Patent Publication Number: US-10760850-B2

Title: Gas liquefaction systems and methods

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims the benefit of priority to U.S. Provisional Application Ser. No. 62/291,868, filed on Feb. 5, 2016, and entitled “GAS LIQUEFACTION SYSTEM AND METHODS,” the content of which is incorporated by reference herein in its entirety. 
    
    
     BACKGROUND 
     Liquefying natural gas can facilitate transport and storage of hydrocarbons and related material. Generally, the processes greatly reduce the volume of gas. The resulting liquid is well-suited to transit long distances, for example, by rail and road transport tankers. It is particularly economical for transport overseas and/or to areas that are not accessible by such pipeline infrastructure. 
     SUMMARY 
     The subject matter of this disclosure relates generally to systems that can liquefy an incoming hydrocarbon stream. These systems can be configured to provide cooling, typically at a heat exchanger, to closely match the cooling curve for natural gas. In this way, the system can form a liquefied natural gas (LNG) product or stream. Some systems may provide refrigeration duty by circulating a refrigerant through the heat exchanger. This “refrigeration” process is often suited for small scale LNG facilities. On the other hand, the embodiments herein can be configured for an “expander” process that circulates fluid derived from the incoming natural gas to effectuate cooling at the heat exchanger. This feature can reduce costs and complexity of the liquefaction system. 
     Some embodiments can be configured to circulate the “derived” fluid at an intermediate pressure that is between the pressure of the incoming hydrocarbon stream and the pressure of a stream (e.g., boil off gas) that enters from a storage facility. This feature reduces the expansion ratio so as to provide sufficient refrigeration duty with a single methane expander to liquefy the incoming feedstock and other fluids to form the LNG product. These improvements can reduce the capital costs and operational complexity of the embodiments as compared necessary to perform the liquefaction process. 
     Some embodiments may find use in many different types of processing facilities. These facilities may be found onshore and/or offshore. In one application, the embodiments can incorporate into and/or as part of processing facilities that reside on land, typically on (or near) shore. These processing facilities can process natural gas feedstock from production facilitates found both onshore and offshore. Offshore production facilitates use pipelines to transport feedstock extracted from gas fields and/or gas-laden oil-rich fields, often from deep sea wells, to the processing facilitates. For LNG processing, the processing facility can turn the feedstock to liquid using suitably configured refrigeration equipment or “trains.” In other applications, the embodiments can incorporate into production facilities on board a ship (or like floating vessel), also known as a floating liquefied natural gas (FLNG) facility. 
     The subject matter herein may relate to subject matter found in U.S. Provisional Application Ser. No. 62/210,827, filed on Aug. 27, 2015, and entitled “SYSTEM AND PROCESS FOR PRODUCTION OF LIQUID NATURAL GAS,” and subject matter found in U.S. Ser. No. 14/985,490, filed on Dec. 31, 2015, and entitled “GAS LIQUEFACTION SYSTEM AND METHODS.” 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Reference is now made briefly to the accompanying drawings, in which: 
         FIG. 1  depicts a schematic diagram of an exemplary embodiment of a liquefaction system; 
         FIG. 2  depicts a schematic diagram of an example of components to implement the liquefaction system of  FIG. 1 ; 
         FIG. 3  depicts a schematic diagram of an example of components to implement the liquefaction system of  FIG. 1 ; 
         FIG. 4  depicts a schematic diagram of an example of components to implement the liquefaction system of  FIG. 1 ; 
         FIG. 5  depicts a schematic diagram of an example of a compression circuit for use in the liquefaction system of  FIGS. 1, 2, 3, and 4 ; 
         FIG. 6  depicts a schematic diagram of an example of a compression circuit for use in the liquefaction system of  FIGS. 1, 2, 3, and 4 ; and 
         FIG. 7  depicts a flow diagram of an exemplary embodiment of a liquefaction process. 
     
    
    
     Where applicable like reference characters designate identical or corresponding components and units throughout the several views, which are not to scale unless otherwise indicated. The embodiments disclosed herein may include elements that appear in one or more of the several views or in combinations of the several views. Moreover, methods are exemplary only and may be modified by, for example, reordering, adding, removing, and/or altering the individual stages. 
     DETAILED DESCRIPTION 
     The discussion below describes various embodiments that are useful to process hydrocarbons for storage as liquid natural gas (LNG). These embodiments include a fluid circuit that flashes and then cools the circulating hydrocarbon stream at an intermediate pressure between the “high” pressure of an incoming hydrocarbon feedstock and the “low” pressure of a boil-off gas that originates from a storage facility. Other embodiments are within the scope of the disclosed subject matter. 
       FIG. 1  illustrates a schematic diagram of an exemplary embodiment of a liquefaction system  100  (also, “system  100 ”) for use to liquefy a hydrocarbon stream. At a high level, the system  100  can have a fluid circuit  102  that receives a feedstock  104  from a source  106 . Incoming feedstock  104  may be in vapor form (also, “gas” or “natural gas”) with a composition that is predominantly methane. Embodiments of the system  100  may be compatible with compositions having methane in a first concentration that is approximately 93% (930,000 ppmV) or greater. In use, the system  100  can form one or more products (e.g., a first product  108 ), typically liquid natural gas (LNG) that meets specifications that define parameters (e.g., temperature, pressure, composition, etc.) for storage. These specifications may specify a second concentration of methane for the LNG product  108  that is lower than the first concentration of incoming feedstock  104 . In one example, the second concentration of methane in the first product  108  for may be approximately 99% or more (990,000 ppmV). The fluid circuit  102  can distribute the LNG product  108  to a storage facility  110  and/or other collateral process equipment. 
     The fluid circuit  102  may be configured to form and circulate fluids (e.g., gasses and liquids). For clarity, these fluids are identified in  FIG. 1  as a process stream  112 . In one implementation, the fluid circuit  102  may include a first heat exchanger  114  (also, “main heat exchanger  114 ”). Examples of the main heat exchanger  114  can have multiple passes, each in the form of a passage that may include brazed aluminum fins (“plate-fin exchanger”) and/or tubular coils (“coil wound exchanger”). Such configurations can facilitate indirect exchange of thermal energy among the fluids that pass through the main heat exchanger  114 . The passages can couple with or more processing units to exchange the process stream  112  at various temperatures. Examples of the process stream  112  can be in vapor, liquid, and mixed-phase forms. However, in one implementation, the fluid circuit  102  may be configured to maintain the process stream  112  in a single phase, either vapor phase or liquid phase. The processing units can be arranged as a sub-cooling unit  116 , a compression unit  118 , and methane expander  120 . 
       FIG. 2  illustrates an example of components to implement the liquefaction system  100  that renders the LNG product  108  from incoming feedstock  104 . At the sub-cooling unit  116 , the fluid circuit  102  can have a first vessel  122  that couples with a second heat exchanger  124 . Examples of the second heat exchanger  124  can form three passes, although fewer or more passes may be useful in certain implementations of the system  100 . The fluid circuit  102  can form a fluid path  126  that couples the passes of the second heat exchanger  124  together. In the compression unit  118 , the fluid circuit  102  can incorporate one or more compression circuits (e.g., a first compression circuit  128  and a second compression circuit  130 ), referred to collectively as the “recycle gas compression circuit.” The first compression circuit  128  can couple with the sub-cooling unit  116  via the main heat exchanger  114 . The methane expander  120  can be part of an open loop circuit or “recycle gas circuit” that provides the primary refrigeration at the main heat exchanger  114 . This recycle gas circuit can include a turbo-machine  132 , preferably having a turbo-compressor  134  that is configured to operate in response to work from a turbo-expander  136 . The turbo-machine  132  can have a pair of inlets (e.g., a first inlet  138  and a second inlet  140 ) and a pair of outlets (e.g., a first outlet  142  and a second outlet  144 ). The inlets  138 ,  140  and the outlets  142 ,  144  couple the turbo-machine  132  with the main heat exchanger  114  and the first compression circuit  128 . including first outlet  142  connected through fluid circuit  102  to compression circuit inlet  121  and compression circuit outlet  123  is connected through fluid circuit  102  to second inlet  140 . 
     The fluid circuit  102  may benefit from one or more auxiliary or peripheral components that can facilitate processes to generate the LNG product  108 . For example, the fluid circuit  102  may include one or more throttling devices  146 . Examples of the throttling devices  146  can include valves (e.g., Joule-Thompson valves) and/or devices that are similarly situated to throttle the flow the process stream  112  ( FIG. 1 ). In use, the throttling devices  146  can be interposed between components in the fluid circuit  102  as necessary to achieve certain changes in fluid parameters (e.g., temperature, pressure, etc.). 
     The compression circuits  128 ,  130  can have one or more compression stages. Two or three stages may be appropriate for many applications. The compression stages of the second compression circuit  130  may be independent or separate from the compression stages of the first compression circuit  128 . This discussion does also contemplates applications for the system  100  that may benefit from combinations of the stages of compression circuits  128 ,  130 , in whole or in part. 
     Starting at the left side of the diagram in  FIG. 2 , the fluid circuit  102  can direct the process stream  112  ( FIG. 1 ) through the various components to generate the LNG product  108 . In one implementation, incoming feedstock  104  can enter a first pass of the main heat exchanger  114  at a first pressure and a first temperature, typically ambient temperature that prevails at the system  100  and/or the surrounding facility. The first pressure may depend on operation of the facility and/or installation. Exemplary pressure may be approximately 700 psig. But this disclosure contemplates that the embodiments can be tuned to accommodate pressure in a range of approximately 400 psig to approximately 1200 psig. Incoming feedstock  104  exits the device (at  148 ) at a second temperature in a range from approximately −140° F. to approximately −170° F. 
     The fluid circuit  102  can direct the cooled fluid stream  148  to a first throttling device  146 A (e.g., throttling device  146 ). This first throttling device  146 A “flashes” the cooled fluid stream  148  upstream of the first vessel  122 , effectively reducing the pressure from the first pressure to the intermediate pressure mentioned above. This intermediate pressure may correspond with suction pressure for one or more of the stages of the compression circuits  128 ,  130 . In one example, the intermediate pressure is at or slightly above (e.g., within 10%) of suction pressure for the first compression stage of the second compression circuit  130 . Flashing at this intermediate pressure is beneficial to simplify construction of the system  100 . In one implementation, the cooled fluid stream  148  may exit the first throttling device (at  150 ) so that the intermediate pressure is less than the first pressure, for example, in a range of approximately 200 psig to approximately 250 psig and at a temperature from approximately −170° F. to approximately −200° F. 
     The fluid circuit  102  can direct the flashed stream  150  at the reduced pressure and, where applicable, reduced temperature to the first vessel  122 . Processes in the first vessel  122  may separate flashed stream  150  at the intermediate pressure (and in mixed-phase form) into a top product  125  and a bottom product  127 , one each in vapor form and liquid form, respectively. In one implementation, the fluid circuit  102  can direct the liquid bottom product  127  to a first pass of the second heat exchanger  124 . This first pass further reduces the temperature of the liquid bottom product  127  so that the liquid bottom product is at (or near) the storage pressure of the storage tank at the storage facility  110 . Typical “storage” pressure for the system  100  may be approximately 28 psig. But such values may depend on specifications at the storage facility  110  that can call for “storage” pressure from approximately 1 psig (or “unpressurized”) to approximately 30 psig (“pressurized”) or more. In one implementation, the liquid bottom product  127  exits the first pass of the second heat exchanger  124  in a range from approximately −245° F. to approximately −260° F. 
     The fluid circuit  102  can split the liquid bottom product into one or more portions downstream of the second heat exchanger  124 . The fluid circuit  102  can direct a first portion as the LNG product  108  for storage in the storage facility  110 . The fluid circuit  102  can direct a second portion  129 , or “slip stream,” back to a second pass of the second heat exchanger  124  via the fluid path  126 . In one implementation, the fluid circuit  102  may include a second throttling device  146 B (e.g., throttling device  146 ) interposed between the first pass and the second pass of the second heat exchanger  124 . This second throttling device can be configured to flash the slip stream so that the slip stream exits the device (at  154 ) at a pressure that is below the “storage” pressure. This pressure can be a range of approximately 25 psig to approximately 10 psig. 
     The fluid circuit  102  can also couple the sub-cooling unit  116  with the storage facility  110 . This configuration can direct a stream  156  to a third pass of the second heat exchanger  124 . Examples of the stream  156  can include boil-off vapor from a storage tank at the storage facility  110 , although the vapor may result from processing of fluids that occur at the storage facility  110 . 
     The second pass and the third pass are useful to sub-cool the slip stream  154  and boil-off stream  156 . During operation, and as noted above, each of the slip stream  154  and the boil-off stream  156  can be conditioned upstream of the second heat exchanger  124  to pressure below the “storage” pressure, e.g., of the storage tank at the storage facility  110 . The slip stream  154  may exit the second pass of the second heat exchanger  124  as vapor (at  158 ) at a temperature from approximately −175° F. to approximately −190° F. The boil-off stream  156  may exit the third pass of the heat exchanger  124  (at  160 ) at a temperature of from approximately −175° F. to approximately −190° F. This fluid circuit  102  can be configured to combine the stream  158  and the stream  160  downstream of the second heat exchanger  124  and upstream of main heat exchanger  114 . This combined vapor stream  158 ,  160  can provide additional cooling at the main heat exchanger  114 , as noted more below. 
     The fluid circuit  102  can direct the vapor top product  125  stream from the first vessel  122  and the combined vapor stream  158 ,  160  from the second heat exchanger  124  to the compression unit  118 . Preferably, these streams flow through separate passes of the main heat exchanger  114 . In one implementation, the vapor top product  125  stream from the first vessel  122  enters a second pass of the main heat exchanger  114 . This stream may be useful to provide some of the cooling duty at the main heat exchanger  114 . The combined vapor stream  158 ,  160  from the second heat exchanger  124  enters a third pass of the main heat exchanger  114 . Each of the second pass and the third pass warms the respective stream so that the streams exit the heat exchanger  114  (at  162 ,  164 ) at a temperature from approximately 90° F. to approximately 120° F. 
     The fluid circuit  102  can couple the passes of the main heat exchanger  114  with different locations of the first compression circuit  128 . This configuration uses the stream  164  (formed by the combined vapor stream  158 ,  160 ) as make-up for the compression circuits  128 ,  130 . In one implementation, the fluid circuit  102  can direct the stream  164  from the third pass to a first location that is upstream of each of the compression stages (e.g., of the first compression circuit  128 ). Vapor stream  162  from the second pass can enter at a second location, preferably at an intermediate compression stage of the recycle gas compression circuit and, in one example, downstream of each of the compressions stages of the first compression circuit  128 . In one implementation, the first compression circuit  128  can be configured so that a vapor stream exits the last of the compression stages (at  166 ) at a pressure from approximately 200 psig to approximately 250 psig. This pressure may serve as the suction pressure for the second compression circuit  130 . The fluid circuit  102  can direct the vapor stream  166  at this pressure to the second compression circuit  130 . This configuration is effective to compress the vapor stream  166  so as to exit the second compression circuit  130  (at  168 ) at its maximum pressure. In one implementation, the maximum pressure of the vapor stream  168  is approximately 1200 psig and, in one example, from approximately 1000 psig to approximately 1200 psig. 
     The recycle gas compression circuit can embody an open loop circuit. This type of circuit can bleed-off a portion of the compressed vapor stream  168  that exits the second compression circuit  130 . This portion finds use as the primary cooling stream for the main heat exchanger  114 . During operation, bleed-off may occur after the circuit builds up from continuous feed from the first vessel  122 , the second heat exchanger  124 , and discharge from the turbo-compressor  134 . In one implementation, the fluid circuit  102  can be configured to split the compressed vapor stream  168  to form one or more portions upstream of the main heat exchanger  114 . The first portion can exit a fourth pass (at  170 ) as liquid at a temperature of from approximately −140° F. to approximately −170° F. The fluid circuit  102  can direct the first portion  170  from the fourth pass to the first throttling device  146 . The first portion  170  may exit the first throttling device  146 A (at  172 ) at the same pressure that the cooled fluid stream  148  exits the first throttling device  146 A (at  150 ), preferably from approximately 200 psig to approximately 250 psig. The fluid circuit  102  can, in turn, combine these two flashed streams  150 ,  172  upstream of the first vessel  122  to form a mixed stream  173  that is fed into first vessel  122 . 
     The second portion forms the primary cooling stream of the recycle gas circuit. As shown in  FIG. 2 , this second portion can exit a fifth pass (at  174 ) at a temperature of from approximately 20° F. to approximately 0° F. and, in one example, at approximately 13° F. and. The fluid circuit  102  can direct the cooled second portion  174  from the fifth pass to the inlet  140  of the turbo-expander  136 . In one implementation, the turbo-expander  136  can be configured to decrease the pressure of the cooled second portion  174 . This apparatus may operate so that the vapor stream exits the turbo-expander  136  (at  176 ) at a pressure from approximately 110 psig to approximately 130 psig and, in one example, the pressure is approximately 116 psig. Expansion at the turbo-expander  136  can result in the expanded vapor stream  176  having a temperature of −116° F., but this temperature can vary from approximately −180° F. to approximately −150° F. The fluid circuit  102  can direct the expanded vapor stream  176  to a sixth pass of the main heat exchanger  114 . As noted above, flow of the expanded vapor stream  176  through this sixth pass can provide the primary refrigeration for the main heat exchanger  114 . The expanded vapor stream can exit the sixth pass (at  178 ) at a temperature from approximately 90° F. to approximately 120° F. As shown in  FIG. 2 , the fluid circuit  102  can direct the resulting liquid stream  178  from the sixth pass to the inlet  138  of the turbo-compressor  134 , which compresses the incoming fluid. In one implementation, the liquid stream  178  may exit the turbo-compressor  134  (at  180 ) at a pressure from approximately 200 psig to approximately 300 psig. The fluid circuit  102  can be configured to return the stream  180  to the second location on the compression unit  118 . 
       FIG. 3  depicts an example of additional components that may be helpful to implement the liquefaction system  100 . The fluid circuit  102  may include a cooler  182  interposed between the first compression circuit  128  and the turbo-compressor  134 . The fluid circuit  102  may also include a separation unit  184  to remove impurities (e.g., heavy hydrocarbons) from incoming feedstock  104 . Examples of the separation unit  184  may include a pair of vessels (e.g., a second vessel  186  and a third vessel  188 ). Processes that occur at the vessels  186 ,  188  can form a top product and a bottom product in vapor form and liquid form, respectively. The third vessel  188  may also benefit from use of one or more peripheral components (e.g., a peripheral component  190 ). Examples of the peripheral component  190  can include pumps, boilers, heaters, and like devices that can facilitate operation of one or more of the vessels  186 ,  188 . In one implementation, the peripheral component  190  may embody a boiler that couples the third vessel  186  with a pipeline  192  and/or like collateral equipment (e.g., conduit, tank, etc.). 
     The fluid circuit  102  may be configured with the cooler  182  between the second location on the compression circuits  128 ,  130  and the turbo-compressor  134 . This configuration is useful to cool the stream  180  that exits the turbo-compressor  134 . In one implementation, the stream  180  exist the cooler  182  so as to enter the second location of the compression unit  118  at a temperature of approximately 111° F. However, this temperature may vary within in a range from approximately 90° F. to approximately 120° F. 
     The fluid circuit  102  may be configured to couple the main heat exchanger  114  with the separation unit  184 . This configuration can direct the stream  148  from the first pass to the second vessel  186 . Depending on the composition of incoming feedstock  104  (and, correspondingly, the stream  148 ), the second vessel  186  can operate at pressure that is less than 700 psig, although this operating pressure can vary in a range of from approximately 600 psig to approximately 800 psig. In one implementation, the second vessel  186  operates at parameters (e.g., temperature, pressure, etc.) so that the vapor top product meets specifications that define the composition of the LNG product  108 . 
     The fluid circuit  102  can direct the liquid bottom product from the second vessel  186  to the third vessel  188 . Examples of the third vessel  188  can operate as a stabilizer column to remove light hydrocarbons to form a liquid bottom product that is “stable” for storage. This liquid bottom product may be a liquid petroleum (LPG) product stabilized at propane vapor pressure. Operating parameters for the third vessel  188  may designate a pressure equal to or slightly above the operating pressure of the first vessel  122 . A third throttling device  146 C (e.g., throttling device  146 ) may be useful to reduce the pressure and/or temperature of the liquid bottom product upstream of the third vessel  188 . In one implementation, the third vessel  188  operates at parameters (e.g., temperature, pressure, etc.) so that the vapor top product meets specifications that define the composition of the LNG product  108 . The liquid bottom product can exit the third throttling device  146  (at  194 ) at a pressure from approximately 200 psig to approximately 300 psig and a temperature of from approximately −90° F. to approximately −120° F. The fluid circuit  102  can be configured to direct the vapor top product from the stabilizer column  188  to the first vessel  122 . 
     The stabilizer column  188  can be fabricated from standard pipe size and schedule for use with a wide range of output rates. In one example, the stabilizer column can use twelve trays so that the top vapor product meets specifications for the LNG product  108 . The fluid circuit  102  may include a condenser, but such configuration may not be necessary because the incoming feedstock  110  may enter the stabilizer column at less than approximately −100° F. and the vapor top product may exit the stabilizer column at −30° F. or warmer. The boiler  190  can use either hot oil or electricity to generate heat. For small re-boiler loads, an electric re-boiler may be cost effective for this purpose. 
     As noted above, the vapor top products from the vessels  186 ,  188  can have a composition that meets specifications that define the composition for the LNG product  108 . The vapor top product from the stabilizer column  188  may enter the second vessel  122 . The fluid circuit  102  can direct the vapor top product from the second vessel  186  to the main heat exchanger  114 . In one implementation, the vapor top product from the second vessel  186  exits (at  196 ) a seventh pass as a liquid at a temperature in a range from approximately −175° F. to approximately −190° F. 
       FIG. 4  depicts an example of the system  100  with components that might be useful to condition the LNG product  108 , the boil-off vapor  156 , and the LPG product. One or more of these components may be part of the fluid circuit  102  or found separately as part of, for example, the storage facility  110 , processing facility, and the like. The components may include additional throttling devices  146 D and  146 E (e.g., throttling device  146 ) and coolers, although this disclosure does not require nor foreclose other devices that may be useful to condition fluids as contemplated herein. For example, a fourth throttling device may reduce the pressure of the LNG product  108  downstream of the second heat exchanger  124  and upstream of the storage facility  110 . A fifth throttling device may be used to condition the boil-off vapor  156  to a pressure approximately equal to the pressure of the slip stream (discussed above in connection with the sub-cooling unit  116 ). In one example, a cooler  198  and a sixth throttling device may condition the LPG product downstream of the stabilizer column  188 . 
       FIG. 5  depicts an example of a compression circuit  200 . This example may find use to implement the compression circuit  128  ( FIGS. 2, 3, and 4 ). The compression circuit  200  has a first end  202  and a second end  204 . The first end  202  can couple with the main heat exchanger  114 , preferably to the third pass to receive the combined vapor stream that may originate from the sub-cooling unit  116 . The second end  204  may couple with the second compression unit  130 , with the main heat exchanger  114 , as well as with the turbo-compressor  134  via, in one example, the cooler  182 . 
     The compression circuit  200  may be configured to increase the pressure without increasing the temperature of the process stream  112  ( FIG. 1 ) from the first end  202  to the second end  204 . This functionality may be embodied in various components (e.g., coolers, compressors, etc.). In one implementation, the compression circuit  200  may include a first compression vessel  206  at the first end  202  (or “inlet”). Examples of the vessel  206  can embody a desuperheater or like device to reduce the temperature of incoming gas to make it less superheated. This device can couple with a compression path  208  that has one or more compression stages (e.g., a first stage  210 , a second stage  212 , and a third stage  214 ). The compression path  208  may include one or more compression vessels (e.g., a second compression vessel  216  and a third compression vessel  218 ) interposed between the stages  210 ,  212 . Nominally, each stage may include a cooler  220  and a compressor  222 . Examples of the cooler  220  may be air-cooled, although this disclosure does not limit selection to any particular type or variation for these devices. The compressor  222  may be gas, motor, and turbine driven devices that can maintain and/or raise the pressure of process stream  112  ( FIG. 1 ) noted herein. At the second end  204 , the compression path  208  may include a fourth compression vessel  224 . This device can receive the compressed stream from the third stage  220 . In one implementation, the fourth compression vessel  224  can also receive each of the vapor top product from the first vessel  122  ( FIGS. 2, 3, and 4 ) and the compressed vapor stream from the turbo-compressor  134  ( FIGS. 2, 3, and 4 ). The compression circuit  200  can deliver the vapor top product from the fourth compression vessel  224  to the second compression circuit  130 . 
       FIG. 6  depicts an example of a compression circuit  300 . This example may find use to implement the compression circuit  130  ( FIGS. 2, 3, and 4 ). The first end  302  can couple with the first compression circuit  128 ; as noted above, the compression circuit  118  may be configured to direct the vapor top product from the fourth compression vessel  224  to the first stage  310 . At the second end  302 , the compression circuit  300  can couple with the main heat exchanger  114 , preferably to the fourth pass to deliver compressed vapor stream to the first throttling device. 
       FIG. 7  depicts an example of a process  400  to liquefy an incoming natural gas stream. The process  400  may leverage the structure discussed above in whole or in part. In one implementation, the process  400  may include, at stage  402 , flashing a vapor stream derived from an incoming feedstock  104  to a mixed-phase stream  173  at a first pressure and, at stage  404 , separating the mixed-phase stream  173  into a first stream  125  and a second stream  127 . The process  400  may also include, at stage  406 , passing the second stream  127  though a heat exchanger and, at stage  408 , directing a first portion  108  of the second stream to form a liquid natural gas (LNG) product. The process  400  may include, at stage  410 , flashing the second portion  129  to a second pressure that is lower that the first pressure. As noted herein, this second pressure may correspond with storage pressure of boil-off gas from a storage facility so that the process  400  may include, at stage  412 , mixing the second portion  129  with boil-off gas  156  that exits the heat exchanger. In one implementation, the process  400  may include, at stage  414 , compressing the mixed stream  164  in a compression circuit  118  from the second pressure to a third pressure. This stage may include, at stage  416 , compressing the mixed stream  164  through a first compression circuit  128  from the second pressure to a suction pressure and, at stage  418 , compressing the mixed stream through a second compression circuit  130  from the suction pressure to the third pressure. The process  400  may further include, at stage  420 , expanding the mixed stream  136  from the third pressure to the first pressure and, at stage  422 , re-introducing the mixed stream  180  at the first pressure into the compression circuit  118 . In one implementation, the process  400  may include, at stage  424 , bleeding off part of the mixed stream  168  at the third pressure, at stage  426 , flashing the part  170  to the first pressure, and at stage  428 , mixing the part  172  with  150  to form the mixed phase stream  173  at the first pressure before separating the mixed-phase stream into the first stream  125  and the second stream  127  (at stage  404 ). Further, the process  400  may include, at stage  430 , separating the incoming feed stock  184  into the vapor stream and a liquid petroleum (LPG) product prior to flashing (at stage  402 ). 
     As used herein, an element or function recited in the singular and proceeded with the word “a” or “an” should be understood as not excluding plural said elements or functions, unless such exclusion is explicitly recited. Furthermore, references to “one embodiment” of the claimed invention should not be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. 
     This written description uses examples to disclose the embodiments, including the best mode, and also to enable any person skilled in the art to practice the embodiments, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the embodiments is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal language of the claims. 
     In view of the foregoing, some embodiments exhibit process efficiency that compares favorably with a nitrogen expander process but require more horsepower than an equivalent sized mixed refrigerant system as well as pressurized storage. Some embodiments require only a single expander to achieve these improvements. This requirement compares favorably with systems that employ two expanders that work in parallel. Moreover, unlike systems that implement mixed-refrigeration processes, some embodiments do not require refrigerants, thus eliminating the need for use, handling, and on-site storage of refrigerants. In this regard, the examples below include certain elements or clauses one or more of which may be combined with other elements and clauses describe embodiments contemplated within the scope and spirit of this disclosure.