Patent Publication Number: US-9835373-B2

Title: Integrated cascade process for vaporization and recovery of residual LNG in a floating tank application

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a non-provisional application which claims benefit under 35 USC §119(e) to U.S. Provisional Application Ser. No. 61/835,770 filed Jun. 17, 2013, entitled “INTEGRATED CASCADE PROCESS FOR VAPORIZATION AND RECOVERY OF RESIDUAL LNG IN A FLOATING TANK APPLICATION,” which is incorporated herein in its entirety. 
    
    
     FIELD OF THE INVENTION 
     The present invention relates generally to liquefaction of natural gas and, more particularly, to vaporizing and recovering liquefied natural gas in an offshore liquefaction facility. 
     BACKGROUND OF THE INVENTION 
     Natural gas is an important resource widely used as energy source or as industrial feedstock used in, for example, manufacture of plastics. Comprising primarily of methane, natural gas is a mixture of naturally occurring hydrocarbon gases and is typically found in deep underground natural rock formations or other hydrocarbon reservoirs. Other components of natural gas include, but are not limited to, ethane, propane, carbon dioxide, nitrogen, and hydrogen sulfide. 
     Typically, natural gas is transported from source to consumers through pipelines that physically connect a reservoir to a market. Because natural gas is sometimes found in remote areas devoid of necessary infrastructure (i.e., pipelines), alternative methods for transporting natural gas must be used. This situation commonly arises when the source of natural gas and the market are separated by great distances, for example a large body of water. Bringing this natural gas from remote areas to market can have significant commercial value if the cost of transporting natural gas is minimized. 
     One alternative method of transporting natural gas involves converting natural gas into a liquefied form through a liquefaction process. Because natural gas exists in vapor phase under standard atmospheric conditions, it must be subjected to certain thermodynamic processes in order to be liquefied to produce liquefied natural gas (LNG). In its liquefied form, natural gas has a specific volume that is significantly lower than its specific volume in its vapor form. Thus, the liquefaction process greatly increases the ease of transporting and storing natural gas, particularly in cases where pipelines are not available. For example, ocean liners carrying LNG tanks can effectively link a natural gas source with a distant market when the source and market are separated by large bodies of water. 
     Converting natural gas to its liquefied form can have other economic benefits. For example, storing LNG can help balance out periodic fluctuations in natural gas supply and demand. In particular, LNG can be more easily “stockpiled” for later use when natural gas demand is low and/or supply is high. As a result, future demand peaks can be met with LNG from storage, which can be vaporized as demand requires. 
     In order to store and transport natural gas in the liquid state, the natural gas is typically cooled to −160° C. at near-atmospheric vapor pressure. Liquefaction of natural gas can be achieved by sequentially passing the gas at an elevated pressure through a plurality of cooling stages whereupon the gas is cooled to successively lower temperatures until the liquefaction temperature is reached. Cooling is generally accomplished by indirect heat exchange with one or more refrigerants such as propane, propylene, ethane, ethylene, methane, nitrogen, carbon dioxide, or combinations of the preceding refrigerants (e.g., mixed refrigerant systems). 
     There are growing efforts to develop floating liquefied natural gas (FLNG) technologies that would enable operations of water-based LNG processing facilities. Such a facility could float above an offshore natural gas field, where it can produce, liquefy, store and transfer LNG at sea before shipping the LNG directly to markets. 
     Various aspects of the floating facility will be subjected to inspection (e.g., checking for inner tank leakage, effectiveness of insulation, etc.) and/or maintenance, which may require physical entry into FLNG LNG storage tanks. Before physical entry is possible, LNG cargo stored in the storage tanks need to be vaporized and recovered after inspection and/or maintenance. While conventional methods for vaporizing and evacuating LNG from LNG storage tanks exist, there may be additional technical challenges to removing residual LNG from FLNG LNG storage tanks due to limited space constraints. Moreover, some conventional methods of LNG do not recover vaporized LNG. 
     BRIEF SUMMARY OF THE DISCLOSURE 
     The present invention relates generally to liquefaction of natural gas and, in particular, to vaporizing and recovering liquefied natural gas in an offshore liquefaction facility. 
     One example of a method for vaporizing liquefied natural gas (LNG) produced from a main liquefaction process and stored in an LNG storage tank comprises: a) heating at least a portion of the LNG to provide a boil-off gas stream and a liquid quench stream; b) routing the boil-off gas stream and the liquid quench stream to a quench system, wherein the quench system cools the boil-off gas stream to provide a quenched stream; and c) compressing the quenched stream to provide a compressed quenched stream. 
     Another example of a method for vaporizing liquefied natural gas (LNG) produced from a main liquefaction process and stored in an LNG storage tank comprises: a) heating via a warm predominantly methane stream at least a portion of the LNG to provide a boil-off gas stream and a liquid quench stream; b) routing the boil-off gas stream and the liquid quench stream to a quench system, wherein the quench system cools the boil-off gas stream to provide a quenched stream; and c) compressing the quenched stream to provide a compressed quenched stream. 
     An example of a system for vaporizing liquefied natural gas (LNG) comprises: at least one LNG storage tank for storing cryogenic materials; a quench system located downstream of the at least one LNG storage tank for cooling boil-off gas produced from the at least one LNG storage tank, the quench system comprising at least two conduits, wherein a first conduit allows transport of boil-off gas from the at least one LNG storage tank to the quench system and a second conduit allows transport of liquid quench stream from the at least one LNG storage tank to the quench system; and a compressor located downstream of the quench system, wherein the compressor is configured to compress a stream exiting from the quench system. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       A more complete understanding of the present invention and benefits thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings in which: 
         FIG. 1  is a simplified flow diagram of a cascade refrigeration process for LNG production compatible with a vaporization and recovery system according to one or more embodiments. 
         FIG. 2A  is a flow diagram of a vaporization and recovery system according to one or more embodiments operating in an open mode. 
         FIG. 2B  is a flow diagram of a vaporization and recovery system according to one or more embodiments operating in a closed mode. 
     
    
    
     DETAILED DESCRIPTION 
     The present invention provides systems and methods for vaporizing and recovering residual LNG found in LNG storage tanks LNG storage tanks are specialized insulated cryogenic containers used to store LNG. While LNG storage tanks are typically installed in or above ground, they may also be installed on offshore LNG vessel. An LNG storage tank installed on an offshore vessel will be referred herein as “FLNG LNG storage tank.” 
     While LNG is generally considered safe (e.g., LNG is not explosive as a liquid), periodic inspection of LNG facilities is recommended and/or required. Safety inspection of LNG storage tanks is often carried out within 5 years after date of built or after the crediting date of a previous inspection in accordance with rules or requirements of a governing authority (e.g., Classification Society). Before these inspections can take place, LNG stored in the LNG storage tank must be evacuated. Typically, last few feet of LNG residing from the heel of the storage tanks (“residual LNG”) are most difficult to vaporize and evacuate. While the LNG storage tank undergoing inspection and/or maintenance should be in a gas-free or substantially gas-free condition, costs associated with inspection/maintenance may be minimized if other LNG storage tanks remain under operation. This may be achieved by segregating the evacuated LNG storage tank from cargo production/offloading lines. Once the LNG storage tanks are de-commissioned, inspection and/or maintenance of the LNG storage tanks may be performed. The present invention can significantly minimize time required to vaporize and evacuate LNG prior to inspection and/or maintenance. Moreover, LNG vaporized from the LNG storage tank may be recovered to a main liquefaction process (i.e., LNG producing process). This process of vaporization and recovery may reduce flaring. Other advantages will be apparent from the disclosure herein. 
     The present invention can be implemented or otherwise integrated with an LNG facility used to cool natural gas to its liquefaction temperature to produce liquefied natural gas. The LNG facility generally employs one or more refrigerants to extract heat from the natural gas and reject to the environment. Numerous configurations of LNG systems exist and the present invention may be implemented in many different types of LNG systems. The present invention may be integrated with one or more existing LNG processes (including cascade processes) and may be compatible with future LNG processes (including FLNG processes and facilities), which reduces capital equipment required. As used herein, “vaporization and recovery system” refer to those features and equipment primarily involved in the vaporization and recovery of the residual LNG. 
     In one embodiment, the present invention may be implemented in a mixed refrigerant LNG system. Examples of mixed refrigerant processes can include, but are not limited to, a single refrigeration system using a mixed refrigerant, a propane pre-cooled mixed refrigerant system, and a dual mixed refrigerant system. 
     In another embodiment, the present invention may be implemented in a cascade LNG system employing a cascade-type refrigeration process using one or more predominately pure component refrigerants. The refrigerants utilized in cascade-type refrigeration processes can have successively lower boiling points in order to facilitate heat removal from the natural gas stream being liquefied. Additionally, cascade-type refrigeration processes can include some level of heat integration. For example, a cascade-type refrigeration process can cool one or more refrigerants having a higher volatility through indirect heat exchange with one or more refrigerants having a lower volatility. In addition to cooling the natural gas stream through indirect heat exchange with one or more refrigerants, cascade and mixed-refrigerant LNG systems can employ one or more expansion cooling stages to simultaneously cool the LNG while reducing its pressure. 
     Cascade LNG Process 
     In one embodiment, the LNG process may employ a cascade-type refrigeration process that uses a plurality of multi-stage cooling cycles, each employing a different refrigerant composition, to sequentially cool the natural gas stream to lower and lower temperatures. For example, a first refrigerant may be used to cool a first refrigeration cycle. A second refrigerant may be used to cool a second refrigeration cycle. A third refrigerant may be used to cool a third refrigeration cycle. Each refrigeration cycle may consider a closed cycle or an open cycle. The terms “first”, “second”, and “third” refer to the relative position of a refrigeration cycle. For example, the first refrigeration cycle is positioned just upstream of the second refrigeration cycle while the second refrigeration cycle is positioned upstream of the third refrigeration cycle and so forth. While at least one reference to a cascade LNG process comprising 3 different refrigerants in 3 separate refrigeration cycles is made, this is not intended to be limiting. It is recognized that a cascade LNG process involving any number of refrigerants and/or refrigeration cycles may be compatible with one or more embodiments of the present invention. Other variations to the cascade LNG process may also be contemplated. In another embodiment, the mixed-reflux heavies removal system of the present invention may be utilized in non-cascade LNG processes. One example of a non-cascade LNG process involves a mixed refrigerant LNG process that employs a combination of two or more refrigerants to cool the natural gas stream in at least one cooling cycle. 
     Referring first to  FIG. 1 , an example cascade LNG facility in accordance with the concept described herein is illustrated. The LNG facility depicted in  FIG. 1  generally comprises a propane refrigeration cycle  30 , an ethylene refrigeration cycle  50 , and a methane refrigeration cycle  70  with an expansion section  80 .  FIGS. 2A and 2B  illustrate embodiments of vaporization and recovery system that may be integrated with LNG producing facility (e.g., facility shown in  FIG. 1 ). More specifically,  FIG. 2A  illustrates an open operation mode (“open mode”) in which vaporization and recovery of residual LNG is achieved while the vaporization and recovery system is open to the main liquefaction process (e.g., process shown in  FIG. 1 ).  FIG. 2B  illustrates a closed operation mode (“closed mode”) in which vaporization and recovery of residual LNG is achieved while the vaporization and recovery system is closed to the main liquefaction process. Those skilled in the art will recognize that  FIGS. 1-2B  are schematics only and, therefore, many items of equipment that would be needed in a commercial plant for successful operation have been omitted for sake of clarity. Such items might include, for example, compressor controls, flow and level measurements and corresponding controllers, temperature and pressure controls, pumps, motors, filters, additional heat exchangers, valves, and the like. These items would be provided in accordance with standard engineering practice. 
     While “propane,” “ethylene,” and “methane” are used to refer to respective first, second, and third refrigerants, it should be understood that the embodiment illustrated in  FIG. 1  and described herein can apply to any combination of suitable refrigerants. The main components of propane refrigeration cycle  30  include a propane compressor  31 , a propane cooler/condenser  32 , high-stage propane chillers  33 A and  33 B, an intermediate-stage propane chiller  34 , and a low-stage propane chiller  35 . The main components of ethylene refrigeration cycle  50  include an ethylene compressor  51 , an ethylene cooler  52 , a high-stage ethylene chiller  53 , a low-stage ethylene chiller/condenser  55 , and an ethylene economizer  56 . The main components of methane refrigeration cycle  70  include a methane compressor  71 , a methane cooler  72 , and a methane economizer  73 . The main components of expansion section  80  include a high-stage methane expansion valve and/or expander  81 , a high-stage methane flash drum  82 , an intermediate-stage methane expansion valve and/or expander  83 , an intermediate-stage methane flash drum  84 , a low-stage methane expansion valve and/or expander  85 , and a low-stage methane flash drum  86 . 
     The operation of the LNG facility illustrated in  FIG. 1  will now be described in more detail, beginning with propane refrigeration cycle  30 . Propane is compressed in multi-stage (e.g., three-stage) propane compressor  31  driven by, for example, a gas turbine driver (not illustrated). The stages of compression may exist in a single unit or two or more separate units mechanically coupled to a single driver. Upon compression, the propane is passed through conduit  300  to propane cooler  32  where it is cooled and liquefied through indirect heat exchange with an external fluid (e.g., air or water). A portion of the stream from propane cooler  32  can then be passed through conduits  302  and  302 A to a pressure reduction means, illustrated as expansion valve  36 A, wherein the pressure of the liquefied propane is reduced, thereby evaporating or flashing a portion thereof. The resulting two-phase stream then flows through conduit  304   a  into high-stage propane chiller  33 A where it can cool the natural gas stream  110  in indirect heat exchange means  38 . High stage propane chiller  33 A uses the flashed propane refrigerant to cool the incoming natural gas stream in conduit  110 . Another portion of the stream from propane cooler  32  is routed through conduit  302 B to another pressure reduction means, illustrated as expansion valve  36 B, wherein the pressure of the liquefied propane is reduced in stream  304 B. 
     The cooled natural gas stream from high-stage propane chiller  33 A flows through conduit  114  to a separation vessel, wherein water and in some cases a portion of propane and/or heavier components are removed, typically followed by a treatment system  40 , in cases where not already completed in upstream processing, wherein moisture, mercury and mercury compounds, particulates, and other contaminants are removed to create a treated stream. The stream exits the treatment system  40  through conduit  116 . The stream  116  then enters intermediate-stage propane chiller  34 , wherein the stream is cooled in indirect heat exchange means  41  via indirect heat exchange with a propane refrigerant stream. The resulting cooled stream in conduit  118  is routed to low-stage propane chiller  35 , wherein the stream can be further cooled through indirect heat exchange means  42 . The resultant cooled stream can then exit low-stage propane chiller  35  through conduit  120 . Subsequently, the cooled stream in conduit  120  can be routed to high-stage ethylene chiller  53 . 
     A vaporized propane refrigerant stream exiting high-stage propane chillers  33 A and  33 B is returned to the high-stage inlet port of propane compressor  31  through conduit  306 . An unvaporized propane refrigerant stream exits the high-stage propane chiller  33 B via conduit  308  and is flashed via a pressure reduction means, illustrated here in  FIG. 1  as expansion valve  43 . The liquid propane refrigerant in high-stage propane chiller  33 A provides refrigeration duty for the natural gas stream  110 . Two-phase refrigerant stream can enter the intermediate-stage propane chiller  34  through conduit  310 , thereby providing coolant for the natural gas stream (in conduit  116 ) and stream entering intermediate-stage propane chiller  34  through conduit  204 . The vaporized portion of the propane refrigerant exits intermediate-stage propane chiller  34  through conduit  312  and enters the intermediate-stage inlet port of propane compressor  31 . The liquefied portion of the propane refrigerant exits intermediate-stage propane chiller  34  through conduit  314  and is passed through a pressure-reduction means, illustrated here as expansion valve  44 , whereupon the pressure of the liquefied propane refrigerant is reduced to flash or vaporize a portion thereof. The resulting vapor-liquid refrigerant stream can then be routed to low-stage propane chiller  35  through conduit  316  and where the refrigerant stream can cool the methane-rich stream and an ethylene refrigerant stream entering low-stage propane chiller  35  through conduits  118  and  206 , respectively. The vaporized propane refrigerant stream then exits low-stage propane chiller  35  and is routed to the low-stage inlet port of propane compressor  31  through conduit  318  wherein it is compressed and recycled as previously described. 
     Still referring to  FIG. 1 , a stream of ethylene refrigerant in conduit  202  enters high-stage propane chiller  33 B, wherein the ethylene stream is cooled through indirect heat exchange means  39 . The resulting cooled ethylene stream can then be routed in conduit  204  from high-stage propane chiller  33 B to intermediate-stage propane chiller  34 . Upon entering intermediate-stage propane chiller  34 , the ethylene refrigerant stream can be further cooled through indirect heat exchange means  45  in intermediate-stage propane chiller  34 . The resulting cooled ethylene stream can then exit intermediate-stage propane chiller  34  and can be routed through conduit  206  to enter low-stage propane chiller  35 . In low-stage propane chiller  35 , the ethylene refrigerant stream can be at least partially condensed, or condensed in its entirety, through indirect heat exchange means  46 . The resulting stream exits low-stage propane chiller  35  through conduit  208  and can subsequently be routed to a separation vessel  47 , wherein a vapor portion of the stream, if present, can be removed through conduit  210 , while a liquid portion of the ethylene refrigerant stream can exit separator  47  through conduit  212 . The liquid portion of the ethylene refrigerant stream exiting separator  47  can have a representative temperature and pressure of about −24° F. (about −31° C.) and about 285 psia (about 1,965 kPa). 
     Turning now to the ethylene refrigeration cycle  50  in  FIG. 1 , liquefied ethylene refrigerant stream in conduit  212  can enter an ethylene economizer  56 , wherein the stream can be further cooled by an indirect heat exchange means  57 . The resulting cooled liquid ethylene stream in conduit  214  can then be routed through a pressure reduction means, illustrated here as expansion valve  58 , whereupon the pressure of the cooled predominantly liquid ethylene stream is reduced to thereby flash or vaporize a portion thereof. The cooled, two-phase stream in conduit  215  can then enter high-stage ethylene chiller  53 . In high-stage ethylene chiller  53 , at least a portion of the ethylene refrigerant stream can vaporize to further cool the stream in conduit  120  entering an indirect heat exchange means  59 . The vaporized and remaining liquefied ethylene refrigerant exits high-stage ethylene chiller  53  through conduits  216  and  220 , respectively. The vaporized ethylene refrigerant in conduit  216  can re-enter ethylene economizer  56 , wherein the stream can be warmed through an indirect heat exchange means  60  prior to entering the high-stage inlet port of ethylene compressor  51  through conduit  218 . Ethylene is compressed in multi-stage (e.g., three-stage) ethylene compressor  51  driven by, for example, a gas turbine driver (not illustrated). The stages of compression may exist in a single unit or two or more separate units mechanically coupled to a single driver. 
     The cooled stream in conduit  120  exiting low-stage propane chiller  35  can be routed to high-stage ethylene chiller  53 , where it is cooled via indirect heat exchange means  59  of high-stage ethylene chiller  53 . The remaining liquefied ethylene refrigerant exiting high-stage ethylene chiller  53  in conduit  220  can re-enter ethylene economizer  56  and undergo further sub-cooling by an indirect heat exchange means  61  in ethylene economizer  56 . The resulting sub-cooled refrigerant stream exits ethylene economizer  56  through conduit  222  and subsequently passes a pressure reduction means, illustrated here as expansion valve  62 , whereupon the pressure of the refrigerant stream is reduced to vaporize or flash a portion thereof. The resulting, cooled two-phase stream in conduit  224  enters low-stage ethylene chiller/condenser  55 . 
     A portion of the cooled natural gas stream exiting high-stage ethylene chiller  53  can be routed through conduit  122  to enter indirect heat exchange means  63  of low-stage ethylene chiller/condenser  55 . In the low-stage ethylene chiller/condenser  55 , cooled stream can be at least partially condensed and, often, subcooled through indirect heat exchange with the ethylene refrigerant entering low-stage ethylene chiller/condenser  55  through conduit  224 . The vaporized ethylene refrigerant exits low-stage ethylene chiller/condenser  55  through conduit  226 , which then enters ethylene economizer  56 . In the ethylene economizer  56 , vaporized ethylene refrigerant stream  226  can be warmed through an indirect heat exchange means  64  prior to being fed into the low-stage inlet port of ethylene compressor  51  through conduit  230 . As shown in  FIG. 1 , a stream of compressed ethylene refrigerant exits ethylene compressor  51  through conduit  236  and subsequently enters ethylene cooler  52 , wherein the compressed ethylene stream can be cooled through indirect heat exchange with an external fluid (e.g., water or air). The resulting cooled ethylene stream is introduced through conduit  202  into high-stage propane chiller  33 B for additional cooling as previously described. 
     The condensed and, often, subcooled liquid natural gas stream exiting low-stage ethylene chiller/condenser  55  in conduit  124  can also be referred to as a “pressurized LNG-bearing stream.” This pressurized LNG-bearing stream exits low-stage ethylene chiller/condenser  55  through conduit  124  prior to entering main methane economizer  73 . In the main methane economizer  73 , methane-rich stream in conduit  124  can be further cooled in an indirect heat exchange means  75  through indirect heat exchange with one or more methane refrigerant streams (e.g.,  76 ,  77 ,  78 ). The cooled, pressurized LNG-bearing stream exits main methane economizer  73  through conduit  134  and routes to expansion section  80  of methane refrigeration cycle  70 . In the expansion section  80 , the pressurized LNG-bearing stream first passes through high-stage methane expansion valve or expander  81 , whereupon the pressure of this stream is reduced to vaporize or flash a portion thereof. The resulting two-phase methane-rich stream in conduit  136  can then enter into high-stage methane flash drum  82 , whereupon the vapor and liquid portions of the reduced-pressure stream can be separated. The vapor portion of the reduced-pressure stream (also called the high-stage flash gas) exits high-stage methane flash drum  82  through conduit  138  to then enter into main methane economizer  73 , wherein at least a portion of the high-stage flash gas can be heated through indirect heat exchange means  76  of main methane economizer  73 . The resulting warmed vapor stream exits main methane economizer  73  through conduit  138  and is then routed to the high-stage inlet port of methane compressor  71 , as shown in  FIG. 1 . 
     The liquid portion of the reduced-pressure stream exits high-stage methane flash drum  82  through conduit  142  to then re-enter main methane economizer  73 , wherein the liquid stream can be cooled through indirect heat exchange means  74  of main methane economizer  73 . The resulting cooled stream exits main methane economizer  73  through conduit  144  and then routed to a second expansion stage, illustrated here as intermediate-stage expansion valve  83  and/or expander. Intermediate-stage expansion valve  83  further reduces the pressure of the cooled methane stream which reduces the stream&#39;s temperature by vaporizing or flashing a portion thereof. The resulting two-phase methane-rich stream in conduit  146  can then enter intermediate-stage methane flash drum  84 , wherein the liquid and vapor portions of this stream can be separated and exits the intermediate-stage flash drum  84  through conduits  148  and  150 , respectively. The vapor portion (also called the intermediate-stage flash gas) in conduit  150  can re-enter methane economizer  73 , wherein the vapor portion can be heated through an indirect heat exchange means  77  of main methane economizer  73 . The resulting warmed stream can then be routed through conduit  154  to the intermediate-stage inlet port of methane compressor  71 , as shown in  FIG. 1 . 
     The liquid stream exiting intermediate-stage methane flash drum  84  through conduit  148  can then pass through a low-stage expansion valve  85  and/or expander, whereupon the pressure of the liquefied methane-rich stream can be further reduced to vaporize or flash a portion thereof. The resulting cooled, two-phase stream in conduit  156  can then enter low-stage methane flash drum  86 , wherein the vapor and liquid phases are separated. The liquid stream exiting low-stage methane flash drum  86  through conduit  158  can comprise the liquefied natural gas (LNG) product at near atmospheric pressure. This LNG product can be routed downstream for subsequent storage, transportation, and/or use. 
     A vapor stream exiting low-stage methane flash drum (also called the low-stage methane flash gas) in conduit  160  can be routed to methane economizer  73 , wherein the low-stage methane flash gas can be warmed through an indirect heat exchange means  78  of main methane economizer  73 . The resulting stream can exit methane economizer  73  through conduit  164 , whereafter the stream can be routed to the low-stage inlet port of methane compressor  71 . 
     The methane compressor  71  can comprise one or more compression stages. In one embodiment, methane compressor  71  comprises three compression stages in a single module. In another embodiment, one or more of the compression modules can be separate but mechanically coupled to a common driver. Generally, one or more intercoolers (not shown) can be provided between subsequent compression stages. 
     As shown in  FIG. 1 , a compressed methane refrigerant stream exiting methane compressor  71  can be discharged into conduit  166 . The compressed methane refrigerant can be routed to methane cooler  72 , whereafter the stream can be cooled through indirect heat exchange with an external fluid (e.g., air or water) in methane cooler  72 . The resulting cooled methane refrigerant stream exits methane cooler  72  through conduit  112  and is directed to and further cooled in propane refrigeration cycle  30 . Upon cooling in the propane refrigeration cycle  30  through heat exchanger means  37 , the methane refrigerant stream can be discharged into conduit  130  and subsequently routed to main methane economizer  73 , wherein the stream can be further cooled through indirect heat exchange means  79 . The resulting sub-cooled stream exits main methane economizer  73  through conduit  168  and then combined with stream in conduit  122  exiting high-stage ethylene chiller  53  prior to entering low-stage ethylene chiller/condenser  55 , as previously discussed. 
     The liquefaction process described herein may incorporate one of several types of cooling means including, but not limited to, (a) indirect heat exchange, (b) vaporization, and (c) expansion or pressure reduction. Indirect heat exchange, as used herein, refers to a process wherein a cooler stream cools the substance to be cooled without actual physical contact between the cooler stream and the substance to be cooled. Specific examples of indirect heat exchange means include heat exchange undergone in a shell-and-tube heat exchanger, a core-in-shell heat exchanger, and a brazed aluminum plate-fin heat exchanger. The specific physical state of the refrigerant and substance to be cooled can vary depending on demands of the refrigeration system and type of heat exchanger chosen. 
     Expansion or pressure reduction cooling refers to cooling which occurs when the pressure of a gas, liquid or a two-phase system is decreased by passing through a pressure reduction means. In some embodiments, expansion means may be a Joule-Thomson expansion valve. In other embodiments, the expansion means may be either a hydraulic or gas expander. Because expanders recover work energy from the expansion process, lower process stream temperatures are possible upon expansion. 
     Vaporization and Recovery of Residual LNG 
     Vaporization and recovery of residual LNG may begin by routing methane from the main liquefaction process (illustrated in  FIG. 1 ) via conduit A to a vaporization and recovery system (illustrated in  FIGS. 2A and 2B ). While  FIGS. 2A and 2B  represent different modes of operation, main components of both modes are identical. Thus, in some embodiments, a single vaporization and recovery system can operate in both open and closed mode without additional equipment. For clarity, reference numbers are used consistently for similar or same elements in the figures. 
     Referring to  FIG. 2A , methane is taken from a methane compressor discharge in conduit  501  and passed through a methane compressor intercooler. In the illustrated embodiment, the compressor  71  is a multi-stage compressor featuring one or more compressor intercoolers. In the embodiment shown in  FIG. 2A , methane is taken from a low-stage methane compressor  71   a  and to the low-stage methane compressor intercooler  502 . Methane exiting the low-stage methane compressor intercooler  502  can then be introduced into the vaporization and recovery system. In some embodiments, multiple boil-off gas (BOG) compressors  513  may be present. These compressors have capacity designed to handle LNG vaporization from standing tanks and tanks being filled. In some embodiments, capacity also exists to handle ship-loading BOG from a transport carrier tanker being filled. The ship-loading capacity often sets the sizing of the BOG compressors  513 . For example, if tank inspection is done when not handling ship-loading BOG vapors, excess capacity exists in the BOG compressors  513  that can be utilized to handle the re-circulated LNG vapors. In another embodiment, additional capacity can be designed into the BOG compressors  513  to handle the recirculation gas. 
     The introduction of methane into the vaporization and recovery system is controlled by a flow control valve  503  which regulates flow of methane via conduit  504  via a feedback loop  506 . The methane in conduit  505  is at approximately 2 to 6 barg and 30 to 50° C. and subsequently injected through a header  507  that terminates below liquid level at bottom of the LNG storage tank  510 . This hot methane gas evaporates the LNG while warming up the LNG storage tank  510 . The resultant vaporized natural gas is routed via conduit  511  to a BOG compressor suction drum  512  and eventually to a BOG compressor  513 . When connected to an FLNG vessel, boil-off gas from the vessel can be routed to the BOG compressor suction drum  512  for quenching. A portion of the vaporized natural gas can be added back into the main liquefaction process by injecting the gas into the low-stage methane compressor suction via conduit  520 . A portion of the vaporized natural gas can also be flared as necessary as via conduit  522  depending on, for example, the capacity of the BOG compressors  513 . The vaporization and recovery system is integrated into the main liquefaction process which, in turn, minimizes flaring of the boil-off gas. 
       FIG. 2B  illustrates the vaporization and recovery system operating in closed mode. This mode may be useful during times when the main liquefaction process may not be available. During closed mode operation, discharge gas taken from the BOG compressor is routed to a gas heater. In some embodiments, the gas heater may be (hard piped with valves or drop out spools. This mode requires LNG in one of the other storage tanks to be used in order to generate BOG to dry out the tank being prepared for maintenance. 
     Referring to  FIG. 2B , BOG is routed via conduit  515  to the BOG compressors  513  whereupon it is compressed. A portion of the resulting compressed BOG may be routed to the low-stage methane compressor via conduit  520  or flared if the low-stage compress is not available. Remaining portion of the compressed BOG is routed to a backup water heater  540 . Flow control valve  530  regulates flow of the compressed BOG to the backup water heater  650 . When the vaporization and recovery system is operating in the open mode ( FIG. 2A ), the flow control valve  530  is closed. When the vaporization and recovery system is operating in the closed mode ( FIG. 2B ), the flow control valve  530  is at least partially open. Flow control valve  541  regulates flow of gas stream to flow control unit  542  and temperature control unit  543 . 
     Example 1 
     Dynamic simulations were developed to model the time required to complete a heating vaporization cycle in both open mode and closed mode operations. The simulations were based on a design that includes 4 BOG compressors producing around 38-40 tons per hour depending on exact composition of BOG. The BOG compressor discharge is between about −110° C. to −125° C. in normal operation. 
     During open mode operation, the quench system was designed for a 60 T/hr load at −80° C. Under these conditions, the maximum BOG return gas temperature was −145° C. at 60 T/hr at the BOG compressor suction. The time required to heat a tank from −160 to +5° C. was estimated to be less than 24 hours including the time to evaporate 1 meter of residual LNG in a single 2500 m 3  tank. The heating was done simultaneously with a separate single operating tank with a BOG return rate of 4.3 T/hr. This heating process is required prior to a 20 hour cycle that brings inert gas followed by air. After this time, it is expected that most of the bottom 1 meter of liquid in the storage tank will have been vaporized and the vaporized gas is recirculated from the connection at the compressor suction and excess gas is sent to the flare as needed. 
     During closed mode operation, the heating process is required prior to the 20 hour cycle to bring in inert gas followed by air. The amount of gas available initially and recirculated is gradually increased until the maximum rate that the BOG compressor can handle is reached. After this time, it is expected that most of the bottom 1 meter of liquid in the tank will have been vaporized and the gas is recirculated from the connection at the BOG compressor suction and excess gas is sent to the flare. A split range pressure control connection allows the gas to be routed to the flare. A bypass is provided to allow temperature control of the warmed methane so that the potential for thermal shock is minimized (on temperature control). Hot water rate is maintained at a continuous rate. In some embodiments, an electric heater with temperature control and no bypass may be used. 
     In closing, it should be noted that the discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. At the same time, each and every claim below is hereby incorporated into this detailed description or specification as additional embodiments of the present invention. 
     Although the systems and processes described herein have been described in detail, it should be understood that various changes, substitutions, and alterations can be made without departing from the spirit and scope of the invention as defined by the following claims. Those skilled in the art may be able to study the preferred embodiments and identify other ways to practice the invention that are not exactly as described herein. It is the intent of the inventors that variations and equivalents of the invention are within the scope of the claims while the description, abstract and drawings are not to be used to limit the scope of the invention. The invention is specifically intended to be as broad as the claims below and their equivalents.