Abstract:
Disclosed are methods and systems for vaporization of liquefied natural gas (LNG) that employ a condensing gas stream to adjust the gross heating value (GHV) of the LNG such that, upon vaporization, a natural gas product is obtained that meets pipeline or other commercial specifications. The condensing gas can be air, nitrogen, or in embodiments, NGLs such as ethane, propane, or butane, or other combustible hydrocarbon such as dimethyl ether (DME) depending on a desired change in GHV. In some embodiments, the methods and systems employ an integrated air separation plant for generation of nitrogen used as a condensing gas, wherein a cool stream of a heat transfer medium, such as water, ethylene glycol, other common heat transfer fluids, or mixtures thereof, obtained by heat transfer during vaporization of the LNG is used to pre-cool an air feed to the air separation plant, or to cool other process streams associated therewith.

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application claims benefit of U.S. Provisional Application Ser. No. 60/529,693, filed Dec. 15, 2003, the teachings of which are incorporated herein by reference in their entirety. 
    
    
     FIELD OF THE INVENTION 
     The present invention relates generally to the storage and distribution of liquefied natural gas (LNG) and vaporization of the LNG into a natural gas product. More particularly, the present invention relates to systems and methods to modify the gross heating value (GHV) of the LNG so as to produce, upon vaporization, a natural gas product that meets pipeline or commercial specifications, or is otherwise interchangeable with domestically produced natural gas. 
     BACKGROUND OF THE INVENTION 
     Presently, the use of imported LNG is becoming increasingly important for many countries as the demand for natural gas continues to increase, while domestic production, particularly in the United States and Canada, has been on decline. The imported LNG can make up for a shortfall in domestic production and/or otherwise meet market demand during peak periods, such as during the winter heating season. Such LNG is produced by any of a number of liquefaction methods known in the art, and typically is produced at and imported from a number of remote areas around the world having vast natural gas supply sources, such as the Middle East, West Africa, Trinidad, Australia, and Southeast Asia. After being shipped from such remote locations by specially designed cryogenic tankers, the LNG is typically stored at cryogenic temperatures, until just prior to use, at various locations around the world near locations of high natural gas demand. 
     It is known that LNG produced from such remote locations in many instances when vaporized does not meet pipeline or other commercial specifications. The resulting natural gas may have an unacceptably high heating value, typically referred to as gross heating value or “GHV”. Various methods have been proposed or used to adjust the GHV of LNG to produce natural gas that will meet pipeline specifications, as is discussed by D. Rogers in “Gas Interchangeability and Its Effects On U.S. Import Plans”, Pipeline &amp; Gas Journal, August 2003 at pages 19-28 and “Long-term Solution Needed To Embrace Imports With Pipeline Gas”, Pipeline &amp; Gas Journal, September 2003, at pages 14-22. For example, such “GHV reduction” or “BTU stabilization” is said by Rogers to be conducted by one or more of the following methods: 1) blending of a high GHV LNG liquid with another LNG liquid having a lower GHV value, such as in the storage tank used to hold LNG prior to sendout; 2) blending of natural gas obtained from a high GHV LNG after vaporization with domestically produced natural gas having a relatively low GHV; 3) injection of an inert gas, such as air or nitrogen, into vaporized LNG prior to its introduction into a pipeline; and 4) stripping heavier hydrocarbons such as ethane, propane, and butane (also known as natural gas liquids or NGLs) from the LNG prior to sendout. 
     A particular method for NGL removal to lower the GHV of LNG is disclosed by U.S. Pat. No. 6,564,579. 
     The methods mentioned above generally require significant additional capital costs or have operational problems associated with them. For example, option  1  advanced by Rogers is not very practical as it would either require maintaining a separate inventory of LNG liquids with suitable GHV values, or very careful management of shipments of specific LNG liquids with suitable GHV values for blending with the remaining LNG contained within existing storage tanks. Option  3  would require expensive equipment to conduct the injection into the vaporized LNG, including compressors for raising the pressure up to pipeline pressure, typically as high as 100 bar. Option 4 advanced by Rogers, and the method disclosed in U.S. Pat. No. 6,564,579, would require expensive equipment to remove the desired amount of NGLs. 
     Conversely, in other parts of the world, such as Japan, there is a desire to increase the GHV of LNG, particularly for LNG having a relatively low GHV produced from sources of natural gas having lower levels of NGLs therein. The GHV can be increased by injection of NGLs or other combustible hydrocarbon materials, such as dimethyl ether, into the LNG such that upon vaporization the resulting natural gas product has an increased GHV. 
     The LNG is typically stored at low pressure, in liquid form, and at cryogenic temperatures at an import terminal. The LNG is usually pumped to a pressure that is slightly above the pressure of the natural gas distribution pipeline. The high-pressure liquid is then vaporized and sent to the distribution pipeline. The pumping operation typically involves a set of low-pressure pumps located in a storage tank or container connected in series to a set of high-pressure pumps located outside the storage tank. 
     In many instances in the past, LNG has been vaporized by simply burning a portion of the vaporized LNG to produce the heat to warm up and vaporize the remainder of the LNG and produce natural gas. Various heat exchange systems have been used for this purpose. 
     As is well known, heat input into the LNG storage tank gradually generates boil-off vapor during storage. Additional vapor generation may occur during filling of the storage container. Vapors may also be obtained from an outside source such as a ship. Ideally, the above-described boil-off vapors are included with the vaporized natural gas sendout into the distribution pipeline. Compressors may be used to boost these vapors to the high operating pressure of the pipeline, which can be as high as 100 bar. However, compressing the vapor to these high pressures requires considerable energy and expensive compressors and related equipment. 
     U.S. Pat. No. 6,470,706 discloses a system and related apparatus that utilizes cold LNG sendout to condense such boil-off vapors at a low interstage pressure. The teachings of U.S. Pat. No. 6,470,706 are incorporated herein by reference in their entirety. The vapor condensate combines with the liquid sendout and becomes a single phase flow into the high pressure pumps. The combined stream then flows to the vaporizers from the high-pressure pumps. Compressing the boil-off vapor stream to the distribution pipeline pressures requires considerably more energy than boosting the boil-off vapor condensate to the high pressure with a liquid pump. 
     Other LNG import terminals use systems similar to U.S. Pat. No. 6,470,706 that condense boil-off vapor at low pressure and pump the resulting condensate with the liquid LNG stream flowing to the vaporizer. 
     It would be desirable to develop a method and system for GHV reduction or BTU stabilization which is more efficient at adjusting the GHV of LNG so that upon vaporization, the resulting natural gas product is interchangeable with domestically produced natural gas or otherwise able to meet set commercial and/or pipeline specifications. It would also be desirable to develop methods and systems that may accomplish the foregoing objectives by relatively simple and low cost modifications to existing systems for vaporization of LNG. 
     SUMMARY OF THE INVENTION 
     In one aspect, the invention is directed to a method for adjusting the GHV of a liquefied natural gas comprising mixing a condensable gas with the liquefied natural gas, the amount of the liquefied natural gas being sufficient to condense at least a portion of the condensable gas and thereby produce a blended condensate. 
     In embodiments, the invention also is directed to a method for adjusting the GHV of a liquefied natural gas that comprises the following steps: 
     providing a condenser vessel having a contact area therein; 
     directing a condensable gas into the condenser vessel; 
     directing a portion of the liquefied natural gas to the condenser vessel in an amount sufficient to condense at least a portion of the condensable gas upon contact and mixing therewith; and 
     contacting the portion of the liquefied natural gas and the condensable gas in the contact area of the condenser vessel to condense the condensable gas into the liquefied natural gas and thereby obtain a blended condensate. 
     In another aspect, the invention is directed a method for vaporizing a liquefied natural gas having an initial GHV to obtain a natural gas product having a final GHV compatible with pipeline or commercial requirements. The method comprises the steps of: 
     providing a condenser vessel having a contact area therein; 
     directing a condensable gas into the condenser vessel; 
     directing a portion of the liquefied natural gas to the condenser vessel in an amount sufficient to condense at least a portion of the condensable gas upon contact and mixing therewith; 
     contacting the portion of the liquefied natural gas and the condensable gas in the contact area of the condenser vessel to condense the condensable gas into the liquefied natural gas and thereby obtain a blended condensate; and 
     vaporizing the blended condensate to produce the natural gas product. 
     In embodiments, the invention relates to a method for vaporizing a liquefied natural gas having an initial GHV to obtain a natural gas product having a final GHV that meets commercial specifications or is otherwise suitable for transport in a pipeline. The method comprises: 
     providing a condenser vessel having a contact area therein; 
     mixing a condensable gas with an initial portion of the liquefied natural gas to cool the condensable gas; 
     directing the cooled condensable gas into the condenser vessel; 
     directing a vapor stream to the condenser vessel, the vapor stream obtained by boil off of the liquefied natural gas from a storage tank designed to store the liquefied natural gas prior to vaporization and delivery into a pipeline; 
     directing a second portion of the liquefied natural gas to the condenser vessel in an amount sufficient to condense at least a portion of the condensable gas and the vapor stream upon contact and mixing with the second portion of the liquefied natural gas and thereby obtain a blended condensate; 
     mixing a third portion of the liquefied natural gas with the blended condensate to obtain a liquefied natural gas mixture; 
     increasing the pressure of the liquefied natural gas mixture to a desired pressure; and 
     vaporizing the liquefied natural gas mixture to produce the natural gas product. 
     In other embodiments, the invention is more particularly directed to a method for vaporizing a liquefied natural gas having an initial GHV to obtain a natural gas product having a final GHV within a commercial specification or suitable for transport in a pipeline. The method comprises: 
     providing a condenser vessel having a contact area therein; 
     mixing nitrogen gas with an initial portion of the liquefied natural gas to cool the nitrogen gas; 
     directing the cooled nitrogen gas into the condenser vessel; 
     directing a vapor stream to the condenser vessel, the vapor stream obtained by boil off of the liquefied natural gas from a storage tank designed to store the liquefied natural gas prior to vaporization and delivery into a pipeline; 
     directing a second portion of the liquefied natural gas to the condenser vessel in an amount sufficient to condense at least a portion of the nitrogen gas and the vapor stream upon contact and mixing therewith to obtain a blended condensate; and 
     vaporizing the blended condensate to produce the natural gas product. 
     In further embodiments, the invention is directed to a method for vaporizing a liquefied natural gas having an initial GHV to obtain a natural gas product having a final GHV within a commercial specification or suitable for transport in a pipeline, the method comprising: 
     providing a condenser vessel having a contact area therein; 
     providing an air separation plant to obtain nitrogen gas by separation of air; 
     mixing the nitrogen gas with an initial portion of the liquefied natural gas to cool the nitrogen gas; 
     directing the cooled nitrogen gas into the condenser vessel; 
     directing a vapor stream to the condenser vessel, the vapor stream obtained by boil off of the liquefied natural gas from a storage tank designed to store the liquefied natural gas prior to vaporization and delivery into a pipeline; 
     directing a second portion of the liquefied natural gas to the condenser vessel in an amount sufficient to condense at least a portion of the nitrogen gas and the vapor stream upon contact and mixing therewith to obtain a blended condensate; 
     mixing a third portion of the liquefied natural gas with the blended condensate to obtain a liquefied natural gas mixture; 
     increasing the pressure of the liquefied natural gas mixture to a desired pressure; 
     vaporizing the liquefied natural gas mixture to produce the natural gas product in a vaporizer which employs a heat transfer fluid to vaporize the liquefied natural gas mixture; and 
     directing the heat transfer fluid into the air separation plant for purposes of heat exchange with one or more process streams of the air separation plant. 
     In another aspect, the invention relates to a system for adjusting the GHV of a liquefied natural gas. The system comprises a condenser vessel that comprises an inlet for a stream of the liquefied natural gas, an inlet for a stream of a condensable gas, an inlet for a stream of a boil-off vapor obtained by vaporization of the liquefied natural gas, an internal structural member providing a surface area for contact of the stream of the liquefied natural gas with the streams of the condensable gas and the boil-off vapor such that the condensable gas and boil-off vapor condense on contact and mixing with the liquefied natural gas stream to form a blended condensate product, and an outlet for the blended condensate product. 
     In other embodiments, the invention relates to a system for adjusting the GHV of a liquefied natural gas. The system comprises: 
     a mixing device having an inlet for a first stream of the liquefied natural gas, an inlet for a condensable gas, and an outlet, the mixing device adapted to blend the condensable gas with the first stream of a liquefied natural gas to produce a cooled blended stream; 
     a condenser vessel comprising an inlet for a second stream of the liquefied natural gas, an inlet for the blended stream, an internal structural member providing a surface area for contact of the liquefied natural gas with the blended stream such that the blended stream condenses on contact and mixing with the second liquefied natural gas stream to form a condensate product, and an outlet for the condensate product; and 
     a conduit for conveying the blended stream from the outlet of the mixing device to the inlet of the condenser vessel for the blended stream. 
     In further embodiments, the invention is directed to a system for vaporizing a liquefied natural gas comprising: 
     a mixing device having an inlet for a first stream of the liquefied natural gas, an inlet for a condensable gas, and an outlet, the mixing device adapted to blend the condensable gas with the first stream of a liquefied natural gas to produce a cooled blended stream; 
     a condenser vessel comprising an inlet for a second stream of the liquefied natural gas, an inlet for the blended stream, an internal structural member providing a surface area for contact of the liquefied natural gas with the blended stream such that the blended stream condenses on contact and mixing with the second liquefied natural gas stream to form a blended condensate product, and an outlet for the blended condensate product; 
     a conduit for conveying the blended stream from the outlet of the mixing device to the inlet of the condenser vessel for the blended stream; 
     a pump having an inlet in fluid communication with the outlet of the condenser vessel, and an outlet; and 
     at least one vaporizer for vaporization of the blended condensate product into a natural gas product, the at least one vaporizer having an inlet for the blended condensate product in fluid communication with the outlet of the pump; an inlet for a heat transfer fluid; an outlet for the heat transfer fluid; and an outlet for the natural gas product which is in fluid communication with an inlet of a natural gas transportation pipeline. 
     An important feature of the invention is that condensable gases, such as air, nitrogen, and even NGLs and other combustible hydrocarbons, such as dimethyl ether (depending upon the desired change in GHV or other natural gas specification), can be condensed into LNG by using cold LNG sendout as a condensing fluid. The type and amount of condensable gas employed is selected such that the resulting combined condensate will have a GHV value or other natural gas specification compatible with the pipeline or commercial use contemplated for the natural gas product upon vaporization of the combined condensate. 
     Other features and advantages are inherent in the methods and systems disclosed herein, or will become apparent to those skilled in the art from reading the following detailed description and its accompanying drawings. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a schematic diagram for an embodiment of the invention that includes condensation of a condensable gas stream, such as a nitrogen diluent gas, by contact with a cryogenic LNG stream to produce a LNG product with an adjusted GHV relative to the cryogenic LNG stream. 
         FIG. 2  is a schematic diagram of another embodiment of the invention that includes an air separation plant for generation of a nitrogen gas stream that may be employed as a condensable gas in the process depicted in  FIG. 1 .  FIG. 2  further includes integration of the air separation plant with the method of  FIG. 1  in that a cool heat transfer fluid, such as a mixture of water/ethylene glycol (WEG) obtained by vaporizing the LNG product by the process of  FIG. 1 , is used to cool various streams of the air separation plant, such as an air feed stream or nitrogen gas stream generated by the air separation plant. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     In the description of the Figures, the same numbers will be used to refer to the same or similar components. Further, not all heat exchangers, pumps, valves, and the like, necessary to achieve the accomplishment of the process, as known to those skilled in the art, have been shown for simplicity. 
     Referring now to  FIG. 1 , an embodiment of a system for vaporizing LNG in accordance with the present invention is shown. Typically, processes for vaporizing LNG are based upon a system wherein LNG is delivered, for instance, by an ocean going tanker via line  11  into LNG storage tank  12 . Tank  12  is a cryogenic tank as known to those skilled in the art for storage of LNG. The LNG could alternatively be supplied by a process located adjacent to tank  12 , by pipeline, or any other source. 
     As mentioned above, such LNG generally has a GHV which is higher than domestically produced natural gas present in pipelines or otherwise used commercially; typically the LNG imported from most natural gas producing areas has a GHV of greater than 1065 BTU/ft 3 , and generally from 1070 BTU/ft 3  to 1200 BTU/ft 3 , and more specifically from 1080 BTU/ft 3  to 1150 BTU/ft 3 . 
     As shown, in-tank, low-pressure pumps  14  are used to pump the LNG from tank  12  through a line  16 , which LNG is typically stored at a temperature of about −255° F. (−159.4° C.) to about −265° F. (−165° C.) and a pressure of about 2 to 5 psig (0.138 to 0.345 bar). Pump  14  typically pumps the LNG through line  16  at a pressure from 35 psig (2.4 bar) to 200 psig (13.8 bar), preferably from about 50 psig (3.4 bar) to about 150 psig (10.4 bar), and at substantially the temperature at which the LNG is stored in tank  12 . 
     The LNG as delivered inevitably is subject to some gas vapor loss (collectively boil-off vapor as mentioned previously) and is conveyed from tank  12  as shown through a line  20 . This boil-off vapor directed via line  20  is typically recompressed in a compressor  24  driven by a power source, not shown. The power source may be a gas turbine, a gas engine, an engine, a steam turbine, an electric motor or the like. As shown, the compressed boil-off vapor is passed through a line  26  to a condenser vessel  30  where it enters the vessel at inlet  28 . The boil-off vapor is condensed, as shown, by passing a quantity of cold LNG from tank  12  via line  16  and a line  19  into a condenser vessel  30  where the boil-off vapor, which is now at an increased pressure, is contacted in a contact area  32  of condenser vessel  30  with the cold LNG from line  19 . Upon contact and mixing with the cold LNG stream, the boil-off vapor condenses and is combined with the LNG stream to desirably produce a substantially liquid LNG stream that may be recovered through a line  44 . A line  17  is used to direct a portion of the cold LNG from line  16  directly to high-pressure pump  46  (described hereinbelow) and thereby bypass the condenser vessel  30 . The amount of cold LNG conveyed by line  17  will depend on the amount of natural gas product to be produced in vaporizer  50  (as needed by local market demand) and also the amount of cold LNG conveyed by lines  18  and  19  as necessary to condense the boil-off gas and condensable gas in condenser vessel  30 . 
     To adjust the GHV of the LNG, a source of a condensable gas (which may have no GHV or a different GHV) is provided via line  36 , which for reduction of GHV is desirably air or nitrogen (molecular nitrogen or N 2 ) gas. Preferably, the condensable gas is nitrogen gas, as this gas is generally inert and does not contribute toward corrosion of the contact vessel  30  or any related downstream equipment. In the event that an increase in GHV is desired, the condensable gas may be a stream with a higher GHV value relative to the LNG employed, such as a relatively NGL rich hydrocarbon stream with a higher carbon content of C 2+ , such as ethane, propane, and butane, or other combustible hydrocarbon such as dimethyl ether. The amount of condensable gas employed will depend on the specific LNG and condensable gas employed, and also the desired GHV value as a result of condensing the condensable gas into the LNG. In preferred embodiments of those embodiments which employ nitrogen gas as a condensable gas, the nitrogen is employed in an amount such that the total content of inerts (nitrogen and carbon dioxide) is about 4 mol % or less due to pipeline specifications. The condensable gas is supplied at a pressure generally slightly above the operating pressure of the condenser vessel  30 . 
     The nitrogen gas employed can be from any source known in the art, including but not limited to, that obtained by separation of nitrogen from air according to well-known technology. Alternatively, the nitrogen can be generated and separated from air using one or more membrane separator cells, also according to well-known, commercially available technology. If nitrogen gas is not generated on or adjacent to the site where the instant method is being practiced, the nitrogen gas may be supplied from an external source and stored in containers, such as one or more storage tanks, until used according to the present method. 
     In the embodiment shown in  FIG. 1 , the condensable gas is first directed to a mixing device  40  which generally mixes the condensable gas with a stream of cold LNG provided to mixing device  40  via a line  18 . The mixing device  40  is provided to mix the condensable gas with a cold stream of LNG so as to desuperheat the condensable gas and enhance the condensation of such condensable gas in condenser vessel  30 . Preferably, the mixing device  40  is a static, in-line mixer, which is well known to those skilled in the art and available from a variety of vendors. The mixing device  40  also minimizes the condensing load on the contact area  32  of mixing device  30 . Treatment of the condensing gas in mixing device  40  also helps reduce the required size of the condenser vessel  30 . After conditioning of the condensable gas in mixing device  40 , the condensing gas is at a pressure of from 35 psig (2.4 bar) to 200 psig (13.8 bar), preferably at a pressure of from 50 (3.4 bar) to 150 psig (10.3 bar), and a temperature of from −260° F. (−165° C.) to −150° F. (−162.2° C.). However, it may be possible to omit mixing device  40 , if the condensing gas is supplied at a sufficiently low temperature and a flow rate which minimizes, and preferably substantially eliminates, the presence of vapor or condensing gas at the inlet of high-pressure pump  46 . 
     Condenser vessel  30  may be any vessel known in the art for condensing boil-off vapor from LNG storage tanks and vessels, as mentioned in U.S. Pat. Nos. 6,470,706 B1 and 6,564,579 B1, the teachings of which are hereby incorporated by reference in their entirety. In particular, the condenser vessel and related apparatus described in U.S. Pat. No. 6,470,706 are preferred for use in the practice of the present invention. The condenser vessel  30  generally has internal members, such as a plurality of packing elements, such as 2-inch (5.1 cm) Pall rings, disposed within the vessel to provide a contact area  32  which has an enhanced surface area for contact of LNG with both boil-off gas and the condensing gas. The heat and mass transfer for vapor/gas condensing in the contact area  32  can also be enhanced by any of the various alternative means well known in the art for gas/liquid contact in a column, such as by structured packing, tray columns and spray elements. After conditioning of the condensing gas in mixing device  40 , the condensing gas is conveyed by a line  41  to the condenser vessel  30 , wherein it is introduced via inlet  42 . Preferably, the inlet  42  is at or below the contact area  32 . Upon contact and mixing with the cold LNG introduced into the condenser vessel, the condensing gas also condenses with the boil-off vapor and forms a blended condensate which is then conveyed by a line  44  to high-pressure pump  46 . 
     It is possible in some embodiments to omit condenser vessel  30  such that the condensable gas is mixed with a stream of cold LNG, and thereby condensed upon contact and mixing therewith, within mixing device  40 , and preferably a static, in-line mixer is used for mixing device  40  as previously described. In such embodiments, the hydraulic conditions should be sufficient that the resulting mixed, condensed stream is substantially in the liquid phase and of sufficient volume, i.e. surge, prior to being introduced to high-pressure pump  46  described hereinafter so that two-phase flow into said pump is avoided or minimized. 
     The condenser vessel  30  is typically operated at a pressure of from 35 psig (2.4 bar) to 200 psig (13.8 bar), and preferably 50 psig (3.4 bar) to 150 psig (10.3 bar), and a temperature of from −265° F. (−165° C.) to −200° F. (−128.9° C.), and preferably from −265° F. (−165° C.) to −260° F. (−162.2° C.). 
     High-pressure pump  46  receives cold LNG via line  17  and the blended condensate via line  44  and thereby increases the pressure thereof; typically, high pressure pump  46  discharges the resulting LNG mixture into a line  47  at a pressure suitable for delivery to a pipeline. Such pipeline pressures are typically from about 800 psig (55.2 bar) to about 1200 psig (82.7 bar) and can be up to 1450 psig (100 bar), although these specifications may vary from one pipeline to another. The LNG mixture in line  47  is passed to the inlet  48  of a vaporizer  50  or other heat exchanger well known in the art for vaporization of LNG. A natural gas product exits the vaporizer  50  at outlet  52  suitable for introduction into an existing natural gas transmission pipeline or system or other commercial use. Typically the temperature of the natural gas exiting from outlet  52  is about 30° F. (1° C.) to 50° F. (10° C.), but this may also vary. 
     In terms of GHV, the LNG mixture in line  47  will in some embodiments result in a natural gas product upon vaporization of 1065 BTU/ft 3  or less, and for those embodiments it is preferably from 1020 BTU/ft 3  to 1065 BTU/ft 3 . 
     Vaporizer  50  may be any type known in the art for vaporizing a LNG stream, such as a shell and tube heat exchanger, submerged combustion vaporizer, or open rack vaporizer. For example, water or air may be used as a heat exchange media, or the heat exchanger may be a fired unit. Such variations are well known to those skilled in the art. It is preferred in practicing the invention to use water, or a mixture of water and other heat exchange fluid, such as ethylene glycol, as the heat exchange medium in vaporizer  50 . In  FIG. 1 , a cooling loop is shown. A cool stream of heat transfer medium, such as a 50/50 mixture by weight of water and ethylene glycol, exits vaporizer  50  through line  56 . A line  58  is shown wherein a portion of the cool heat transfer medium is conveyed by line  58  outside of the system for use elsewhere, such as for example, use as a coolant to condition the air feed or other process stream associated with a nitrogen/oxygen air separation plant as shown in  FIG. 2  and discussed hereinbelow. The cool heat transfer medium could also be used to cool the condensing gas, such as nitrogen, which is obtained from the separation plant or elsewhere, and used in the process as described herein. Pump  62  is used to convey the heat transfer medium through lines  59 ,  61 ,  63  and  54  into vaporizer  50 . A heat exchanger  64  can be used to adjust the temperature of the heat transfer medium to a desired temperature for use in vaporizer  50 . 
     Referring now to  FIG. 2 , an embodiment of the invention is shown which includes an integrated air separation plant for purposes of supplying nitrogen gas as a condensable gas for use in the condenser vessel  30  of  FIG. 1 . Air is fed to the air separation plant via a line  66  which is initially directed to a compressor  70 , wherein the pressure is increased to that typical for use in an air separation plant, such as from 250 psig (17.2 bar) to 400 psig (27.6 bar), which compressor  70  is driven by a power source, not shown. The power source may be a gas turbine, a gas engine, an engine, a steam turbine, an electric motor or the like. After compression, the air feed stream is directed via line  72  to a conditioning unit  78  wherein the air is filtered to remove any particulate matter therefrom and also dehydrated by use of molecular sieve dehydration, membrane, or pressure swing adsorption (PSA), all of which are well-known in the art. The air feed is then directed to heat exchanger  80  via a line  82 , wherein the air is pre-cooled to a temperature of preferably from 55° F. (12.8° C.) to 100° F. (37.8° C.) before cryogenic distillation. As another integration feature, heat exchanger  80  utilizes a heat transfer medium (coolant) conveyed by line  58  that comprises the portion of the cool heat transfer medium as previously described, which is obtained from the cooling loop employed for vaporization of the LNG in vaporizer  50  of  FIG. 1 . Line  86  returns the heat transfer medium to line  59  of the cooling loop that employs the heat transfer medium as shown in  FIG. 1 . Utilization of this cool heat transfer medium can result in significant savings in terms of operating costs. Further, use of the heat transfer medium to indirectly transfer heat from the air feed stream to the cold LNG being vaporized allows beneficial use of the cold LNG without the safety (explosive combustion) concerns that might be present if the cold LNG stream is used in a heat exchanger to directly transfer heat from the air feed stream to the LNG and/or the relatively rich, but cold, O 2  stream resulting from the air separation. 
     After pre-cooling, the air feed is conveyed by a line  88  to heat exchanger  90  wherein the air is further cooled to a temperature of from −100° F. (−73.3° C.) to −250° F. (−156.7° C.) by heat exchange with cold process streams provided by lines  96  and  94  as described hereinafter. Heat exchanger  90  is typically a multi-pass, plate-fin heat exchanger of the type well-known to those skilled in the art. The cooled air stream is then conveyed by line  92  to turboexpander  102 , where the cooled air stream is expanded in the turboexpander  102  to provide a cooled air stream at a temperature of from −260° F. (−162.2° C.) to −300° F. (−184.4° C.) which is conveyed via line  104  to distillation column  110 . 
     In distillation column  110 , the condensed air stream is separated into streams of relatively pure nitrogen and oxygen, which are recovered from distillation column  110  by lines  96  and  94  respectively. A reboiler is used in conducting the distillation as known to those skilled in the art, and is not shown for simplicity. Distillation column  110  employs well-known air separation technology for separation of the air into the respective streams of nitrogen and oxygen. The stream of nitrogen is conveyed by line  96  to heat exchanger  90 , wherein it is used in exchange relationship to cool the air feed introduced into heat exchanger  90  by line  88 . The nitrogen stream is then conveyed by line  98  to a compressor  112 , that is driven by work derived from expansion of air in turboexpander  102  that is transferred to compressor  112  via shaft  114 . After initial compression in compressor  112 , the nitrogen stream is then conveyed by line  115  to compressor  120 , wherein it is further compressed to a pressure of from 50 psig (3.4 bar) to 150 psig (10.3 bar) suitable for being used in condenser vessel  30  of  FIG. 1 . The compressed nitrogen gas stream is then cooled in a heat exchanger  121  using a portion of the cooled heat exchange medium (water, ethylene glycol, or mixture thereof) taken from line  58 , which portion is conveyed to heat exchanger  121  via line  124 . The compressed nitrogen gas stream is then conveyed to the condenser vessel  30  by line  36 . Similarly, the stream of oxygen is conveyed by line  94  to heat exchanger  90 , wherein it is also used in heat exchange relationship to cool the air feed introduced into heat exchanger  90 . The oxygen is thereafter removed from the process by line  100  and used for other purposes. 
     Having thus described the invention by reference to certain of its preferred embodiments, it should be understood that the embodiments described herein are illustrative rather than limiting in nature and that many variations and modifications are possible within the scope of the present invention.