a vapor, storing the liquid in a storage tank, and flowing the vapor from the separation vessel and a vapor from the storage vessel into the first mixer to mix with gas from the source of gas. Additionally, the method may include vaporizing a portion of the liquid from the separation tank using the heat exchanger, and flowing gas from the heat exchanger to the first mixer to mix with gas from the source of gas. 
     
    
     
       BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS 
         [0021]    The foregoing and other advantages of the invention will become apparent upon reading the following detailed description and upon reference to the drawings. 
           [0022]      FIG. 1  is a process flow diagram for a liquefaction plant according to an embodiment of the present invention. 
           [0023]      FIG. 2  is a schematic overview of a gas source, a liquefaction plant and LNG storage, according to an embodiment of the present invention. 
       
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
       [0024]    Illustrated in  FIG. 1  is a schematic overview of a plant  10  for natural gas (NG) liquefaction according to an embodiment of the present invention. The plant may include a process stream  12 , a cooling stream  14 , return streams  16 ,  18  and a vent stream  20 . As shown in  FIG. 1 , the process stream  12  may be directed into a mixer  22  and then through a compressor  24 . Upon exiting the compressor  24  the process stream may be directed through a heat exchanger  26  and then through a splitter  28 . The process stream may exit an outlet of the splitter  28  and then be directed through a primary heat exchanger  30  and an expansion valve  32 . The process stream  12  may then be directed though a gas-liquid separation tank  34 . Finally, the process stream  12  may be directed through a splitter  36 , a pump  38 , a valve  40 , a storage tank  42  and a liquid natural gas (LNG) outlet  44 . 
         [0025]    As further shown in  FIG. 1 , the cooling stream  14  may be directed from the splitter  28  through a turbo compressor  46 , an ambient heat exchanger  48 , the primary heat exchanger  30 , a turbo expander  50 , and finally, redirected through the primary heat exchanger  30  and into the mixer  52 . 
         [0026]    A first return stream  16  may include a combination of streams  14 ,  16 ,  20  from the plant  10 . For example, as shown in  FIG. 1 , the first return stream  16  may originate from the separation chamber  34  and be directed into a mixer  54  where it may be combined with the vent stream  20  from the storage tank  42 . The first return stream  16  may then be directed from the mixer  54  through the primary heat exchanger  30 . Upon exiting the primary heat exchanger  30 , the first return stream  16  may be directed into the mixer  52 , where it may be combined with the cooling stream  14 . The first return stream  16  may then be directed out of the mixer  52  and through a compressor  56 . After exiting the compressor  56 , the first return stream  16  may be directed through a heat exchanger  58 , and finally, into the mixer  22 . 
         [0027]    Finally, as shown in  FIG. 1 , a second return stream  18  may be directed from an outlet of the splitter  36 . The second return stream  18  may then be directed through a pump  60 , the primary heat exchanger  30 , and finally, into the mixer  22 . 
         [0028]    In operation, a process stream  12  comprising a gaseous NG may be provided to the plant  10  through an inlet into the mixer  22 . In some embodiments, the process stream  12  may then be compressed to a higher pressure level with the compressor  24 , such as a turbo compressor, and may also become heated within the compressor  24 . Upon exiting the compressor  24  the process stream  12  may be directed through the heat exchanger  26  and may be cooled. For example, the heat exchanger  26  may be utilized to transfer heat from the cooling stream to ambient air. After being cooled with the heat exchanger  26 , the process stream  12  may be directed into the splitter  28 , where a portion of the process stream may be utilized to provide the cooling stream  14 . In additional embodiments, a process stream  12  comprising a gaseous NG may be provided to the plant  10  through an inlet into the mixer  22  at a sufficient pressure that the compressor  24  and the heat exchanger  26  may not be required and may not be included in the plant  10 . 
         [0029]    The cooling stream  14  may be directed from the splitter  28  into the turbo compressor  46  to be compressed. The compressed cooling stream  14  may then exit the turbo compressor  46  and be directed into the heat exchanger  58 , which may transfer heat from the cooling stream  14  to ambient air. Additionally, the cooling stream  14  may be directed through a first channel of the primary heat exchanger  30 , where it may be further cooled. 
         [0030]    In some embodiments, the primary heat exchanger  30  may comprise a high performance aluminum multi-pass plate and fin type heat exchanger, such as may be purchased from Chart Industries Inc., 1 Infinity Corporate Centre Drive, Suite 300, Garfield, Heights, Ohio 44125, or other well known manufacturers of such equipment. 
         [0031]    After passing through the primary heat exchanger  30 , the cooling stream  14  may be expanded and cooled in the turbo expander  50 . For example, the turbo expander  50  may comprise a turbo expander having a specific design for a mass flow rate, pressure level of gas, and temperature of gas to the inlet, such as may be purchased from GE Oil and Gas, 1333 West Loop South, Houston, Tex. 77027-9116, USA, or other well known manufacturers of such equipment. Additionally, the energy required to drive the turbo compressor  46  may be provided by the turbo expander  50 , such as by the turbo expander  50  being directly connected to the turbo compressor  46  or by the turbo expander  50  driving an electrical generator (not shown) to produce electrical energy to drive an electrical motor (not shown) that may be connected to the turbo compressor  46 . The cooled cooling stream  14  may then be directed through a second channel of the primary heat exchanger  30  and then into the mixer  52  to be combined with the first return stream  16 . 
         [0032]    Meanwhile, the process stream  12  may be directed from the splitter  28  through a third channel of the primary heat exchanger  30 . Heat from the process stream  12  may be transferred to the cooling stream  14  within the primary heat exchanger  30  and the process stream  12  may exit the primary heat exchanger  30  in a cooled gaseous state. The process stream  12  may then be directed through the expansion valve  32 , such as a Joule-Thomson expansion valve, wherein the process stream  12  may be expanded and cooled to form a liquid natural gas (LNG) portion and a gaseous NG portion that may be directed into the separation chamber  34 . The gaseous NG and the LNG may be separated in the separation chamber  34  and the process stream  12  exiting the separation chamber may be a LNG process stream  12 . The process stream  12  may then be directed into the splitter  36 . From the splitter  36  a portion of the LNG process stream  12  may provide the return stream  18 . In some embodiments, the remainder of the LNG process stream  12  may be directed through the pump  38 , then through the valve  40 , which may be utilized to regulate the pressure of the LNG process stream  12 , and into the storage tank  42 , wherein it may be withdrawn for use through the LNG outlet  44 , such as to a vehicle which is powered by LNG or into a transport vehicle. 
         [0033]    The gaseous NG from the separation chamber  34  may be directed out of the separation chamber  34  in the first return stream  16 . The first return stream  16  may then be directed into the mixer  54  where it may be combined with the vent gas stream  20  from the storage tank  42 . The first return stream  16  may be relatively cool upon exiting the mixer  54  and may be directed through a fourth channel of the primary heat exchanger  30  to extract heat from the process stream  12  in the third channel of the primary heat exchanger  30 . The first return stream  16  may then be directed mixer  52 , where it may be combined with the cooling stream  14 . The first return stream  16  may then be compressed to a higher pressure level with the compressor  56 , such as a turbo compressor, and incidentally may also become heated within the compressor  56 . A power source (not shown) for the compressors  24 ,  46 ,  56  may be any suitable power source, such as an electric motor, an internal combustion engine, a gas turbine engine, such as powered by natural gas, etc. 
         [0034]    Upon exiting the compressor  56 , the first return stream  16  may be directed through the heat exchanger  58  and may be cooled. For example, the heat exchanger  58  may be utilized to transfer heat from the first return stream  16  to ambient air. After being cooled with the heat exchanger  58 , the first return stream  16  may be directed into the mixer  22 . 
         [0035]    Finally, the second return stream  18 , which may originate as LNG from the splitter  36 , may be directed through a fifth channel of the primary heat exchanger  30 , where the second return stream  18  may extract heat from the process stream  12 , and the second return stream  18  may become vaporized to form gaseous NG. The second return stream  18  may then be directed into the mixer  22 , where it may be combined with the first return stream  16  and the process stream  12  entering the plant  10 . In some embodiments, the second return stream  18  may be directed through the pump  60  upon exiting the splitter  36 . In additional embodiments, a pump (not shown) may be located between the separation chamber  34  and the splitter  36  and the pump  60  may not be required and may not be included in the plant  10 . Furthermore, if a pump (not shown) is included that is located between the separation chamber  34  and the splitter  36  the pump  38  may not be included in the plant  10  and the valve  40  may be utilized to regulate the pressure of the LNG process stream  12  directed to the storage tank  42 , thus reducing the number of pumps included in the plant  10 . 
         [0036]    As shown in  FIG. 2 , an LNG liquefaction plant  10  may be coupled to a clean-up unit  70  that may be coupled to a gas source  80 . The clean-up unit  70  may separate, such as by filtration, impurities from the NG before the liquefaction of the gas within the plant  10 . For example, the gas source  80  may be a waste disposal site, which may contain a number of gases not conductive to transportation fuel and a liquefaction process. Such gases may include water, carbon dioxide, nitrogen, soloxains, etc. Additionally, the gas from the gas source  80  may be pressurized prior to being directed into the plant  10 . Conventional methods and apparatus for such cleaning and pressurization may be utilized. 
         [0037]    The gas source  80  may be a gas supply such as a waste disposal site, coal bed methane well, or natural gas pipeline, or any source of gas where a portion of the gas therefrom that has not been liquefied cannot be returned to the source. The gas from the gas source  80  may be fed into the clean-up unit  70 , which may contain a number of components for cleaning the gas and optionally for pressurization of the gas during such cleaning. After cleaning the gas, the pressure of the clean gas may be increased to a suitable level for the plant  10 . Additionally, depending on the pressure of the gas from the gas source  80 , it may be necessary to compress the gas prior to the cleaning the gas. For example, gas from a waste disposal site typically has a pressure of approximately atmospheric pressure requiring using a compressor to increase the pressure of the gas before any cleaning of the gas. By using a compressor to increase the pressure of the gas before cleaning of the gas from a waste disposal site, compression of the gas after cleaning may not be required. However, in many situations the use of a compressor to increase the pressure of the gas both before and after cleaning of the gas may be required. 
         [0038]    As shown in  FIG. 2 , an optional gas return  82  may be provided to return gases from the plant  10  to the clean-up unit  70  for additional cleaning of the gas. For example, gases, such as nitrogen, may build-up over time and need to be returned to be removed from the gas. Additionally, a vent stream  20  may be directed back into the plant  10  from the storage tank  42 , as previously described with reference to  FIG. 1  herein. 
       Example 
       [0039]    In one embodiment, the process stream  12  may be provided to the plant  10  at a pressure level of approximately 300 psia, a temperature level of approximately 100° F., and at a mass flow rate of approximately 1000 lbm/hr. The incoming process stream  12  may then mixed in the mixer  22  with the return streams  16 ,  18 , creating a process stream  12  exiting the mixer  22  having a flow rate of approximately 6350 lbm/hr, at a pressure level of approximately 300 psia, and a temperature level of approximately 97° F. The process stream  12  may then be compressed by the compressor  24  to a pressure level of approximately 750 psia and cooled by ambient air to a temperature level of approximately 100° F. with the heat exchanger  26  prior to being directed into the splitter  28 . About fifty-seven (57%) percent of the total mass flow may be directed into the cooling stream  14  and the remaining about forty three (43%) percent of the mass flow may be directed into the process stream  12  exiting the splitter  28 . The process stream  12  may be cooled to a temperature level of approximately −190° F. within the primary heat exchanger  30  and may exit the primary heat exchanger  30  at a pressure level of approximately 750 psia. The process stream  12  may then be further cooled by the expansion valve  32  to approximately −237° F. at a pressure of approximately 35 psia, which may result in a process stream  12  comprised of about 21% vapor and about 79% liquid. This example may provide a plant  10  and method of liquefaction that enables the liquefaction of 1000 lbm/hr, an amount equal to the input into the plant  10 . 
         [0040]    As may be readily apparent from the forgoing, the process and plant  10  as described herein may recycle a portion of the gas in the process and plant  10  to liquefy an amount of gas for storage or use that is equal to the mass flow into the process and plant. In this manner, the process and plant  10  can be used for liquefaction of gas where gas cannot be returned to the source thereof such as described herein. For example, the plant  10  may be utilized for waste disposal sites, coal bed methane wells, and off-shore wells. 
         [0041]    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 scope of the invention as defined by the following appended claims.