Patent Publication Number: US-2012036890-A1

Title: Nitrogen rejection methods and systems

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application claims the benefit of U.S. Provisional Application No. 61/178,328 filed May 14, 2009. 
    
    
     FIELD OF THE INVENTION 
     Embodiments of the disclosed invention relate to nitrogen rejection methods and systems. More particularly, embodiments of the disclosed invention relate to methods and systems for efficiently reducing the nitrogen concentration of a natural gas production stream. 
     BACKGROUND OF THE INVENTION 
     This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art. 
     Description of the Related Art 
     Natural gas is one of the world&#39;s fastest growing and most significant sources of energy. It is highly desirable due to it&#39;s availability, relative price, and its reduced environmental impact over coal and other sources of energy generation. Gas fields, some containing recoverable hydrocarbon condensates and/or C2, C3, C4, and C5 natural gas liquids (NGL) components, face the challenge of separating nitrogen from the methane-rich stream in order to meet the energy content (often measured in BTU/scf) requirements for methane gas sales contracts. The separation of nitrogen from methane is technically challenging because the gases have similar size, chemical nature, and boiling point. The additional complexity of nitrogen separation and the compression normally associated with nitrogen removal from methane-rich streams combine to increase the area footprint and weight of the facilities involved. Efficiently reducing the nitrogen content of produced natural gas streams is one of the world&#39;s toughest energy challenges. 
     In a standard cryogenic distillation process used for high flow rate applications, the natural gas feed stream is routed repeatedly through a column and a heat exchanger (typically a brazed aluminum plate-fin type), where the nitrogen is cryogenically separated and vented. This approach is very capital intensive as a lot of aluminum is needed. Further, the final methane product is typically produced at low pressure, so re-pressurization is needed, which is almost always accomplished via energy-intensive compressors. Other existing processes include pressure swing adsorption (PSA), membrane separation, lean oil absorption, and solvent absorption. 
     Existing cryogenic distillation processes require large, expensive, complex pieces of equipment to reduce the nitrogen (N 2 ) content of produced natural gas. In particular, existing cryogenic distillation nitrogen rejection units (NRU&#39;s) also require large quantities of aluminum for fabrication. Another problem with current processes is the significant amount of energy required to compress the methane up to a sufficient pressure for pipeline transport to the destination market. 
     NRU processes other than cryogenic distillation also generally result in large capital expenditure, complexity, and high power consumption costs due to the needed compression and other factors. 
     One example of a common cryogenic nitrogen rejection approach is found in U.S. Pat. No. 7,520,143 (the &#39;143 patent), which discloses a dual stage cryogenic distillation type nitrogen rejection unit (NRU) that produces a low pressure, low temperature liquefied natural gas stream having less than 1.5 mol % nitrogen, a nitrogen vent stream having over 98 mol % nitrogen content, and a fuel stream with a nitrogen content of about 30 mol %. 
     What is needed are methods and systems of more efficiently separating nitrogen from natural gas in natural gas production operations. 
     Other relevant information may be found in U.S. Pat. No. 4,890,988; C OYLE,  D AVID  A., P ATEL,  V INOD,    Processes and Pump Services in the LNG Industry,  Proceedings of the Int&#39;l Pump Users Symposium (2005); and “Rejection Strategies,” Hydrocarbon Engineering, October 2007 pp. 49-52. 
     SUMMARY OF THE INVENTION 
     In one embodiment of the present invention a nitrogen rejection system is provided. The nitrogen rejection system includes a natural gas feed stream comprising nitrogen and methane and having a temperature above cryogenic conditions; a feed stream heat exchanger configured to reduce the temperature of the natural gas feed stream to form a majority liquefied natural gas feed stream; a separation unit configured to receive the cooled natural gas feed stream and produce an overhead stream enriched in nitrogen and a bottoms stream enriched in methane (“liquefied methane stream”); and a liquid methane pump configured to pump the liquefied methane stream to a sales compression pressure to form a pressurized liquefied methane stream, wherein the pressurized liquefied methane stream is substantially vaporized in the feed stream heat exchanger to form a methane product stream. In some embodiments, the liquid methane pump is a sleeve bearing type pump and may further include a magnetic thrust bearing configured to reduce a gravity thrust load on an axial bearing of the liquid methane pump and may be configured as a single pump, a series of at least two pumps, a parallel configuration of at least two pumps, a multistage pump, and any combination thereof. 
     In some embodiments, the separation unit is configured to operate at a pressure of at least about 200 pounds per square inch (psi) to about 500 psi and a temperature of at least about −220 degrees Fahrenheit (° F.) to about −120° F. and may be a tower having a top feed stripper portion and a lower cryogenic reboiler portion configured to separate gaseous nitrogen from the liquefied methane stream. In additional embodiments, at least a portion of the overhead stream enriched in nitrogen is fed to the feed stream heat exchanger to form a warmed nitrogen enriched stream. The system may further include a compressor configured to compress the warmed nitrogen enriched stream to form a compressed nitrogen enriched stream; and a nitrogen rejection unit (NRU) configured to receive the compressed nitrogen enriched stream to form a methane enriched stream, wherein the warmed nitrogen stream is less than about 50 volume percent (vol %) of the natural gas feed stream. Alternatively, a portion of the overhead stream enriched in nitrogen may be fed to a power generation unit configured to generate power using the at least a portion of the overhead stream enriched in nitrogen. 
     In still another alternative embodiment of the system, the system further includes a reboiler feed stream from the separation unit; a slip stream from the substantially liquefied natural gas feed stream; a reboiler heat exchanger configured to exchange heat energy from the slip stream to the reboiler feed stream to generate a nitrogen containing vapor from the reboiler feed stream, wherein the slip stream is then re-mixed with the substantially liquefied natural gas feed stream; and an expansion device configured to receive the substantially liquefied natural gas feed stream and hold a back-pressure on a feed condensing pass of the feed stream heat exchanger, wherein the expansion device is selected from the group consisting of a flow control device, a level control device, a back-pressure control valve, and any combination thereof. Alternatively, the system may include a feed separator configured to produce a nitrogen enriched gas stream and a bottoms stream enriched in methane; and at least one level control valve configured to maintain a liquid level in the feed separator. In a further embodiment, the system may include a flow integrated controller configured to control at least the back-pressure on the feed condensing pass of the feed stream heat exchanger. 
     In a second major embodiment of the disclosure, a method of nitrogen rejection is disclosed. The method includes cooling a natural gas feed stream comprising nitrogen and methane in a feed stream heat exchanger to form a majority liquefied natural gas feed stream; separating the substantially liquefied natural gas feed stream in a separator to produce an overhead stream enriched in nitrogen and a liquid bottoms stream enriched in methane (“liquefied methane stream”); pressurizing the liquefied methane stream in a liquid methane pump to a sales compression pressure to form a pressurized liquefied methane stream; and exchanging heat from the natural gas feed stream to the pressurized liquefied methane stream in the feed stream heat exchanger to form a methane product stream. In some embodiments, the liquid methane pump is a sleeve bearing type pump and further comprises a magnetic thrust bearing configured to reduce a gravity thrust load on an axial bearing of the liquid methane pump, which may be configured as a single pump, a series of at least two pumps, a parallel configuration of at least two pumps, a multistage pump, or any combination thereof. 
     Additional embodiments may provide that the separation unit is configured to operate at a pressure of at least about 200 pounds per square inch (psi) to about 500 psi and a temperature of at least about −220 degrees Fahrenheit (° F.) to about −120° F. or that the separation unit is a tower having a top feed stripper portion and a lower cryogenic reboiler portion configured to separate gaseous nitrogen from the liquefied methane stream. The method may further include feeding at least a portion of the overhead stream enriched in nitrogen to the feed stream heat exchanger to form a warmed nitrogen enriched stream, compressing the warmed nitrogen enriched stream in a compressor to form a compressed nitrogen enriched stream; and feeding the compressed nitrogen enriched stream to a nitrogen rejection unit (NRU) to form a methane enriched stream, wherein the warmed nitrogen stream is less than about 50 volume percent (vol %) of the natural gas feed stream. 
     In a further alternative embodiment, the method may include feeding at least a portion of the overhead stream enriched in nitrogen to a power generation unit; and generating power in the power generation unit. 
     In yet another alternative embodiment, the method may include taking a reboiler feed stream from the separation unit; taking a slip stream from the substantially liquefied natural gas feed stream; exchanging heat energy from the slip stream to the reboiler feed stream in a reboiler heat exchanger to generate a nitrogen containing vapor from the reboiler feed stream; re-mixing the slip stream with the substantially liquefied natural gas feed stream; and maintaining a back-pressure on a feed condensing pass of the feed stream heat exchanger using an expansion device configured to receive the substantially liquefied natural gas feed stream, wherein the expansion device is selected from the group consisting of a flow control device, a level control device, a back-pressure control valve, and any combination thereof. 
     In still another alternative, the method may include producing a nitrogen enriched gas stream and a bottoms stream enriched in methane in a feed separator; and maintaining a liquid level in the feed separator using a level control valve. The method may further provide for controlling at least the back-pressure on a feed condensing pass of the feed stream heat exchanger and the back-pressure on the separation unit using flow integrated controller. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The foregoing and other advantages of the present invention may become apparent upon reviewing the following detailed description and drawings of non-limiting examples of embodiments in which: 
         FIG. 1  is a schematic illustration of a system in accordance with certain aspects of the disclosure; 
         FIG. 2  is a flow chart illustrating of a process in accordance with certain aspects of the system of  FIG. 1 ; 
         FIGS. 3A-3C  are schematics of several exemplary alternative embodiments of the system of  FIG. 1 ; 
         FIG. 4  illustrates a chart showing a temperature heat flow plot for comparing heat flow between hot and cold streams. 
     
    
    
     DETAILED DESCRIPTION 
     In the following detailed description section, the specific embodiments of the present disclosure are described in connection with preferred embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present disclosure, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the disclosure is not limited to the specific embodiments described below, but rather, it includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims. 
     Definitions 
     Various terms as used herein are defined below. To the extent a term used in a claim is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. 
     As used herein, “a” or “an” entity refers to one or more of that entity. As such, the terms “a” (or “an”), “one or more”, and “at least one” can be used interchangeably herein unless a limit is specifically stated. 
     As used herein, the term “enriched” as applied to any stream withdrawn from a process means that the withdrawn stream contains a concentration of a particular component that is higher than the concentration of that component in the feed stream to the process. 
     As used herein, the term “expansion device” refers to one or more devices suitable for reducing the pressure of a fluid in a line (for example, a liquid stream, a vapor stream, or a multiphase stream containing both liquid and vapor). Unless a particular type of expansion device is specifically stated, the expansion device may be (1) at least partially by isenthalpic means, or (2) may be at least partially by isentropic means, or (3) may be a combination of both isentropic means and isenthalpic means. Suitable devices for isenthalpic expansion of natural gas are known in the art and generally include, but are not limited to, manually or automatically actuated throttling devices such as, for example, valves, control valves, Joule-Thomson (J-T) valves, or venturi devices. Suitable devices for isentropic expansion of natural gas are known in the art and generally include equipment such as expanders or turbo expanders that extract or derive work from such expansion. Suitable devices for isentropic expansion of liquid streams are known in the art and generally include equipment such as expanders, hydraulic expanders, liquid turbines, or turbo expanders that extract or derive work from such expansion. An example of a combination of both isentropic means and isenthalpic means may be a Joule-Thomson valve and a turbo expander in parallel, which provides the capability of using either alone or using both the J-T valve and the turbo expander simultaneously. Isenthalpic or isentropic expansion can be conducted in the all-liquid phase, all-vapor phase, or mixed phases, and can be conducted to facilitate a phase change from a vapor stream or liquid stream to a multiphase stream (a stream having both vapor and liquid phases). In the description of the drawings herein, the reference to more than one expansion device in any drawing does not necessarily mean that each expansion device is the same type or size. 
     As used herein, the term “indirect heat exchange” means the bringing of two fluids into heat exchange relation without any physical contact or intermixing of the fluids with each other. Core-in-kettle heat exchangers and brazed aluminum plate-fin heat exchangers are specific examples of equipment that facilitate indirect heat exchange. 
     As used herein, the term “compressor” means a machine that increases the pressure of a gas by the application of work. 
     As used herein, the term “liquid methane pump” means a device for increasing the head of a fluid stream at cryogenic conditions. More specifically, the liquid methane pump is limited to the types of pumps used in processing liquefied natural gas (LNG) and therefore will be capable of pressurizing liquid methane from at least about 200 pounds per square inch (psi) to about 1,200 psi at a flow rate of from at least about 1,000 cubic meters per hour (m 3 /hr) to about 2,500 m 3 /hr and up to about 25,000 m 3 /day. 
     As used herein, the term “reboiler heat exchanger” refers to an indirect heat exchange means used to at least partially vaporize a stream withdrawn near the bottom of a separation unit or feed separator. 
     As used herein, the term “bottoms stream” or “bottoms product” refers to an at least partially liquid stream withdrawn from at or near the bottom portion of a separation unit or separation vessel. 
     As used herein, the terms “comprising,” “comprises,” and “comprise” are open-ended transition terms used to transition from a subject recited before the term to one or elements recited after the term, where the element or elements listed after the transition term are not necessarily the only elements that make up of the subject. 
     As used herein, the terms “containing,” “contains,” and “contain” have the same open-ended meaning as “comprising,” “comprises,” and “comprise.” 
     As used herein, the terms “distillation” or “fractionation” refer to the process of physically separating chemical components into a vapor phase and a liquid phase based on differences in the components’ boiling points and vapor pressures at specified temperature and pressure. Another type of separation may be referred to as “phase separation,” which simply allows a gas-liquid fluid to separate based on differences in the density of the two fluids, for example in a vessel, by releasing the fluid out of the bottom of the vessel and releasing the gas out of the top of the vessel without additional physical elements such as weir plates, strippers, chimneys, internal packing, etc. 
     As used herein, the terms “having,” “has,” and “have” have the same open-ended meaning as “comprising,” “comprises,” and “comprise.” As used herein, the terms “including,” “includes,” and “include” have the same open-ended meaning as “comprising,” “comprises,” and “comprise.” 
     As used herein, the term “natural gas” refers to a multi-component gas obtained from a crude oil well (associated gas) or from a subterranean gas-bearing formation (non-associated gas). The composition and pressure of natural gas can vary significantly. A typical natural gas stream contains methane (C1) as a significant component. The natural gas stream may also contain ethane (C2), higher molecular weight hydrocarbons, and one or more acid gases. The natural gas may also contain minor amounts of contaminants such as water, nitrogen, iron sulfide, wax, and crude oil. 
     As used herein, the term “natural gas feed stream” refers to a stream of natural gas after it has undergone at least some pretreatment, as described elsewhere in the disclosure. 
     As used herein, the term “nitrogen rejection unit” or “NRU” refers to any system or device configured to receive a natural gas feed stream comprising substantially methane and nitrogen and produce substantially “pure” products streams (e.g. a salable methane stream and a nearly pure nitrogen stream—about 96 to 99 percent N 2 ). Examples of types of NRU&#39;s include cryogenic distillation (most common), pressure swing adsorption (PSA), membrane separation, lean oil absorption, and solvent absorption. 
     As used herein, the term “separation unit” refers to any vessel configured to receive a fluid having at least two constituent elements and configured to produce a gaseous stream out of a top portion and a liquid (or bottoms) stream out of the bottom of the vessel. The separation unit may include internal contact-enhancing structures (e.g. packing elements, strippers, weir plates, chimneys, etc.), may include one, two, or more sections (e.g. a stripping section and a reboiler section), and may include additional inlets and outlets. Exemplary vessels include bulk fractionators, strippers, phase separators, and others. 
     As used herein, the term “cryogenic condition” refers to a temperature and pressure that is sufficient to liquefy a majority portion of a fluid. For a fluid containing a single component, the cryogenic condition is below the bubble point of the single component fluid. For a fluid having multiple components, the temperature and pressure may be below the bubble point of only one of the components and if the composition is such that the majority portion of the fluid is liquefied, then the fluid is under cryogenic conditions for purposes of the present disclosure. 
     As used herein, the term “heat exchanger” refers to any device or system configured to transfer heat energy or cold energy between at least two distinct fluids. Exemplary heat exchanger types include a co-current or counter-current heat exchanger, an indirect heat exchanger (e.g. a spiral wound heat exchanger or a plate-fin heat exchanger such as a brazed aluminum plate fin type), direct contact heat exchanger, shell-and-tube heat exchanger, or some combination of these. 
     Description 
     The disclosed systems generally disclose a rough pre-separation of a natural gas feed stream comprising nitrogen and methane and having a temperature above cryogenic conditions. The systems further include a feed stream heat exchanger configured to reduce the temperature of the natural gas feed stream to form a substantially liquefied natural gas feed stream, a separation unit configured to receive the cooled natural gas feed stream and produce an overhead stream enriched in nitrogen and a bottoms stream enriched in methane (“liquefied methane stream”), and a liquid methane pump configured to pump the liquefied methane stream to a gas sales compression pressure to form a pressurized liquefied methane stream, wherein the pressurized liquefied methane stream is substantially vaporized in the feed stream heat exchanger to form a methane product stream. 
     The disclosed methods generally include the steps of cooling a natural gas feed stream in a feed stream heat exchanger to form a substantially liquefied natural gas feed stream, separating the substantially liquefied natural gas feed stream in a separator to produce an overhead stream enriched in nitrogen and a liquid bottoms stream enriched in methane (“liquefied methane stream”), pressurizing the liquefied methane stream in a liquid methane pump to a gas sales compression pressure to form a pressurized liquefied methane stream, and exchanging heat from the natural gas feed stream to the pressurized liquefied methane stream in the feed stream heat exchanger to form a methane product stream. 
     The presently disclosed systems and methods generally disclose pre-separation of a natural gas feed stream to produce a saleable methane product stream and a nitrogen enriched stream still containing a significant amount of methane (e.g. from about 8 to about 40 percent nitrogen by volume with the remainder substantially comprising methane). The produced overhead stream enriched in nitrogen will be about 25 percent to less than 50 percent of the volume of the initial natural gas feed stream, and may then be sent to a traditional NRU to provide additional methane product. The pre-separation step further includes the use of a unique LNG pump to pump the liquefied methane stream up to pressure to provide a pressurized liquefied methane stream for heat exchange with the natural gas feed stream, where the pressurized liquefied methane stream is expanded into gaseous form and provided at high pressure and preferably without additional compression to the methane sales pipeline as a methane product stream. 
     In some embodiments of the systems and methods, the liquid methane pump may be a sleeve bearing type pump and may further include a magnetic thrust bearing to reduce a gravity thrust load on an axial bearing of the liquid methane pump. The separation unit may be a cryogenic separator or include a cryogenic nitrogen stripper (a staged separation device) top portion and a reboiler bottom portion. The overhead stream enriched in nitrogen may be sent to a traditional nitrogen rejection unit for additional nitrogen removal to form another methane product stream or it may be sent to a power generation unit to produce power, or some combination of both of these. 
     The described systems and methods can operate on any gas stream containing 5% to 25% (vol) nitrogen to remove up to 75% or more of the methane in the natural gas feed stream as a methane product stream requiring no further processing (e.g. ready for sale). The heat integration of the natural gas feed stream, the pressurized liquefied methane stream, and the overhead stream enriched in nitrogen have been carefully designed to optimize the pressure to which the liquefied methane stream can be pumped, in order to minimize the gas compression power needed to put the methane product stream into a sales pipeline. The pumping power requirement per unit of liquid methane is much less than the compression power requirement per unit of gaseous methane. Beneficial results of the disclosed systems and methods include greater equipment reliability, lower capital cost, lower operating cost, and smaller equipment footprint. In addition, the size of the NRU (Nitrogen Removal Unit) required to treat the remaining gas is significantly reduced. Many different commercially available NRU designs can be employed downstream of the cryogenic bulk Nitrogen separation process above to separate the Nitrogen from the remaining gas stream. These and other embodiments are further described in the attached figures, which are provided for illustrative purposes. 
     Referring now to the figures,  FIG. 1  is a schematic illustration of a system in accordance with certain elements of the disclosure. The system  100  includes a natural gas feed stream  102 , a feed stream heat exchanger  104  having a feed condensing pass  103 , a substantially liquefied natural gas feed stream  106 , a flow control element  108 , a separation unit  110 , a liquefied methane stream  112 , a liquid methane pump  114 , a pressurized liquefied methane stream  116 , a methane product stream  118 , and an overhead stream enriched in nitrogen  120 . As shown, the pressurized liquefied methane stream  116  and the overhead stream enriched in nitrogen  120  are routed through the feed stream heat exchanger  104 , where the pressurized liquefied methane stream  116  is vaporized to form a methane product stream  118  and the overhead stream enriched in nitrogen is warmed to form a warmed nitrogen enriched stream  122 . 
     Additional elements shown in  FIG. 1  include a diverted warmed nitrogen enriched stream  124  going to a compressor  126  and a compressed warmed nitrogen enriched stream  128  entering a nitrogen rejection unit (NRU)  130  to form another methane product stream  132 . Alternatively or in addition, another diverted warmed nitrogen enriched stream  134  is shown going to a power generation unit  136 . 
     The natural gas feed stream  102  is a natural gas stream that has probably undergone pretreatment to remove some of the contaminants and components from the natural gas stream. Pretreatment is generally the first consideration in cryogenic processing of natural gas. A raw natural gas suitable for the disclosed system  100  may comprise natural gas obtained from a crude oil well (associated gas) or from a gas well (non-associated gas). The composition of the natural gas can vary significantly depending on the source. Natural gas will typically contain methane (C 1 ) as the major component, and will typically also contain ethane (C 2 ), propane (C 3 ), and other higher hydrocarbons, diluents such as nitrogen, argon, and helium, and contaminants such as water, carbon dioxide, mercury, mercaptans, hydrogen sulfide, benzene, methanol, iron sulfide, ethylene glycol, and others. The solubilities of these contaminants vary with temperature, pressure, and composition. At cryogenic conditions, CO 2 , water, and other contaminants can form solids, which can plug flow passages in cryogenic heat exchangers and other equipment. These potential difficulties can be avoided by removing such contaminants. Although requirements may vary, the following are exemplary amounts of contaminants that may be accepted in a methane product stream: water—0.1 part per million (ppm); carbon dioxide—10 to 1,000 ppm; methanol—1.0 ppm; benzene—0.1 ppm; hydrogen sulfide—50 to 500 ppm; ethylene glycol—1.0 ppm. In the following description, it is assumed that the natural gas feed stream  102  has been suitably treated to remove unacceptable levels of mercury, sulfides, carbon dioxide, and other contaminates, and dried to remove water using conventional and well-known processes (e.g. amine treating, membrane separation, adsorption, etc.) to produce a “sweet, dry” natural gas feed stream  102 . Alternatively, some level of these contaminants may be left in the natural gas feed stream  102  and become distributed into the methane product stream which may require additional treatment at a later stage depending on the intended use of the methane product stream. 
     Although feed stream heat exchanger  104  is depicted as surrounding the separation unit  110 , the heat exchanger  104  may not enclose the separation unit  110 , but the system  100  may include a “cold box” (an insulation system comprising a sheet metal box filled with perlite or other appropriate insulating medium) configured to enclose the heat exchanger  104  and the separation unit  110 . The feed exchanger  104  is configured to include a feed condensing pass  103  configured to condense at least a majority portion of the natural gas feed stream  102 . The feed exchanger  104  is further configured to operate at pressures up to about 1,000 pounds per square inch (psi) and lower the temperature of the feed stream  102  to a temperature of from about −180° F. to about −100° F. Note that this temperature range is higher than the temperatures generally required for full cryogenic separation of the type that occurs in a standard cryogenic separation NRU. In some embodiments, the heat exchanger  104  is preferably an indirect heat exchanger such as a spiral wound heat exchanger, a plate-fin heat exchanger (e.g. a brazed aluminum plate fin type), or a printed circuit heat exchanger. 
     The substantially liquefied natural gas feed stream  106  produced from the heat exchanger  104  will preferably comprise from about 5 volume percent (vol %) to about 25 vol % nitrogen with the remainder being primarily methane. In addition, the natural gas feed stream  106  may have an expected flow rate of from at least about 10 million standard cubic feet per day (10 Mscf/d) to about 800 Mscf/d or more (larger amounts may require multiple systems  100  in parallel) and enter the system  100  at a pressure of from about 300 psi to about 1,000 psi. 
     Flow regulating device  108  can be any device or group of devices capable of regulating the flow of liquid to the separation unit  110  to maintain a desired pressure, temperature, and liquid level in the separation unit  110 , such as, but not limited to, a flow control valve, a temperature control valve, a feed separator, a liquid regulator, an expansion device, a flow regulating pump, or a combination of such equipment. If the pressure of stream  106  is higher than the pressure in the separation unit  110 , the flow regulating device  108  can be used to depressurize the liquid to a pressure at or near the pressure of the separation unit  110 . If the pressure of the stream  106  is lower than the pressure in separation unit  110 , a flow regulating pump may be used to increase the pressure of stream  106  to a pressure at or near the pressure of the separation unit  110 . 
     The separation unit  110  may be a simple phase separator device, a bulk fractionator (e.g. distillation) type of device, a stripper column, or some combination of these. The separation unit  110  is considered a cryogenic separation unit because it will receive a majority liquefied natural gas feed stream  106  and produce a liquefied methane stream  112 . In one exemplary embodiment, the separation unit  110  may be a simple cryogenic phase separator, a cryogenic stripper column having stripping internals such as weir plates, a cryogenic distillation column (also referred to as a bulk fractionation column or tower) having one, two, three or more sections with internals configured to increase the amount of contact between a falling liquid product (liquefied methane) and a rising gaseous product (overhead stream enriched in nitrogen). In another alternative embodiment, the separation unit  110  may include one inlet or more than one inlet to receive the majority liquefied natural gas feed stream  106 . For example, in some embodiments, the separation unit  110  may comprise an upper stripping section and a lower reboiler section. 
     The separation unit  110  is configured to operate at pressures from about 200 psi to about 500 psi or from about 250 psi to about 300 psi. Such high pressures are typically not used in conventional nitrogen rejection unit designs to support a salable methane product stream. In addition, the separation unit  110  is configured to produce the liquefied methane stream  112  having less than about 4 volume percent (vol %) nitrogen or less than about 2 vol % or less than about 1 vol % nitrogen. The liquefied methane stream  112  is further configured to be at a pressure from about 200 psi to about 600 psi or from about 300 psi to about 500 psi and a temperature of from about −300 degrees Fahrenheit (° F.) to about −100° F. or from about −280° F. to about −160° F. These compositions, pressures, and temperatures may be adjusted depending upon process economics, requirements of a methane sales contract, flow rate, pressure, and composition of the natural gas feed stream  102 , and other factors that can be adjusted for by a person of ordinary skill in the art. 
     In one exemplary embodiment, the separation unit  110  is configured to produce the overhead stream enriched in nitrogen  120  having from about two times to about four times the concentration of nitrogen in the natural gas feed stream  102 , depending on the amount of nitrogen removal required. The overhead stream enriched in nitrogen  120  is further configured to be at a pressure from about 100 psi to about 500 psi or from about 200 psi to about 400 psi and a temperature of from about −300 degrees Fahrenheit (° F.) to about −100° F. or from about −280° F. to about −160° F. These compositions, pressures, and temperatures may be adjusted depending upon process economics, requirements of a methane sales contract, flow rate, pressure, and composition of the natural gas feed stream  102 , and other factors that can be adjusted for by a person of ordinary skill in the art. 
     In one exemplary configuration, the separation unit  110  is configured to provide overhead stream enriched in nitrogen  120 , which may be sent to a conventional NRU  130 , a power generation unit  136 , or some combination thereof. The nitrogen to methane ratio in the overhead stream enriched in nitrogen  120  is important for providing adequate cryogenic reflux in the NRU  130  to ensure high methane product recovery in the NRU  130 . The separation unit  110  may also be configured to separate from the natural gas feed stream  102  a liquefied methane stream  112  that meets sales pipeline requirements and reduces, to the greatest extent possible, the size of the overhead stream enriched in nitrogen  120  to the NRU  130 . Beneficially, the smaller the overhead stream enriched in nitrogen  120 , the smaller the NRU  130  and its associated compression requirements. 
     The liquid methane pump  114  is preferably a sleeve bearing type pump configured to pump the liquefied methane stream  112  to a gas sales compression pressure to form a pressurized liquefied methane stream  116 . Canned motor pumps are more fully disclosed in U.S. Pat. No. 4,890,988, which is hereby incorporated by reference for purposes of describing canned motor pumps. In general, a canned motor pump includes two coaxial tubular walls defining an annular space for the flow of a heat exchange fluid which heats or cools the can. In addition, sleeve bearing pumps may prove to be more reliable than the currently used roller bearing pumps. These sleeve bearing pumps are capable of reliable long life from the radial and axial sleeve bearings. A significant contribution to the axial thrust bearing long life is a magnetic thrust bearing compensation device which reduces the gravity thrust load on the axial bearing during starting. This reduction in axial thrust load allows the hydrodynamic thrust bearing to build the lubricant film, or lift off quicker, reducing direct frictional contact during startup acceleration. Operationally, the pumps will experience flow variations from near zero to maximum (e.g. up to about 25,000 m 3 /day) rating during cool-down, startups and upset conditions. Similarly, the pressures can vary from near atmospheric to rated conditions (e.g. up to about 1,000 psi). Frequent starting and stopping of these pumps is sometimes required based on feed gas availability. It is believed that no prior art system incorporates these types of pumps for LNG operations. Further, persons skilled in the art prefer not to pump LNG at such high pressures and flow rates due to known reliability issues with the bearings in cryogenic pumping operations at such elevated pressures and flow rates. See, e.g. C OYLE,  D AVID  A., P ATEL,  V INOD,    Processes and Pump Services in the LNG Industry,  Proceedings of the Int&#39;l Pump Users Symposium (2005). 
     The liquid methane pump  114  is preferably configured to pump a fully liquefied or nearly fully liquefied methane stream  112  from a pressure of from a pressure of about 200 psi to about 600 psi up to a pipeline pressure of from about 400 psi to about 1,000 psi, at flow rates (per pump for multiple pump systems) from at least about 1,000 m 3 /hr to about 5,000 m 3 /hr or from about 1,500 m 3 /hr to about 3,000 m 3 /hr (over a day, these rates may be from about 10,000 m 3 /day to about 30,000 m 3 /day) depending on the requirements of the pipeline and the methane sales contract. 
       FIG. 2  is a flow chart illustrating of a process in accordance with certain aspects of the system of  FIG. 1 . As such,  FIG. 2  may be best understood with reference to  FIG. 1 . The process  200  includes box  202  showing the step of cooling a natural gas feed stream  102  in a feed stream heat exchanger  104  to form a substantially liquefied natural gas feed stream  106  and box  204  showing the step of separating the substantially liquefied natural gas feed stream  106  in a separator unit  110  to produce an overhead stream enriched in nitrogen  120  and a liquid bottoms stream enriched in methane (“liquefied methane stream”)  112 . The process  200  further includes box  206  showing the step of pressurizing the liquefied methane stream in a liquid methane pump  114  to a gas sales compression pressure to form a pressurized liquefied methane stream  116  and box  208  showing the step of exchanging heat from the natural gas feed stream  102  to the pressurized liquefied methane stream  116  in the feed stream heat exchanger  104  to form a methane product stream  118 . 
     The process may further include pretreating steps (not shown) as described in connection with the system  100 . The process  200  may also include feeding at least a portion of the overhead stream enriched in nitrogen  120  to the feed stream heat exchanger  104  to form a warmed nitrogen enriched stream  122 , compressing the warmed nitrogen enriched stream in a compressor  126  to form a compressed nitrogen enriched stream  128 , which is fed to a nitrogen rejection unit (NRU)  130  to form a methane enriched stream  132 , which may be sold as a methane product stream. 
       FIGS. 3A-3C  are schematics of several exemplary alternative embodiments of the system of  FIG. 1 . As such,  FIGS. 3A-3B  may be best understood with reference to  FIG. 1 . In  FIG. 3A , to the extent an element in system  300  is designated with the same reference number as system  100 , that element may be considered to be equivalent to or substantially equivalent to the element as described above in connection with system  100 . The system  300  further includes a flow control device  302 , a pressure control device  303 , a controlled flow stream  306  flowing into a feed separator  308  configured to produce a nitrogen enriched gas stream  312  and a bottoms stream enriched in methane  310 , which passes to the separator unit  110  via a level control device  311 . The separator unit  110  is configured with a top feed stripper portion  314  and a lower cryogenic reboiler portion  316  to reduce the nitrogen content of the liquefied methane stream  112 . The system  300  further includes a reboiler stream  324  from the reboiler portion  316  of the separation unit  110  and a slip stream  320  from the substantially liquefied natural gas feed stream  106 , wherein the slip stream  320  and reboiler stream  324  are configured to flow through a reboiler heat exchanger  322  configured to exchange cold energy from the reboiler stream  324  to the slip stream  320 . Nitrogen enriched gas stream  312  is configured to combine with the overhead stream enriched in nitrogen  120  and flow through overhead flow control valve  326  to the heat exchanger  104 . 
     The top feed stripper  314  and reboiler  316  are configured to significantly increase the fraction of the methane in the natural gas feed stream  102  that is removed to the liquefied methane stream  112 . Such removal beneficially significantly reduces the size of the NRU  130  required and further enriches the overhead stream enriched in nitrogen  120  by combining the nitrogen enriched gas stream  312  therewith, which increases methane recovery in the NRU  130  with less methane loop or nitrogen recycle compression. 
     The flow control device  302  may be a low pressure drop temperature control valve configured to increase or decrease the flow of the majority liquefied natural gas feed stream  106  into the slip stream  320  depending on the actual temperature of the majority liquefied natural gas feed stream  106  and the desired temperature of the controlled flow stream  306 . For example, if the temperature of the controlled flow stream  306  is higher than desired, the flow control device  302  may be adjusted to restrict flow therethrough, which will increase the flow of the slip stream  320 , which passes through reboiler heat exchanger  322  where it is cooled by indirect heat exchange with reboiler stream  324  and is then combined with controlled flow stream  306 . Automatic or manual control may be utilized to control the flow rates of the various streams. 
     The feed separator  308  is configured to accumulate fluids and release a gaseous enriched nitrogen stream  312  and a liquid bottoms stream  310 , which is controlled by a level control device  311 . In one embodiment, the level control device  311  is a low pressure drop valve configured to maintain a particular fluid level in the feed separator  308  for continuous operation. Beneficially, this arrangement provides for higher nitrogen concentrations in the overhead stream enriched in nitrogen  120 , a slightly higher methane concentration in liquid bottoms stream  310 , and a slightly lower pressure and temperature in the separation unit  110 . 
     The overhead flow control valve  326  may be a high pressure drop pressure control valve configured to maintain and control the pressure and flow rate of the overhead stream enriched in nitrogen  120 . 
       FIG. 3B  schematically illustrates an exemplary system  350 , which is a modification to the systems  100 ,  300  to provide additional flow control options. As shown, gaseous enriched nitrogen stream  312  may be controlled by pressure control valve  352  to form controlled nitrogen stream  354 , which may be combined with overhead stream enriched in nitrogen  120  to form overhead stream  356 . Beneficially, such an arrangement provides greater control over the stream  356  prior to introduction into the feed stream heat exchanger  104  as well as controlling pressure in the feed separator  308 . 
       FIG. 3C  schematically illustrates an exemplary system  370 , which is a modification to the systems  100 ,  300 ,  350  to provide yet more additional flow control options. In particular, system  370  shows a temperature integrated controller  372  configured to obtain a temperature of the controlled flow stream  306  and operatively connected to flow control device  302  and slip stream flow control device  378 . Also shown is a flow integrated controller  374  configured to obtain a pressure of the majority liquefied natural gas stream  106  and operatively connected to at least flow control valve  376 . Note, the pressure integrated controller  374  may also control the level control device  311  and the back-pressure control valve  352 . Optionally, a feed pressure controller  382  and feed flow controller  384  may be provided. 
     Beneficially, the temperature integrated controller  372  may be configured to provide a more finely tuned temperature control of the controlled flow stream  306  by operating temperature control valves  302  and  378  in concert depending on the actual temperature of the majority liquefied natural gas feed stream  106  and the desired temperature of the controlled flow stream  306 . 
     Still referring to  FIG. 3C , the system  370  may be configured to flow-control the majority liquefied natural gas feed stream  106  downstream of the feed stream heat exchanger  104  using either the flow control device  376  or the level control device  311  or a combination of these to hold the design back-pressure on the feed condensing pass  103  of the feed stream heat exchanger  104 . In particular, the flow integrated controller  374  can be used to override the flow control device  376  output in order to maintain the desired minimum back-pressure in the feed condensing pass  103  of the feed stream heat exchanger  104 . Note that pressure and flow readings may be taken at stream  102 , such as by a pressure sensing device sending information to feed pressure controller  382  to establish a set-point, which may be sent to feed flow controller  384 , which may additionally obtain flow readings from a flowmeter or other sensor to provide a set-point to the flow control device  376 . Alternatively or additionally, readings may also be taken from stream  106  and used to set the flow control device  376 . The flow integrated controller  374  can operate in cascade mode or in automatic flow control mode, which is often used during cooldown and startup or during turndown (low feed flow) operation. In this mode of operation, the level control device  311  is a low pressure drop valve, and the back-pressure on the feed separator  308  and separation unit  110  can be controlled with a common low-pressure drop control valve. 
     In another exemplary alternative embodiment, the system  370  can operate without the feed separator  308 , level control device  311 , and back-pressure control valve  352 . In such an arrangement, the pressure control functions are all accomplished using the flow control device  376 , which is a high pressure drop expansion valve, such as a Joule-Thompson type unit. 
     The flow control device  376  can also be configured to operate independently of the pressure control function by using the back-pressure control valve  352  to increase the operating pressure of the feed separator  308  and using level control device  311  as the primary liquid expansion device (e.g. a Joule-Thompson type valve). Note that the back-pressure control valve  352  would operate as a vapor expansion device in this case. In this embodiment, the top feed separator  308  is provided, and the feed separator  308  operates at the same pressure as the feed condensing pass  103  in the feed exchanger  104 . The temperature control valve  302  is a low pressure drop valve and the feed separator back pressure control  352  and level control valve  311  are both high pressure drop valves. As such, at least part of the feed expansion device operation takes place across these two separator control valves. 
       FIG. 4  illustrates a chart showing a temperature heat flow plot for comparing heat flow between hot and cold streams. The chart  400  plots temperature in degrees Fahrenheit (° F.) along the y-axis  402  and heat flow in millions of British thermal units per hour (MBtu/hr) along the x-axis  404 . A curve for a warm fluid (about 900 psi) flowing through a heat exchanger is shown at  406 , a curve for a lower pressure (about 300 psi) cold fluid flowing through the heat exchanger is shown at  408 , and a curve for a higher pressure (about 775 psi) cold fluid flowing through the heat exchanger is shown at  410 . In T-Q charts such as chart  400 , the important factor is the gap between the warm fluid curve  406  and the cold fluid curves  408  or  410 . As shown, the gap between the warm fluid curve  406  and the high pressure cold fluid curve  410  maintains about a 5-10 degree difference through the charted temperature range of about −130° F. to about 130° F. This means that there is heat transfer between these two fluids, even at the higher pressures. There is a slightly higher rate of heat transfer between the warm fluid  406  and the lower pressure cold fluid  408  than between the warm fluid  406  and the high pressure cold fluid  410 , but for the purposes of the disclosure, the heat transfer is sufficient to meet the requirements of the process. 
     Beneficially, keeping the fluid at a higher pressure reduces or eliminates the need to repressurize the product gas for pipeline delivery, which eliminates a portion of the horsepower, footprint, and materials needed for compression of the lower pressure stream. This process efficiency more than makes up for the slight decrease in heat transfer efficiency shown by the T-Q chart  400 . 
     EXAMPLE 
     In one exemplary case, a natural gas feed stream having an assumed temperature, flow rate, pressure, and composition was provided. Table 1 below shows the temperature, flow rate, pressure, and composition of the relevant streams as shown in  FIGS. 1 and 3A . 
     
       
         
           
               
               
               
               
               
               
               
               
               
             
               
                 TABLE 1 
               
               
                   
               
               
                   
                 Stream 
                 Stream 
                 Stream 
                 Stream 
                 Stream 
                 Stream 
                 Stream 
                 Stream 
               
               
                 Component 
                 102 
                 122 
                 118 
                 106 
                 306 
                 112 
                 120 
                 312 
               
               
                   
               
             
            
               
                   
               
            
           
           
               
               
               
               
               
               
               
               
               
            
               
                 methane 
                 0.904 
                 0.775 
                 0.977 
                 0.904 
                 0.904 
                 0.965 
                 0.781 
                 0.773 
               
               
                 nitrogen 
                 0.093 
                 0.224 
                 0.020 
                 0.093 
                 0.093 
                 0.032 
                 0.219 
                 0.227 
               
               
                 ethane 
                 0.003 
                 0.001 
                 0.003 
                 0.003 
                 0.003 
                 0.003 
                 0.000 
                 0.000 
               
               
                 Total 
                 1.000 
                 1.000 
                 1.000 
                 1.000 
                 1.000 
                 1.000 
                 1.000 
                 1.000 
               
               
                 Pressure 
                 915 
                 275 
                 770 
                 905 
                 902 
                 285 
                 280 
                 300 
               
               
                 (psia) 
               
               
                 Temperature 
                 136 
                 130 
                 130 
                 −131 
                 −150 
                 −170 
                 −176 
                 −174 
               
               
                 (deg F.) 
               
               
                 Mscfd 
                 95 
                 34 
                 61 
                 95 
                 95 
                 77 
                 16 
                 18 
               
               
                   
               
            
           
         
       
     
     In particular, the exemplary flow rates illustrate the relative size of warmed nitrogen rich stream  122  as compared with the natural gas feed stream  102 . Beneficially, this results in a smaller volume of fluids going to the NRU  130  for further treatment, lowering the energy consumption, footprint, materials, and capital costs of such systems and methods as disclosed herein. It is also worth noting the difference in pressure between stream  112  and  118 . This pressure increase is preferably obtained through pumping stream  112  up to pressure rather than using compression equipment, which provides still more savings in energy use and equipment cost as well as potentially providing greater reliability. 
     While the present disclosure may be susceptible to various modifications and alternative forms, the exemplary embodiments discussed above have been shown only by way of example. However, it should again be understood that the disclosure is not intended to be limited to the particular embodiments disclosed herein. Indeed, the present disclosure includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.