AU2008201463B2 - Apparatus for the liquefaction of natural gas and methods relating to same - Google Patents

Description

AUSTRALIA Patents Act COMPLETE SPECIFICATION (ORIGINAL) Class Int. Class Application Number: Lodged: Complete Specification Lodged: Accepted: Published: Priority Related Art: Name of Applicant: Bechtel BWXT Idaho, LLC Actual Inventor(s): Dennis N Bingham, Kerry M Klinger, Michael G McKellar, Gary L Palmer, Kevin T Raterman, Terry D Turner, John J Vranicar, Bruce M Wilding Address for Service and Correspondence: PHILLIPS ORMONDE & FITZPATRICK Patent and Trade Mark Attorneys 367 Collins Street Melbourne 3000 AUSTRALIA Invention Title: APPARATUS FOR THE LIQUEFACTION OF NATURAL GAS AND METHODS RELATING TO SAME Our Ref: 825981 POF Code: 43783/462027 The following statement is a full description of this invention, including the best method of performing it known to applicant(s): -1 - 1a TITLE OF THE INVENTION APPARATUS FOR THE LIQUEFACTION OF NATURAL GAS AND METHODS RELATING TO SAME 5 The present application is a divisional application from Australian patent application number 2002346035, the entire disclosure of which is incorporated herein by reference. CROSS REFERENCE TO RELATED APPLICATIONS This application claims the benefit of United States Patent Application 10 Serial No. 10/086,066, filed February 27, 2002 for Apparatus for the Liquefaction of Natural Gas and Methods Relating to Same. BACKGROUND OF THE INVENTION Field of the Invention: The present invention relates generally to the compression and liquefaction of gases, and more particularly to the partial 15 liquefaction of a gas, such as natural gas, on a small scale by utilizing a combined refrigerant and expansion process. A reference herein to a patent document or other matter which is given as prior art is not to be taken as an admission that that document or matter was, in Australia, known or that the information it contains was part 20 of the common general knowledge as at the priority date of any of the claims. Natural gas is a known alternative to combustion fuels such as gasoline and diesel. Much effort has gone into the development of natural gas as an alternative combustion fuel in order to combat various drawbacks of 25 gasoline and diesel including production costs and the subsequent emissions created by the use thereof. As is known in the art, natural gas is a cleaner burning fuel than other combustion fuels. Additionally, natural gas is considered to be safer than gasoline or diesel as natural gas will rise in the air and dissipate, rather than settling. 30 To be used as an alternative combustion fuel, natural gas (also termed "feed gas" herein) is conventionally converted into compressed natural gas (CNG) or liquefied (or liquid) natural gas (LNG) for purposes of storing and transporting the fuel prior to its use. Conventionally, two of the known basic Y:\8fEH%722681Lsped2002 348035.doc 1b cycles for the liquefaction of natural gases are referred to as the "cascade cycle" and the "expansion cycle." Briefly, the cascade cycle consists of a series of heat exchanges with the feed gas, each exchange being at successively lower temperatures 5 until the desired liquefaction is Y:\EM72268I1sped2002 346035.doc 5 accomplished. The levels of refrigeration are obtained with different refrigerants or with the same refrigerant at different evaporating pressures. Thecascade cycle is considered to be very efficient at producing LNG as operating costs are relatively low. However, the efficiency in operation is often seen to be offset by the relatively highinvestment costs associated with the expensive heat exchange, and the compression equipment associated 10 with the refrigerant system. Additionally, aliquefaction plant incorporating such a system may be impractical where physical space is limited, as the phyical components used in cascading systems are relatively large. In an expansion cyclegas is conventionally compressed to a selected pressure, cooled, then allowed to expand through an expansion turbine, thereby producing work as 15 well as reducing the temperature of the feed gas. The low temperature feed gas is then-heat exchanged to effect liquefaction of the feed gas. Conventionally, such a cycle:has been seen as being impracticable in the liquefaction of natural gas since there is no provision for handling some of the compomets resentinnatural, gas which freeze at the temperatures encountered in the heat exchangers, for example, water and carbon dioxide. 20 Additionally, to make the operation of conventional systems cost effective such systems are conventionally built on a large scale to handle large volumes of natural gas. As a result, fewer facilities are built making it more difficult to provide the raw gas to the liquefaction plant er facility as wel as making distribution of the liquefied product an issue., Another major problem with large scale facilities is the capital and operating 25 expenses associated therewith., For example, a conventional large scale liquefaction plant, i.e., producing on the order of7O,000 gallons of LNG per day, may cost.$2 million to $15 million, or more, intcapital expenses. Also, such a plant may require thousands of horsepower to drive the compressors associated with the refrigerant cycles, making operation:of the plants expensive. 30 An additional problem with large facilities is the cost associated with storing large amounts of fuel in anticipation of future use and/or transportation. Not only is there a cost associated-with building large storage-facilities, but-there is, also an efficiency isuerelated therewith as stored LNG will tend to wann and vaporize over-time creating a loss of the LNGIfueliproduot. Further, safety may bee'ome an issue wheijlarger amounts of LNG fuel 35 prodiet are stored. -2- 5 In confronting the foregoing issues, various systems have been devisedlwhich attempt to produce LNG-or CNG from feed gas on a smaller scale in aWffort toeliminate. lonternatorage issues and to reduce the capital and operating expensesassociated with the liquefaction and/or compression of natural gas. However such systems and techniques haveall sffeed from one or more drn-backse 10 U.SPtent 5,50 52524o Barelay, issued Aprik9, 1 996isdirected to system for produningNG and/drTCNG. The disclasd: system-is stated to operate on aismall scale producing approximately 1,000 gallons a day of liquefied or compressed fuel product. However, the liquefaction portion of the system itself requires the flow of a "clean" or "purified" gas, neaniig thatvarions d nstituentsin thegas siudh as carbon dioxide, water, 15 or heavy hydrocarbons must be renved before the actual liquefaction process can begin. Simil U. Patents 6 085,546'add&6,085,541 bothissued July 1,;2000 to Johnstni describe methods and systems6f producing LNG. The Johnston patents: are bothdirectedito st all sdale prodition of LNG but again, both require "prepurification" of the gas in order t& iinplement the actualliquefactin cycle. The; ieed to provide "clean" 20 -or".prepurified"kgas to the liquefaction cycle is based on the fact that certaigas component niigh freeze and plug ththe liquefactionsprocess because of their relatively higher freezing points as compared to methane which makes up the; larger Sie many sode6s of natural gas, such as residential or industrial service gas, are 25 considered to be relatively "dirty," the requirement of'providing "clean" or "preputified" gasis actually requirement ofimplemnenting expensive and often: complex filtration and purification systems prior to the liquefaction process: This requirement simply'adds eilense aaie'oihp&ity to theconstruction and operation 6f such liquefaction plants or 30 In iew of the shbitcomings in the art, it would-e advantageous toprovide a' 'oness,' and plant for carrying out'sech Ap'tocess, of efficiently produCing liquefied natffal gaon a srnallisdale. More-p'aticularly, it wo'ld be advantageous to.provide a systein for pifdducifig liqdefied'naturalgas froina source of relatively "dirty" or unpurified" nathiralga'wsithoutthe need foi prepurification*" Such a system or process 35 nayiniilde vribus-creahup cycles which are integrated with the liquefaction cycle. for -3- 4 purposes for efficiency. It would be additionally advantageous to provide a plant for the liquefaction of natural gas which is relatively inexpensive to build and operate, and which desirably requires little or no operator oversight. 5 It would be additionally advantageous to provide such a plant which is easily transportable and which may be located and operated at existing sources of natural gas which are within or near populated communities, thus providing easy access for consumers of LNG fuel. BRIEF SUMMARY OF THE INVENTION 10 According to the present invention, there is provided a liquefaction plant including: a plant inlet configured to be sealingly and fluidly coupled with a source of unpurified natural gas; a turbo expander positioned and configured to receive a first stream of natural 15 gas drawn through the plant inlet and produce an expanded cooling stream therefrom; a compressor mechanically coupled to the turbo expander and positioned and configured to receive a second stream of natural gas drawn through the plant inlet and produce a compressed process stream therefrom; a high efficiency countercurrent flow heat exchanger positioned and configured 20 to receive the compressed process stream and the expanded cooling stream in a countercurrent flow arrangement to cool the compressed process stream; a tube-in-shell heat exchanger positioned and configured to receive the cooled compressed process stream therethrough, the tube-in-shell heat exchanger including a plurality of vertically stacked corrosion resistant coils within a corrosion resistant 25 tank and at least one diverter valve, the at least one diverter valve for maintaining continuous flow through one coil of the plurality of coils and transitory flow through at least one other coil of the plurality of coils of the tube-in-shell heat exchanger; a first plant outlet positioned and configured to be sealingly and fluidly coupled with the source of unpurified gas and to discharge the expanded cooling stream 30 thereinto subsequent to passage thereof through the high efficiency countercurrent flow heat exchanger; a first expansion valve positioned and configured to receive and expand a first portion of the cooled compressed process stream to form an additional cooling stream, the plant further including conduit structure to combine the additional cooling Cpnwr\SPEC-825981.doc 5 stream with the expanded cooling stream prior to the expanded cooling stream entering the high efficiency countercurrent flow heat exchanger; a second expansion valve positioned and configured to receive and expand a second portion of the cooled compressed process stream to form a mixed gas, liquid 5 natural gas and solid carbon dioxide therefrom; a first gas-liquid separator positioned and configured to receive the mixed gas, liquid natural gas and solid carbon dioxide; and a second plant outlet positioned and configured to be sealingly and fluidly coupled with a storage vessel, the first gas-liquid separator being positioned and 10 configured to deliver a liquid contained therein to the second plant outlet. According to the present invention, there is also provided a method of producing liquid natural gas, the method including: providing a source of unpurified natural gas; flowing a portion of natural gas from the source; 15 dividing the portion of natural gas into a process stream and a first cooling stream; flowing the first cooling stream through a turbo expander having an expanded first cooling stream exiting therefrom and producing work output therefrom; powering a compressor with the work output of the turbo expander; 20 flowing the process stream through the compressor having a compressed process stream exiting therefrom; cooling the compressed processed stream with at least the first expanded cooling stream using a plurality of heat exchangers, the plurality of heat exchangers including a high efficiency heat exchanger cooling the compressed process stream to 25 a cooled stream of natural gas having a temperature that does not generate solid carbon dioxide therein and a tube-in-shell heat exchanger cooling the cooled stream from the high efficiency heat exchanger forming a cooled process stream of natural gas, the tube-in-shell heat exchanger having a plurality of coils of tubing therein; maintaining a steady state flow of at least a portion of the cooled stream from 30 the high efficiency heat exchanger through one coil of the plurality of coils of tubing of the tube-in-shell heat exchanger; C:pofordiSPEC-825981.doc 5a maintaining a steady state flow of at least a portion of the cooled stream from the high efficiency heat exchanger through one coil of the plurality of coils of tubing of the tube-in-shell heat exchanger; diverting some of the flow of at least a portion of the cooled stream from the 5 high efficiency heat exchanger through at least one other coil of the plurality of coils of tubing of the tube-in-shell heat exchanger; dividing the cooled compressed process stream from the tube-in-shell heat exchanger into a product stream and a second cooling stream; expanding the second cooling stream and combining the expanded second 10 cooling stream with the expanded first cooling stream; expanding the product stream to form a mixture including mixed gas, liquid natural gas and solid carbon dioxide; separating liquid natural gas and solid carbon dioxide from the mixed gas, liquid natural gas and solid carbon dioxide forming a thickened slush used for cooling 15 in the tube-in-shell heat exchanger; and separating at least a portion of the liquid natural gas from the solid carbon dioxide and liquid natural gas. Another arrangement considered by the Applicant but which is not the subject of the present application relates to a method which is provided for removing carbon 20 dioxide from a mass of natural gas. The method includes cooling at least a portion of the mass of natural gas to form a slurry which comprises at least liquid natural gas and solid carbon dioxide. The slurry is C:\pcf\Wr\SPEC-825081 doc 6 flowed into a hydrocyclone and a thickened slush is formed therein. The thickened slush comprises the solid carbon dioxide and a portion of the liquid natural gas. The thickened slush is discharged through an underflow of the hydrocyclone while the remaining portion of liquid natural gas is flowed through 5 an overflow of the hydrocyclone. Cooling the portion of the mass of natural gas may be accomplished by expanding the gas, such as through a Joule-Thomson valve. Cooling the portion of the mass of natural gas may also include flowing the gas through a heat exchanger. 10 The method may also include passing the liquid natural gas through an additional carbon dioxide filter after it exits the overflow of the hydrocyclone. Another arrangement considered by the Applicant but which is not the subject of the present application relates to a system for removing carbon dioxide from a mass of natural gas. The system includes a compressor 15 configured to produce a compressed stream of natural gas from at least a portion of the mass of natural gas. At least one heat exchanger receives and cools the compressed stream of natural gas. An expansion valve, or other gas expander, is configured to expand the cooled, compressed stream and form a slurry therefrom, the slurry comprising liquid natural gas and solid carbon 20 dioxide. A hydrocyclone is configured to receive the slurry and separate the slurry into a first portion of liquid natural gas and a thickened slush comprising the solid carbon dioxide and a second portion of the liquid natural gas. The system may further include additional heat exchangers and gas expanders. Additionally, carbon dioxide filters may be configured to receive 25 the first portion of liquid natural gas for removal of any remaining solid carbon dioxide. BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS The foregoing and other advantages of the invention will become apparent upon reading the following detailed description and upon reference to 30 the drawings in which: FIG. 1 is a schematic overview of a liquefaction plant according to one embodiment; Y:BE722661\Speel2OO2 346035.doc 7 FIG. 2 is a process flow diagram depicting the basic cycle of a liquefaction plant according to one embodiment; FIG. 3 is a process flow diagram depicting a water clean-up cycle integrated with the liquefaction cycle according an embodiment; 5 FIG. 4 is a process flow diagram depicting a carbon dioxide clean-up cycle integrated with a liquefaction cycle according an embodiment of the present invention; FIGS. 5A and 5B show a heat exchanger according to one embodiment; FIGS. 6A and 6B show plan and elevational views of cooling coils used 10 in the heat exchanger of FIGS. 5A and 5B; FIGS 7A through 7C show a schematic of different modes operation of the heat exchanger depicted in FIGS. 5A and 5B according to various embodiments; FIGS. 8A and 8B show perspective and elevation view respectively of a 15 plug which may be used in conjunction with the heat exchanger of FIGS. 5A and 5B; FIG. 9 is a cross sectional view of an exemplary CO 2 filter used in conjunction with the liquefaction plant and process of FIG. 4; FIG. 10 is a process flow diagram depicting a liquefaction cycle 20 according to another embodiment; FIG. 11A is a process schematic showing a differential pressure circuit incorporated in the plant and process of FIG. 10; FIG. 11B is a process schematic showing a preferred differential pressure circuit incorporated in the plant and process of FIG. 10; 25 FIG. 12 is a process flow diagram depicting a liquefaction cycle according to another embodiment; FIG. 13 is a perspective view of liquefaction plant according to one embodiment; FIG. 14 shows the liquefaction plant of FIG. 4 in transportation to a plant 30 site; and FIG. 15 is a process flow diagram showing state points of the flow mass throughout the system according to one embodiment. Y:\EK722661\spc20 346035.doc 7a DETAILED DESCRIPTION OF THE INVENTION Referring to FIG. 1, a schematic overview of a portion of a liquefied natural gas (LNG) station 100 is shown according to one embodiment. It is noted that, while the present invention is set forth in terms of liquefaction of 5 natural gas, the present invention may be utilized for the liquefaction of other gases as will be appreciated and understood by those of ordinary skill in the art. The liquefaction station 100 includes a "small scale" natural gas liquefaction plant 102 which is coupled to a source of natural gas such as a 10 pipeline 104, although other sources, such as a well head, are contemplated as being equally suitable. The term "small scale" is used to differentiate from a larger scale plant having the capacity of producing, for example 70,000 gallons of LNG or more per day. In comparison, the presently disclosed liquefaction plant may have capacity of producing, for example, approximately 10,000 15 gallons of LNG a day but may be scaled for a different output as needed and is not limited to small scale operations or plants. Additionally, as shall be set forth in more detail below, the liquefaction plant 102 of the present invention is considerably smaller in size than a large-scale plant and may be readily transported from one site to another. 20 One or more pressure regulators 106 are positioned along the pipeline 104 for controlling the pressure of the gas flowing therethrough. Such a configuration is representative of a pressure letdown station wherein the pressure of the natural gas is reduced from the high transmission pressures at an upstream location to a pressure suitable for distribution to one or more 25 customers at a downstream location. Upstream of the Y:\BEH\722681\sped2002 346035.doc 5 pressure regulators 106, for example, the pressure in the pipeline may be approximately 300 to 1000 pounds per square inch absolute (psia) while the pressure downstream of the regulators may be reducedto approximately 65 psia.or less. Of course, such pressures are exemplary and may vary depending on the-particular pipeline 104 and the needs of the downstream customers. It is further noted that the available pressure of the upstream gas 10 in the pipeline 104 (i.e., at plant entry 112) is not critical as the pressure thereof may be raised, for example by use of an auxiliary booster pump and heat exchanger, prior to the gas entering the liquefaction process described. herein. Prior to any reductionin pressure along the pipeline 104, a stream offeed.gas 108 is split off from the pipeline 104 and fed through a flow meter 110 which measures and 15 records the amount of gasfiowing therethrough. The stream of feed gas108 then enters the small scale -liquefaction plant 102 through a plant inlet 112 for processing as will be detailed below herein. A portion of the feed gas entering thes.liquefactioi plant 102 becomes LNG and exits the plant 102 at a plant outlet 114 for storage in a suitable tank or vessel 116. Thevessel 116 is. preferably configured to hold at least10,00 gallons of 20 LNG at a pressure of approximately 30 to 35 psia and at temperatures -as low as. approximately -240P:F. 'Howeverother vessel sizes and configurations may be utilized depending on specific'output requirements of the plant 102. A. vessel- outlet 11-8is coupledto a flow meter 120 in.assoGiation with dispensing the LNG from the vessel-i 16, such as to a vehicle which is powered by LNG, or into a 25 transport vehicle asemay~bi required. A vessel inlet 122, couple with a valyelmeter.set 124 whidh could include flow and ortprocess measurement devices, allows for venting and/or-purging of a vehicles tank duringsdispensing of LNG fremathe vessel 416i...Piping 126 associated; with the vessel 116 an&connecting with a second plant inletj12 provides flexibility incontrolling the flow of LNG from the liquefaction plant 102 ad4 also allows 30 the flow tolbediverted away froe the vessel 116 orfor drawing vapor from t e vessel 116, shouldcontditions ever'make suchaction desirable.. The liquefaction -plant 102 is-also coupled to a, downstream section, 130'of the pipeline 104,at a s'eond plant outlet 132 for discharging the portion of natural gas not liquefied duringthe process conducted withainliquefaction plant 102 along with other 35 constituents which maybe removed during productionsof the LNG. Optionally adjacent -8- 5 the vessel inlet 122, vent piping 134 may be Coupled with piping of liquefaction plant 102 as indicated by interface points 136A and. 136B. Such vent piping 134 will similarly carry gas into the downstream section 130 of the pipeline 104.

As the various gas components leave the- liquefaction plant 102 and enter into the downstream section 130 of the pipeline 104 a valve/meter set 138, which could include 10 flow and/or process measuring devices, may be used to measure the flow of the gas therethrough. The valve/meter sets 124 and 138 as well as thd flow meters 110 and 120 may be-positioned outside of the plant 102 and/orinside the plant as may be desired. Thus, flow meters 110 and 126, when the outputs thereof are compared, help to determine the net amount, of feed gas removed from the pipeline 104 as the'upstream flow meter 110 15 measures the gross amount of gas removed and the downstream flow meter 130 measures the amount of gas placed back into the pipelineI04, the- difference -being the net amount of feed gas removed from pipeline.104. Sirmilarly, optional flow meters 120 and 124 indicate the net discharge of LNG from the vessel 116. Referring now to FIG. .2, a process flow diagram is shown; representative of one 20 embodimentofthb liquefaction plant 102 schematically depicted in FIG... As previously indicated with resiect to FIG. 1, a high pressure strearn of feed gas (i.e.i,300 -to 1000 ipsia), 'or example, at a temperature of approximately 60*F entersthe liquefaction plant 102 fhrouigh the plantitilet 112. Pior to processing the feed gas, a small portion of feed gas 140 may be split 6ff, passed through drying filter 14-2 and utilized assinstrument control 25 gas ii conjunction with operating and controlling variousicomponents in the liquefaction Plant 102. While ornlya single stream 144 ofinsti-unent gas is:depicted, itwillbe. appreciated b those of skill in the art that multiplelines of instrument gas may be formed ina similar manner. Alternatively, a separate source of instrument gas, suth as, for example,-nitrogen, 30 may be provided for-canrolling various instruments and components within the liquefaction-plant 102. As will be appreciated ,y those.of ordinary-.skill in the art alternative iintrument'controlsg'such as elebtricahlactuatibn, may likewise be-implemented. Upoi entryinto theiquefaction plant 102;the feedgas-flows through a filter 146 t6 'remove any sizeable objects.which might cause darnage to; or otherwise obstruct, the 35 flow of gas through the various components of-theliqnfactionrplant 102.'Theffilter 146 -9- 5 may additionally be utilized to remove certain liquid-and solid components. For example, the filter 146 may be a coalescing type filter. One exemplary filter is available from Parker Filtration, located in Tewksbury, Massachusetts and is designed-to process approximately 5000 standard cubic feet per minute (SCFM) of natural gas at approximately 60*F at a pressure of approximately 500 psia. 10 The filter 146 may be provided with an optional drain 148 which discharges into piping near the plant dit 132, as-is indicated byinterface connections 136C and 136A, the discharge ultimately Teentering the downstream section 130 of the pipeline 104 (see FIG. 1). Bypass piping 1:50 is routed around the filter 146, allowing the filter 146 to be isolated and serviced as may be required without interrupting the flow of gas through the . 15 liquefaction plant 102. After the feed gas flows through the filter 146 (or alternatively around the filter by wayof piping 150) the feed gas is split into two streams, a cooling stream 152 and.a process stream 154; The cooling stream 152 passes through a turbo expandpr 156 and is expanded to an expanded cooling stream 152' exhibiting a lower pressure, for example 20 between atniospheric pressure and approximately 100 psia; at reduced temperate of approximately 100*F. The'turbo expander 156 is a turbinewhich expands the gas and extracts power from the- expansion process. A rotary compressor 158 is coupled to the turbo expander 156 by mechanical means, such as with a shaft 160; and utilizes the power generated by the turbo expanded 156 to compress the process stream 154., The proportion 25 of gas in each of the cooling and process lines 152 and 154 is determined by the- power requirements of the compressor 158 as well as the flow and pressure drop across the turbo expander-1 56. Vane control valves within the turbo -expander 156 may be used to control the proportion of gas between the cooling and process lines 152 and 154 as is required according to the above stated parameters. 30 An exemplary turbo expander 156 and compressor 158 system includes a frame size ten (10) system available from GE Rotoflow, located in Gardona, California, The expander 156 compressor 158 system- is designed to operate at approximately 440 psia at 5,000 pounds rmass per hour at about 60*F. The expander/compressor systern may also be fitted with magnetic bearingsto reduce theCootprint of the expander 156 and compressor 35 158 'as well as simplifymaihtenance thereof. -10- 5 Bypass'piping 162 routes the cooling-stream 152 around the turbo expander 156. Likewise bypass piping 164foutes-the'processstream 154 around the compressor 158. The bypass piping 162 and 164 may-be used during startup to bring certain components to a steady state condition prior to the processing of LNG within the liquefaction plant 102. For example, the bypass piping 162 and 164 allows the heat exchanger 166, and/or other 10 components.to be brought to a steady state temperature without inducing thermal shock. Without bypass piping 162 and l'64, thermaklshock might result from the immediate flow of gas from the turbo e6(pander 156 and compressor 154. Depending on the, design of specific components (i.d., the heat exchanger 166) being used in the liquefaction plant 102, several hours may be required to bring'the systemto a thermally steady state condition 15 upon start-up of 'the liquefactionpIant,102. For example, by routing the process stream 154 around the.compressor 158, the temperature of the process stream 154 is not increased priorto ts introduction into the heat exchanger 166. However, the cooling stream 152,as it bypasses the expander 1.56, passes through a' Joule-Thomson (JT):valve 163 allowing the coolingstream to expand 20 thereby reducing its temperature. The JT valvc 163 utilizes: the Joule-Thomsonprinciple that expansion of gat wilfresultin an associated cooling of the gas as well, as is, understood bythose ofordinary skill in-the art. The cooling stream 152 may then be used to incrementally reduce the temperature of theheat exchanger 166. In onetembodiment, as- discussed in more detail blow, the heat exchanger 166 is a 25 high efficiency heat exchanger made from aluminum. In start-up situations it m.y be desirable to reduce'theatemperature of such a heat-exchangeri466 by as much as L8*F per minuteintil a defined temperature limit is achieved. During start-up of the liquefaction plant, th'e temperature of the heat exchanger 166 may be monitored as it increnentally drops. The JT Valve 163 and other valving 1 65,oriastrument may controlled, 30 accordingly 'in ider to-effect the rate and pressure of flow in the cooling stre nmI 152' and process stream 154'which ultimately controlsfthe cooling rate ofheat,exchaner 1,66 and/or other components of the liquefaction plant Also, duringstart-upit may be desirable to have an amount of LNG already present in the tank 16(FIGM.; ). Some of thecold-vapor taken from the LNG present in 35 the tank, or cold vapo or gas from another source may be cycled-through the system in -11- 5 order to-cool various components is so desired.or deemed necessary. Also, as will become apparent upon reading the additional-description below, other cooling devices, including additional JT valves, located in various "loops" or flow streams may likewise be controlled during start-up in order to cool: down the heSt exchanger,166.or pther. components of the liquefaction plant 102. 10 Upon achieving a steady state condition, the process stream 154 is flowed through the compressor 158 which raises the pressure of'the process stream 154. An exemplary ratio of the outlet to inlet pressures of a rotary compressoris approximately 1.5 to 2.0, with an average ratib being around 1.7. The compression processes not ideal and, therefore, adds heat to the process stream. 154 as it is-compressed. To removefheat from 15 the compressed process stream 154' it is flowed through the heat exchanger 166. and is cooled to a very low temperaturtfor example approximately -20Q*F. The exemplary heat'exithange 166 depicted in FIG. 2 is a type utilizing countercurrentflow, as is known by th6se of ordinary 9kill in the art. After'eiiting the heat eehanger 166, the cooledspompressed process stream 154" 2() is splitinto two new streams, cooling stream 170 and.a product stream 172. The cooling streant 170 and the product strearn 172 are each expanded. through JT valvgs. 174 and 176 respectively. The expansion ofthe:coolingand process: streams 170 and 17,2 through the JT valves 174 and 176 result in a reduced pressure; such as,-for example , between atmospheric and approximately 100 psia, and a reduced:temperature, for example, of 25 approximately ,240*F The reduced pressure and temperatures will cause the cooling and product streais 170 and 172 to form a mixture of liquid and- vapor natural gas. The cooling-stream 170 is combined with the expanded cooling stream. 152' exiting the turbo expander 156 to create a combined cooling stream 178. Thecombined cooling strtam'178 is then used to cool the-compressed process stream '154' via the heat 30 exchanger '166. After coolig the compressed process stream 154' in the heat exchanger 166, the dombinsd 'cboling stream 178 may be discharged'baqk into -the naturalgas. pipeline -104 at the downstream section- 130 (FIG.4).: , After expansion via the- JTvalve 176, the produt stream 17entersinto a liquid/vayor separator180. The'vapor cofiponent from the separator 180 is collected and 35 removed therefrom through piping 182 and addedsto the-eombined cooling stream 178 -12- 5 upstreaf of the heatexchanger 166. The liquid component in the separator is the LNG fuel product and passes-through the Vlant outlet.4 1,4 for storage in the vessel i1 IG. 1) By controllingthe proportion of gas respectively flowing through the cooling and product streams 170 and 172; the thermodynamics of the processiwill produce a product streamithat-h a highliquid fraction If the liquid fraction is highei.e., greater than 90% 10 the methane content in the liquid will bethigh and the heavy hydrooarbons (ethane, propane, etc:) will be low thus approaching thessame composition s the incoming gas stream 12. If the liquid fraction is low, the methane content in the liquidawill be low, and the heavy hydrocarbon content in the liquid will be high The heavy hydrocarbons add more energy content to the fuel; which causes the fuel to burn hotter in combustion 15 processes The liquefaction process depicted and described with respect to FIG. 2 provides for low cost, efficient, and-effective means of producing LNG when water and/or carbon dioxide.are not present in tlhe source gas that is tobe subjectedito the liquefaction cycle. Referring now to FIG. 3, a process flow diagram is shown depicting a liquefaction 20 process-performed in accordance with another embodirpent of-a liquefaction plant 102'. As the liquefaction plant 102' and the process carried out thereby share a number of siinilarities with the plant 1,02 and process depicted in FIG. 2, likecomponents are identified with like reference numerals for sake of clarity. Liquefaction plant 102 as shown in FIG. 3 essentially modifies the basic cycle 25 shown in FIG. 2 to allow for removal of water from the natural gas stream drigg th1 e production of LNG and for prevention of ice formation throughout the syepte~n. As. illustrated intFIG:3 the water. cleanup oleincludes a sourxce-of methanol 200, or some other water absorbing product, whiehlis injected into the gas strram, via a pmp. 202,. at a locationprior to'thegas being split into the cooling stream 152 andthe propess stream 30 '154. The pump 202'desirably includes variable flow capability to inject Methanol into the gas stream preferablyvia at least one of an atomizing or aaporizing nozzle. Alternatively; valving 203 may be usedto accommodate multiple types of nozzles such that an appropriate nozzle may be-used depending on the fjow characteristics of the feed as. Preferably,-a single nozzle-is used without valving 203 when water gontert in the 35 source gas does not significantly flucuate. -13- 5 Asuitablepump 202 for injecting the methanol may include Variableflow control in the Yingd ofO.4 ft 2.5 gallons per minute (GPM) at a design pressure of approximately 100 psia fora water content of approximately 2 to 7-poundstmass per millions of standard cubic feet (Ibfn/mnscof). The variableflow control may beccomplished through the use of a-variable frequency-drive coupled to a mtor of the pump 202. -Such am exemplary 10 pump is available ftom Amerka LEWA located in Holliston; Massachuse-s. The methanol ismixed with theigas stream to lower the freeZing point of any water which maybe contained therein. The methanol mixes wit-h the gas strMea and binds with the Water to prevent the formation of ice in the cooling stream 152 during expansion in the turbo expander 156. Additiondlyj as noted; above, the. methanol is present in-the process 15 stream 154 and passes therewith through the compressor 158. About midway through the h6at exchange process (i.e., between approxiinately : 60Fiand. 90*F) the methanol and waterfoni a liquid. The compressed process stream 154' is-temporarily diverted from the heat eichanger 166 and passed through a separating tank-204 wherein the methanol/water liquid is separated frem the compressed process stream.154', the liquid being discharged 20 iluiugh a valve 206 andthe gas flowing to a-coalescing filter 208 to remove an4dditional amount of the methanol/water mixture. The methanol/water mixture may bedischarged frorn the/coaldscing filter 208 through a valve 210 with the dried gas reentering therheat exchanger 166 for further cooling and-processing:- -As is indicated byinterf-face connections '36D and 136A, both valves206 and 210 discharge the removed methanollwater mixture 25 ito piping near the plant xdit 132 for: discharge into.the downstream section 130 of the pipdine104 (see FIGA) An dkeilaycoalescing fdlter,208 usedfor removing the'methanolvwateriniixture ruf be designed t-poess-natural gas at approximately #7O 0 F tt flows of approximately 2500 SCFM and at a pressure of approximately;800 psia. Such acfiften may exhibitvan 30 efficiency of removing the methane/water mixture to less than75, ppm/w. A suitable filter is available froi Pirker Filtration, floated in Tewksbury, Massachusetts The' liquefactio1procesashownin FIG.: 3 thus provides for efficient production of natural gas bfintegrating the removal of water duringthe process-without expensive equipment and preprodessingrequired prioito the liquefaction cycle, and particularly prior 35 to the expansion of the gas through the turbihe exiander, 156. -14- 5 Referring now to FIG 4, a process flow diagram is shown depicting a liquefaction ,:process performed in accordance with another embodiment. of the liquefaction plant 102". As the plant 102" and process carried out-therein share a number of similarities with plants 102 and 102' ahd -the processesdepicted in FIGS. 2 and 3 respectively, like components areagain identified withI like reference numerals for sake of clarity, Additionally, for sake 10 of clarity, the portion of the cycle between the plant inlet 112 and the expander 156/coinpressor 158 is omitted in FIG. 4, but may be considered -an integral part of the plant 102" and'process shown in FIG. 4. The liquefaction plant 102"-shown in FIG. 4-modifies the basic cycle shown in FIG. 2 to incorporate an additional cycle for removing carbon dioxide (CQ 2 ) from the 15 natural gas stream during the production of LNG. While the plant 102" and process-of FIG. 4 are shown to indlude- the water clean-up cycle described- in reference to plant .102' andthe process of FIG. 3, the C0 clean-up cycle is not dependent on the eistence.of the water clean-up cycle and-may be independently integrated with the inventive liquefaction process. 20 ' ' The-heat exchange process may be-divided among three different heatexchangers 166,220 and 224. The first heat exchanger 220 in the flow path of the: compressed process stream 154' uses ambient conditions, such as, for- example ,air, water, or ground temperatures r a- combination thereof, for -cooling the compressed process stream 154'. The ambient condition(s) heat exchanger 220 serves to reduce, the temperature of the. 25 - compressed process stream 154' to'enisure that the-heat-generated by the-compressor 158 doesnot thermally damage the high efficiency heat. exchanger 166,which Sequentially follows the ihbient heat ekshanger 2-20' Ai -exenplary ambient heat exchanger 220 may be designed to process the coinbressed:process steam 154' at approximately 6700 tos,6800:lbs mass per ho1Ar-(lbm/hr) 30 - at a designriessure 6f approximately 800 psia The heat-exchanger 220 may fu-therbe configured such that the inlet temperature of the gas is approximately 249 0 and theoutlet teinetature of the gas is' approximately 170FF-with anambient source-temperature-(i.e., air temperate, etc.) being approxiinately100*F.;- Ifauch~a heat exchanger is provided with a fan, such may be driven:by a suitable electric motor. 35 The high efficiency-heat exchanger 166, sequentially following the ambient heat -15- 5 exchanger 220 along the flow path, may be formed as a countercurrent flow, plate and fin type heat exchanger. Additionally, the-plates and fins may be formed of a highly thermally condu tive material such as, for example, aluminum. The high efficiency heat exchanger 166 is positioned and configured to efficiently transfer as much heat as possible from-the compressed process stream 154' to.the comlned cooling stream 178'. The high 10 efficiency heat exchanger 166 may be configured such.that the inlet temperature of the gas will be approximately 1 70*F and the outlet temperature-pf the gas will be approximately 105*F. The liquefaction plant 102' is desirably configured such that temperatures generated within the high efficiency heat exchanger 166 are never low enough&to generate solid CO 2 which might-result in blockage in the flow path Qf the compressed process 15 streamA 54%, The third heat exchanger 224 sequentially located along the flow path of the process stream is, in part, associated with the processing of solid CO 2 removed from the process-stream at alater point in the cycle. More specifically, heat exchanger 224allows the CO 2 to be reintroduced into the gas pipeline 104 at the downstream section by. 20 sublimingthe-renfoved solid CO in anticipation. of its discharge back into the pipeline 104. The sublimation of solid C0 2 .in heat exchanger 224 helps to prevent damage to, or the plugging of, heat-exchanger:166. It isnoted thatheatexchangers 166 an4 224,cquld be combinedif desired. The sublimationof the.solid CQ 3 also serves to further chill the process gas in anticipation of the liquefaction thereof. 25 One exemplary heatiexchanger:224 used for processing the solid CQ 2 may include A tube-in-shell typeheat exchanger. Referring to FIQ. 5A, aqn exemplary tube-in5shel1 heat exchanger 224 constructed in accordance with the present invention is shown with a portion of the tank-230 stripped away to-eveala plurality of, in this instance three, cooling coils 232A 232C stackedivertically therein. Aglter material 234,may also be disposed in 30 the tank 230 about a portion of the lower.coil 232A to ensure that no solieCQ 2 e s the heat changer 224. The filter material 234 may include, for, example, stainless teel mesh, One or more structural:supports 236 may be placed in the tank to support the coils 232'A-232C as. may be required depending on the size and construction the coils 232A 232C.+ 35 ReferringbrieflytoFIGS.6Aand 6Baan exemplarycooling coil or coiled bundle -16- 5 232 may include- inlet/outlet pipes 238 and 240 with a plurality of individual tubing coils 242 coupled therebetween. The tubing coils 242 are -in-fluid -conmunication with each of the inlet/outlet pipes 238 and 240 and are structurally and :sealingly coupled therewith. Thus, in operation, fluid may flow into the first-inlet/outlet pipe 240 for distribution -among the plurality of tubing coils 242 and pass from the tubing coils 242 into-the 'second 10 inlet/outlet pipe 238 to be subsequently discharged therefrom. Of course, if desired, the flow throughithe cooling coils 232 couldbe-in the reverse directioh as set-forth below. An exemplary coil 232 may include, for example, inlet/outlet pipes 238 and 240 which are formed of 3 inch diameter, schedule80 304L stainless steel pipe: The tubing coils 242 may be formed of 304L stainless steel tubing having a wal thickness of 0.049 15 inches. The cooling coils 232 may further be designed aid sized to accommodate flows having, for exaMple, but not liniited to, pressures of approximately, 815 psia at a temperature between approximately -240*F and -200*F.. Such-coils 232 are available from the Graham Corporation located at Batavia, New York. 20 Referring back to FIG. 5A, the ends of the inlet1o6jtldt pipes 238 and 240 of each Pihdividial cooling coil, for example coil 232B, are sealingly and struturally coupled to s' the corresponding inlet/outlet pipes 238 and 240 of each -adjacent-coili.e, 232A and V 232C- Sich Goninection may be made, for example, by welding or by other mechanical means. 25 Referring now to FIG. 5B, theitank 230 includes a shelF 244 and end caps 246 with a plurality of inlets and outlets coupled therewith. The shell 244 and end aps 246 may be formed of, for example 304 or 304L stainless steel such that the tank 230 has a design pressure -of approximately 95 psia for operating temperatures of approximately -240*F. Desirably, the tank 230 may be designedtwith adequate corrogibr allowances for a 30 ninunmservice life of 20 ears. Fluid ihay be intriuted into th-e coiling tubes 232A4232C through one of a pair of coil inilets 248A and 250A which are respectively coupled with the inlet/outlet pipe(s) 238 and 240 of a cdolingcdoil 232A The coilihlets 248Aand 25OA inay be designed, for example, to acconfhfdate a flow of high density gas of at least approximately 5 000 lbm/hr 35 having a pressure cf approximately 750 psia at a teigeature of approximatbly-102*F. -17- 5 A set of coil outlets 248B and 250B are respectively: associated with, and sealingly coupled to, the inlet/outlet pipes 238 and 240 of a coil 232C. Eagh tube outlet 248B and 250B may be designed, for. example, to accommodate, a flow of high density fluid of at least approximately 5000 Ibm/hr having a pressure of approximately 740 psia at a temperature of approximately -205*F. 10 A plurality of tank irlets 252A-2521 are coupled with the tank 230 allowing the cooling streams 253 and 255 (FIG., 4), including removed solid. CO 2 , to enter into the tank 230 and flow over one or more coils 232A-232C. For example, tank inlets 252A-252C allow one or more of the cooling streams 253 and 255 to enter the tank 230 and flow over coil 232A, while tank inlets 252D-252F allow one or more of the cooling streams 253 and 15 255 to enter the tank 230 and flow first over coil 232B and then over coil 232A. The tank inlets 252A-2521.may bepositioned about the periphery of the shell 244 to provide a desired distribution of the cooling streams 253 and 255 with respect to the coils 232A 232C. Each tank inlet 252A-252I may be designed to accommodate flows having varying 20 characteristics. For example, tank inlet 252G may be.designed to accommodate a slurry of liquid methane having approximately 10% solisl 90 2 at a mass, flow rate of approximately 531 lbm/hr having a pressure of approximately 70 psia and a temperature of approximately -238*E1 Tan inlet 252Hgay be desigped to accommodate a flow of mixedgas, liquid and solid CO 2 at a flow rate of approximately 1012 Ibm/hr exhibiting a pressure of 25 approximately 70 psia. ans a temperature of approximately -218 0 F Tank inlet 2521 may be designed to accqmmodate a flow gf mixed gas liquid and solid (O at a flow rate of approximately 4100 lbm/hr exhibiting a pressure of approximately 70 psia and a temperature 9ogpproximatelp2.y p*. It is also notedithat,3s shown in FIG. 6A of the drawings, an termost interior 30 shell or splash jacket 292 may be formed about the cooling coils 232A-232C such that an annulus: may befqrme4 between the interior shell and thetak shell .44t.The interior shell may be configure to cpatrol the flow of theentering cooling streams trough the varipustank inlets 252A-2521 such that the cooling streams now pverthecooling coils 232A-32Cbut do not contact the tank shell 244 of reheat x langer 324.Additionally 35 . an innermost interior shell or splash jacket 294 may be formed.within the cooling coils -18- 5 232A-232C such that an'annulus may be formed between the interior of the coils and the 'inlet/outlet pipe 240. Stainless steel, such as 304L or other corrosive resistant materials are suitable for use in forming jackets 292 and/or 294. A tank outlet 254 allows fni discharge of the cooling streams 253 and 255 after they'have passed over one or more coils 232A-232C. The'tank outlet 254 may be 10 designed, for example, to accommodate a flow of gas ata Mass flow rate of approximately 5637 ibm/hr having a pressure of approximately 69 psia and a temperature of anproximately -158*F.. Referiing now to FIGS. 7A through 7C, a schematic is shown of various flow configurations possible with the heat exchanger 224. The heat exchanger 2241imay be. 15 configured such that the process stream 154' entering through the tube inlet 248A may pass through less than the total number of cooling coils 232A-232C. Thus, if it is-desired, the process stream 154"'may floW through all three cooling coils 232A-232C, onl1y two of the cooling coils 232A and 232B, or through just one of theicooling coils 232A or 250B. AFlow through the first coil 232A, appropriatepiping will allow'the procdss stream 154"' 'to 20 -exit through associated tuning outlet 250A. Similarly, ifit is desired that the process .strean 154' flow through coils 232A and 232B, it may exit throkigh associated tubing outlet148B. For example, referring to FIG. 7A, the process stream 154"'iay eitet coil inlet 248A to flow, initially, ,through the inlet/outlet pipe 240. At a location above where the 25 first coil 232A is coupled with the inlet/outlet pipe 240, a flowdiverter 25i1A blocks.'the procst stream 154"' forcing it to flow through the first cooling coil 232A. While there may be some transitory flow into the other coils 232B and 232C, the steady state- flow of the process stieanr 154"' will be through the inlt/outlet pipe 238 exiting the coil outlet 250B sind/or coil outlet '250A. 30 Referiingto FIG. 7B, it cafn be seen that the use of two floWdiverters 251A and 25 1B will cause the process stream 154"' to traverse throtigh the first coll 232A, as was described With respeef to FIG. 7A, and then flow through inlet/outletpipe 238 until it encounters the second diverter 25 iB. The second diverter will cause theprocess stream 154"' to flow through the. second oil 232B-and then through the inlet/outlet pipe 240 35 through ch coil outlet 248B... -19- 5 Referring to FIG. 7C, it is shown that the use of three flow diverters 251A-251C will cause the process stream 154"' to traverse. through the first two coils, as was described with respect to FIG. 7B, and then through inlet/o tet pipe 240 until it encounters the third diverter 251C. The third diverter will cause the process stream 154' to flow through the third. coil 232C and then through the inlet/outlet pipe 238 exiting the coil outlet 250B. 10 Thus, depending on the placement of the diveqters 251A-251C, the capacity of the heat exchanger is readily adapted.tp vaious processing conditions and output requirements. The flow diverters 251A-251C may comprise plugs, valves or blind flanges as may be appropriate. While valves or blind flange may be easily adapted to the process when located externally to the heat excitanger 224(e.g., at coil outlet 248B) it is desirable that 15 plugs be used in the internal locations (e.g., for the diverprs 251A and.251B adjacent the first and second coils:respectively). An exemplary plug 251 is shown in FIGS. 8A and 8B. Therplug 251 may be include a threaded exteriorportion 290 for engagement with a cooperatively threaded structure.within the inlet/outlet pipes 238 and 240. A keyed head 292 isconfigured to cooperatively mate with a tool for rotating the plug 251 in association 20 with the plugs' installation or removal from the inlet/outset pipes 238 and 240. Additionally, a set of interior threads 294;may be formed in the keypi head so as to lockingly engage the installation/removal tool therewith such that the plug may be disposed in an inlet/outlet.pipe 238,and 240 of substaptiallength. Furthermore, the configuration, quantity, and placement of the flow diverterA and cooling coils as discussed 25 and illustrated are .exemplary. Thus, it will be understood that a wide variety of alternative flow diverters and cooling coil arrangements can be used in accordance with the present invention. In conjunction with controlling the flow, of the process stream. 154' through the cooling coils 232A-232C, the-cooling stream(s) entering through the.tank lets 252A 30 2521 may be siplilarly controlled through appropriate valving and. piping.

Referringback, to FIG. 4, as the process stream 154"' ex jtthe het exchanger 224 throiigh line 256, it is divided into a cooling stream 170'sand a product stream 172'. The cooling strea 170'passes through a JT valve 1.74' which expands the cooling stream 170' producing various phases of CO 2 , including solid COtherein, forrning a slurry of 35 natural gas and CO 2 . This CO 2 rich slurry enters heat exchanger 224hirough oneor more -20- 5 of the tank inputs 252A-2521 to pass over one or more coils 232A-232C (see FIGS. 5A and 5B).

The product stream 172' passes through a JT valve 176' and is expanded to a low pressure, for example approximately 35 psia. The expansion via JT valve 176' also serves to lower the temperature, for example to approximately-240"F. At this ppinj in the, 10 process, solid CO 2 is formed in the product stream 172'. The expanded product stream 172", now cortaining'solid-CO 2 , enters-the liquid/vapor. separator 180wherein the vapor is. collected and removed from the separator 180 through piping 182' and added to a combined cooling stream257 for use as a refrigerant in heat exchanger-224. The liquid in the liquid/vapor separator 180 will be a slurry comprising the LNG fuel product. and solid 15 Cd2. The slurry may be removed from the separator 180 to a hydrocyclone 258 via an appro riate1y sized-and configured pump 260. Pump 260 -is primarily used to manage dVe06r generation resulting from a pressure drop through the:hydrocyclone -258.. That's pump 260 manages vapor'by taking the-cold slurry and pressurizing it to asubcooled.-state. 20 *Upon'the subcooled slurry passing through hydrocyclone 258,the slury returns to a state of equilibrium thus preventing fuel product vapor and/orvaporized C02 formation as. tesilt of the slurry experiencing a-pressure drop while passing through the hydrocyclone. * Pump 260 is schematically shown in FIG, 4 to be external to the liquid/vapor separator 180, the pump may be physically locatedwithin the liquid/vapor separator 260 if so 25 desired. In such a configuratiofi,the pump may be submersed in the lower portipn of the separator 180. A sUitable pump may be configured to have an adjustableflow rate.-of approximately 2to 6.2.gallons per minute (gpm) of LNG with a differential pressure of 80 psi while operating at -240*F. The adjustableflow rateinay be controlled by meansof a variable frequency drive.' Such an- exemplary pump is available from Barber-Nichols 30 located in Atvada Colorado. The hydr66yclone 258 acts as a separator to remove.the solid C2 om the slurry allowing the-NG product fuel to be colleted -and stored,. An exemplary hydrocyclone 258 iay be design ed, for example, to operate at a pressure of approximately 125 psia at a temperature of approximately -238

*

F-.The.hydrocyclone 25&8;uses a pressure drop-to 35 create a centrifugal force which separates the solids from the liquid- A thickened slush, -21- 5 formed of a portion of the liquid natural gas-with the solid CO 2 , exits the hydrocyclone 2584hrough an underflow 262. The remainder of the liquid natural gas is passed through an overflow 264 for additional filtering. A slight pressure differential, for example, approximately 0.5 psi, exists between the underflow 2Q and the overflow 264 of the hydrocyclone. Thus, for examplethe thickened slush may exit the underflow 262 at 10 approximately 40.5 psia with the liquid natural gas editing the oyerflow 264 at approximately, 4 0 psia. However, other pressure differentials may be more suitable depending df the specific hydrocyclone 258 utilized. A control valve 265 may be positioned at the overflow.264 of the hydrocyclone-258 to assist in controlling the pressure differential experienced within the hydrocyclone 258. 15 A suitable hydrocyclone 258 is available, for example, from Krebs Engineering of Tucson, Arizona. An exemplary hydrocyclone may be configured to operate at design pressures of-up to: approximately 125 psi ,within, temperature range of approxinatly 100F to -3009F. Additionally, an exeinplary hydrocyclone desirably includes an interior which is mricro-polished to an:8-12 micro inch finish otbetter. 20 Theliquid-natural gas passes through one of a plurality, in tls instace twQ, CO 2 screen filters 266A and 266B placed in parallel. The screen. filters 266A and 2663 capture any remaining solid CQi which may not have been separated put in the hydrocyclone.258. Referring briefly to FIG. 9, an exemplary screen filter 266 may be formed of 6 inch. schedule'40 stainless steel pipe.268 andinclude a first filter screen 270 f coarse stainless 25 steel mesh, a second conical shaped filter screen 272 of stainless steel, mesh less coarse than the first filter screen 270, and a third filter screen 274 formed of fine, stainless steel mesh. For exayiple, in.one embodiment, the first filter screen 270 may beformed of 50 to 75-mdsh stainless steel, the second filter:screen 272 may be formed of 75 to .100 mesh stainless steel and the third filter screen 274 May be formed qf 100 to 150 meshtainless 30 steel. In another embodiment, two of the filter screens 270 and 274 maybe formed of the same grade of. mesh;for example 40,mesh stainless steel or fiper, and packed in a. less dise or more dense manner to get the desired effect. Thaties,, filter screen 47Q can be fabricated froma mesh blanket or screensthat is-rolled, relatively loosely to provide a less dense, or-less-surface area, packing and filter screen 274 can be.fabricated from the same 35 mesh blanket or screen material but rolled more tightly to produce more dense, or higher -22- 5 surface area packing. The CO 2 screen filters266A and 266Bmay, from tine tQ time, become' clogged or plugged with slid CO 2 captured therein. Thus, as one filteriie., 266Ais being. sed to capture CO 2 from the liquid natural gas sttearn, the other filter; Le., .3266Bmay be purged of Od by passing a relatively high temperature natural gas therethroughin a counter 10 flowingg fashion. For example, gas rmay be drawn after the-water cleanr-p cycle through a fourth heat exchanger 275 as indicated at interface points 276C and 276B to flow through and clean the-CO 2 screen filter 266B. Gas may be flowed through one or more pressure regulating Valves 277 prior to passing through the heat exchanger 275 and into the CO screen filter 266B as may be dictated by pressure and flow conditionsavithin theprocess. 15 Durincldaning of the filter 266B, the cleaning gas may.be discharged-back to coif-type heat exchanger 224 ar iswindicated bylintrface connections 301,B and3QIC. Appropriate valving and piping allows for-the fi-lters 266A and 266B to be switched and -4solated ffromone another ashay be required. Other methods of removing CQ solids that 1iave cnmufated on the fltedr ate readily known by those of ordinary skill in the art. 20 The filtered liquid natural gas exits the plant 102" for storage as described above herein. A fail open-type valve 279-maybe placed between-the lines comingfrom-the plant linlet and outlet as a fail safedevice in case of upset conditions either within the plant.102" or from extemalt sources; such as the tank 116 (FIG. 1). The thickened slush formed in the hydrocyclone 258 exitsthe underflow 262 and 25 passes'through piping 278 to heat exchanger 224 where it helps to~.ool the process stream 154' flowing therethrough. Vapor passing through line 182' from theliquid/vapor separator 10 passes through-aback pressure control valve 280A and-is combine d-with a opbrtion of gas drawn 6ff heat.exchanger 224 through line 259 to form a combined cooling Itrea 257: Thecombined cooling stream -257 flowing through line,259 further serves as 30 "make-up" to keep ductor 282 working correctly if the flow rate through back pressure control valve 280A is too low: -Baekpressure cont-ol valve 250B is preferably set-a. couple to a few psi higherhan pressure covtl Valve 280A to keep; otbined cooling trean257 moving-in the orret direcion.: The co mbined cooling stream 257 thenpasses bthiough an-eductor 282. A motive stre.anv284 , drawn.-from the Orocess stream .between 35 the high efficiency heat exchahger 166 and coil-type heat exehanger;224, also flows -23- 24 through the eductor and serves to draw the combined cooling stream 257 into one or more of the tank inlets,252A-2521 (FIG. 5B). An exemplary eductor 282 may be configured to operate at a pressure of approximately 764 psia and a temperature of approximately -105'F for the motive stream, and pressure of 5 approximately 35 psia and temperature of approximately -240"F for the suction stream with a discharge pressure of approximately 69 psia. Such an eductor is available from Fox Valve Development Corp. of Dover, New Jersey. The C02 slurries introduced into heat exchanger 224, either via cooling stream 170', combined cooling stream 257 or underflow stream 278, flow 10 downwardly through the heat exchanger 224 over one or more or cooling coils 232A-232C causing the solid C02 to sublime. This produces a cooling stream 286 that has a temperature high enough to eliminate solid C02 therein. The cooling stream 286 exiting heat exchanger 224 is combined with the expanded cooling stream 152' from the turbo 156 expander to form combined cooling 15 stream 178' which is used to cool compressed process stream 154' in the high efficiency heat exchanger 166. Upon exiting the heat exchanger 166, the combined cooling stream 178' is further combined with various other gas components flowing through interface connection 136A, as described throughout herein, for discharge into the downstream section 130 of the 20 pipeline 104 (FIG. 1). Referring now to FIG. 10, a liquefaction plant 102' according to another embodiment is shown. The liquefaction plant 102"' operates essentially in the same manner as the liquefaction plant 102' of FIG. 4 with some minor modifications. 25 A fourth heat exchanger 222 is located along the flow path of the process stream sequentially between high efficiency heat exchanger 166' and heat exchanger 224. Heat exchanger 222 is associated with the removal of C02 and serves primarily to heat solid C02 which is removed from the process stream at a later point in the cycle, as shall be discussed in greater detail 30 below. The fourth heat exchanger 222 also assists in cooling the gas in preparation for liquefaction and C02 removal. The thickened slush formed in the hydrocyclone 258 exits the underflow 262 and passes through piping 278' to heat exchanger 222, wherein the density of the thickened sludge is reduced. As the C02 slurry exits heat Y:\BEH\722661\spec2OO2 346035.doc 24a exchanger 222 it combines with any vapor entering through plant inlet 128 (from tank 116 shown in FIG. 1) as well as vapor passing YABEH\722861spe2002 348035.doc 5 through line 182' from the liquid/vapor separator 180 forming combined cooling stream 257'. The combined cooling stream 257' passes through a back pressure control valve 280A and then through anl eductor 282. A motive stream; 284', drawn from the process stream between heat exchanger 222 and heat exchanger 224, also flows through the eductor and serves to draw the combined cooling stream 158 into one ormore of the tank 10 inlets 252A-252I (FIG. 5B). As with the embodiment described in reference to FIG. 4 the CO 2 slurries introduced into heat exchanger 224, either via cooling stream 170 or combined cooling stream 257, flow downwardly through the heat exchanger 224 over one or more cooling coils 232A-232C causing the solid- CO 2 to. sublime. This produces a cooling stream 286 15 that has-a temperiture high enough to eliminate solidCO 2 therein. The cooling stream exiting heat exchanger 224 is combined with the expanded cooling stream 152' from the turbo 156 expaider to form combined cooling stream 18' whichis -used to cool compressed process stream 154' in the high efficiency heat exchanger 166. Upon exiting the hdat exchanger 166, the combined cooling stream 178' isfurther combined with 20 various other gas components flowing through interface connection- 136A, asdescribed throughout herein, fot discharge into the downstreamsection' 130'of the pipeline 104 (FIG. ). As with embodinents discussed above the CO 2 screen filters 26,6A and 266B may require cleaningor purging froM tiine-t time. However, in the embodiment shown in 25 FIG. 10, gas may be drawn after the water clean-up cycle at interface-point 2760-and'enter into-iterfack point 276A or 276B to flow through and-clpan CO 2 screen filters 266A or 266B. During cleaning of the filter 266B,. the cleaning gas maybediseharged baekvto the pipeline 104 (FIG.1) as is indicated byinterface connections 136Eer 13:6F and 1%3A. Appropriate'valving Andpiping allows for the filters 266A and 266B-!o beiswitchedland 30 indlated frinhe another as may be required. Other methods ofremoving CO 2 solids that have accumulated orthe filters are readily.known by-those df ordinary skill in-the art. The filtered-liquid nattiral:gas exits4he plAi't102" for storage as describedabove herein. Referringiow to FIGS. 14 A and -2,. a differential pressure, circuit 300 of plant 102!" is shown. The differential pressure circuit 30is-designed.to balance the flow 35 entering the JT valve 176just prior to the liqiidA'apor separator-180 based on the -25- 5 pressure difference between the compressed process stream 154' and the product stream 172'. The JT valve 174' located along cooling stream 170' acts as the primary control valve passing a majority of the-mass flow exiting'from heat exchanger 224 in order to maintain the correct temperature. in the product stream 172'. During normal operating conditions; it is assumed that gas-will always be flowing through JT valve 174'. Opening 10 up JT valve 174' increases the flow back into heat exchanger 224 and consequently decreases the temperature in product stream 172',. Conversely, restricting the flow through JT valve 174' will result in an increased temperature in product stream 172'. JT valve 176'- located-in the product stream 172' serves to, balance any excess flow in the product stream 172' due to variations, for example, in controlling the temperature of 15 the product stream 172' or from surges experienced due to operation of the compressor 158. A pressure differential control (PDC) valve 302 is disposed between,:anid coupled to the compressed process stream 154' and the product stream 172' (as is also indicated by interface connections 301A and 301B in FIGA.).. A pilot line 304 is coupled between the 20 low pressure side 306 of the PDC valve 302,and the pilot 308,of JT valve 176'., Both the PDC valve 302 and the pilot 308;of IT valve 176' are biased (i.e., with spr igs) for pressure offsets to compensate for pressure losses experienced by the flow of the process stream 154' through the-circuit-containing heat exchangers 16, 22 (if used) and 224. The following are examples of how the: differential pressure circuit 300 may 25 behave in certain exemplary situations. In onre situation, the pressure and flow increase in the compressed prqcess stream 154' due- to fluctuations in the compressor-158. As pressure inereas.s in the compressed process stream 154', the high side 310 of the PDC valve 302 causes the PDQ ya,v.ef 02 to operr, thereby increasing the pressure within the pilot line 304 and htle pilot 308of JT 30 valve 176'.. After flowing through the variousheat exchangers a new pressure will result ih the product- stream 172'. With flow-being maintained by ST valve 174',v eessive process fluid builtip in the product stream 172' willresut in less prssuredoss across the heat exchangers, bringing the pressure in the product stream 172' elqspr to the pressure exhibited by the compressed process stream 154'. The increased pressure in the-product 35 stream 172' will be sensed by the PDCsvalve 302-and cause it-to close thereby overpming -26- 5 the pressure in the pilot line 304 and the biasing element of the pilot 308. As a result, JT valve 176' will open and increase the flowvtherethrough. As flow increases through JT valve 176' the pressure in-the product stream 172' will be reduced. na second scenario, the pressure and flow are in a steady state condition in the compressed processstream 154'. In this case the compressor will providezmore flow than. 10 will be removed by'JT valve 174', resulting in an increase in pressure in the product stream 172'. As the pressure builds in the product stream, the PDC:302 valve and JT valve 176' will react as described above with respect to the first scenario to reduce the pressure in the product stream 172'. In a third scenario, JT valve 174' suddenly opens, magnifying the pressure loss 15 across the heat exchangers 224 and .166 and thereby reducing the pressure in the product stream 172'. The loss of pressure in the product stream 172' will be sensed by the PDC valve:302,;thereby actuatingthe pilot 308 such that JT valve 176' closes until the flow comes back into equilibrium. In a fourth scenario, JT valve 174' suddenly closes, causingta pressure spike in-the 20 product stream 172'. In this case, the pressure increase will be sensed by the PDC valve 302, thereby actuating the pilot 308 and causing JT valve 176' to open and release.the eXcess pressure/flow until the pressure and flow are back in equilibrium. In a fifth scenario, the pressure decreases in the compressedsprocess stream.154' due to fluctuations in the compressor. This-will cause the circuit 300 to respond such that 25 JT valve 176' momentarily closes until the pressure and flow;balance out in the product stream 172' The JT valve 174" is a significant componentsof the differential pressure circuit 300 as it sees to maintain-the split between cooling stream 170' and product stream: 172' subsequent the flow of compressed process stream 154'through heat exchanger 224. JT 30 valve 174':accoriplishes this by maintaining the temperature of the stream inline 256 exiting heat:exchanger 224. As the temperature in line 256 (and thus in coQling stream 170 and process stream 1727) drops below a desired temperature, the flow through. JT valve 174' mayte adjusted toprovide less cooling. to heat exchanger 224. Conversely as the temperature in line 256 raises above a desired temperature, the flow throughJT valve 35 174' may be adjusted to provide additional cooling to heat exchanger 224. -27- 28 Referring now to FIG. 11 B, a preferred circuit 300' is shown. The operation of circuit 300' is generally the same as circuit 300 described above, however instead of using mechanical control, circuit 300' is electrical-pneumatically controlled. The primary differences between circuit 300 and 300' include replacing pressure sense 5 lines 370 and 372 with pressure sensors 374 and 376 and electrical leads 370' and 372'. Furthermore, the differential pressure regulator 302 and control line 304 are replaced by an electrical controller 302' and an electro-pneumatic sense line 304' and pilot 308 is replaced with a current-to-pneumatic (l/P) pilot control 308'. It should be noted that when using circuit 300 or circuit 300' will work with any number of heat 10 exchangers that would provide a pressure drop from 154' to 172'. Referring now to FIG. 12, a liquefaction plant 102' "'and process is shown according to another embodiment. The liquefaction plant 102' "' operates essentially in the same manner as the liquefaction plant 102' of FIG. 10 with some minor modifications. Rather than passing the thickened CO 2 slush from the hydrocyclone 15 258 through a heat exchanger 222 (FIG.10), a pump 320 accommodates the flow of the thickened CO 2 slush back to heat exchanger 224. The configuration of plant 102' " eliminates the need for an additional heat exchanger (i.e., 222 of FIG. 10). However, flow of the thickened CO 2 slush may be limited by the capacity of the pump and the density of the thickened slush in the configuration shown in FIG. 10. 20 Referring now to FIG. 13, an exemplary physical configuration of plant 102" described in reference to FIG. 4 is according to one embodiment thereof. Plant 102" is shown without siding or a roof for viewability. Substantially an entire plant 102" may be mounted on a supporting structure such as a skid 330 such that the plant 102" may be moved and transported as needed. Pointing out some of the major 25 components of the plant 102", the turbo expander 156/compressor 158 is shown on the right hand portion of the skid 330. A human operator 332 is shown next to the turbo expander 156/compressor 158 to provide a general frame of reference regarding the size of the plant 102". Generally, the overall plant may be configured, for example, to be approximately 30 feet long, 17 feet high and 8.5 feet wide. 30 However, the overall plant may be sized smaller or larger as desired. The high efficiency heat exchanger 166 and the heat exchanger 224 used for YABEH\72266t1spec12002 346035.doc 5 sublimation of solid CO' are found on the left hand side of the skid 330. The parallel CO filters 266A and 226B can be seen adjacent heat exchanger 224. Wiring 334,may extend from the skid 330 to a remote location, such. as. a separate pad 335 or control room, for controlling-various components, such as, for example; the turbo expander 156/compressor 158, as will be appreciated and understood by-those of skill in the art. Additionally, 10 pneumatic and/or hydraulic lines might extend from the skid 330 for control or external power input as may be desired. It is noted that by remotely locating the controls, or at least some of the controls, costs may be reduced as such remotely locate controls-and instruments need not have, for example, explosion proof enclosures or other safety features as would be required if located on the skid 330.. 15 It is alfs' noted that'a framework 340 may be mounted on the skid 330 and configured to substantially encompassthe plant 102". A first section 342, exhibiting a first height, is shown to substantially encompass the volume around-the turbo expander 156 and compressor 158. A second section 344 substantially encompasses the volume around the heat exchangers-166, 224; filters 266A and 266B and other components which 20 operate at reduced temperatures. The second section 344 includes-two subsections:344A and~344B with subsection 344A being substantiallyequivalent in height'td section 342. Subsection 344B extends above the height of section 342 and may be removable for,. purposes of transportation as-discussed below. The piping associated with the-plant102" may be insnlated fbr purposes minimizing unwanted heatstransfer Alternatively, or in 25 combination with insulated pipes and selected components, an. insulated wall 346 -may separate section 342 from section'344 and from the external-environs-of the plant 102". Additionally, insulated walls may be placed on the framework 340 about the exterior of the plant 102" to insulate at least a pdrtion of the plant 102" from ambient temperature conditions which might reduce the efficiency of the plant 102". Furthermore, various 30 componentsrnaylb individually insulated-in addition tb interconnecting piping, including but not limited to.,separation tank-180, filter modules 266ABe and heat exchangers 166 *-and 224. Referring now tb-FIG. 14, the-plant 102", or a substantial portion thereof, may, for example, be- loaded onto a trailer 350 to be transported by truck 352 to a plantsite 35 Alternativelyi thelsuppbrting structure may serve as the trailer with the skid 330 -29- 5 configured with wheels, suspension and a hitch to mount to the truck tractor 352 at one end, and a second set of Wheels 354 at the opposing end. Other means of transport will be readily apparent to those having ordinary skill in the art. It is noted that upper subsection 344B has been removed, and, while not explicitly shown in the drawing, some larger components such.as the high efficiency heat exchanger 10 166 and the solid CO 2 processing heat exchanger 224 have been removed. This p9tentially allows the plant to be transported without any special permits (i.e,, wide load, oversized load, etc.) while keeping the plant substantially intact. It is further noted that the plant may include controls such that minimal operator input is required. Indeed, it may be desirable that. any plant 102-102."' function without an 15 on-site operator. Thus,.with proper programing and controlidesign, the-plant.may be accessed through remote telemetry for monitoring and/or adjusting the operation of the plant. Similarly, various alarms may be built into such controls so as to alert a remote operator or to shutdown the plant in an upset condi-tion. -One suitablp0ontroller, for example, may be a DL405 series programable logic controller (PLC) commercially 20 available from.Automation Direct of Cumming,:Georgig. While the invention has'been disclosed primarily interms of liquefaction of natural gas, it is noted that the present invention may be utilized simply for removal of gas components, such:as, for example,. CO 2 from a stream of relatively "di4y" gas.. Additionally, other gases may-be processed. and other gascomponents, such as, for 25 example, nitrogen, may be removed. Thus; the present invention is not limited to the liquefaction of natural gas and the removal qf CO 2 therefrom. EXAMPLE Referring now to FIGS. 4 and 15, an. example of the process carried ougtin the 30 liquefaction plant 102" is set forth. It is noted that FIG. 14 is the same process flow diagram as FIG 4 (combined with the additional eotnponents of FIG. 3.- e.g. the compressor 154 and expander 156 etc.) but with component reference numerals o-mited or clarity As the general process.has been describ,ed above with reference to FIG. 4, the following. example will set forthexemplaryeconditions of the gas/liquid/slurry a0 various 35 locations throughout the plant-, referred to herein.asstate points, according-to the -30- 5 calculated operational design of the plant 102". At state point 400, as the gas leaves distribution pipeline and enters the liquefaction plant the gas will be approximately 60 0 Fat a pressure of approximately 440 psia with aiflow of approximately 10,00 lbmlhr:' At state points 402 and 404, the flow will be split such that approximately 5,065 10 lbm/hiflows throligh state point 402 and approximately 4,945 ibm/hr flows through state point 404 with temperatures and pressures of each state point-being similar to that of state point 400. At state point 406, as the stream exits the turboexpander 156, the gas will be approximately -104*F at a pressure ofapproximately 65 psia, At state point 408, as the 15 gas exits the compressor 158, the gas will be approximately 187F at.a pressure of approximately 770 psia. At state point 410, after the first heat exchanger 220 arid prior to the high efficiencyheat exchanger 166, the gas will be approximately:175"E at a pressure of approximately 770 psia. At state point 412, after water cleanup and about midway 20 through the hi'h efficiency heat dxchanger1 66, the gas will be approximately -70*F at a pressure of appr-ximately 766 psia and exhibit a flow rate of approximately 4,939 Ibm/hr. The gas exiting the high- efficiency heat exchanger 166, as shown at state point 4-4, will be appfoxinately 405*F -at a pressure of approximately 763--psia. The flowIhrough the product stream 172' at state point 418 will'be approximately 25 -205*F at pressure of approximately 761 psia-with a flow rate of approximately 3,735:: lbm/hr. At state point 420, after passing through the Joule-Thomson valve, and prior to entering the separator 180, the stream will become a mixture of gas, liquid natural gas, and' solid CO 2 and will be approximately-240*Fat a pressure of approximately 35 psia. The slurry of solid C02 and liquid natural gas will have similar temperatures and pressures as 30 it leaves the-separator 180, however, it will have a flow rate of approximately 1,324 libm/hr. At state point 422, the pressute of the slurry will be raised, via the pump 260;'to a pressure of approximately 114 psia and a temperature of approximately -236"F. At state point424, after being separated via the hydrocyclone 158, the liquid'natural gas willbe 35 approximately -240*F'at a pressure of approximately 35 psia with a flow rate of -31- 5 approximately 1,059 lbm/hr. The state of the liquid natural gas will remain substantially the same as it exits the plant 102" into a storage vessel. At state point-426 the thickened slush (including solid C0 2 ) exiting the hydrocyclone 258 will be approximately -235*F at a pressure of approximately -68.5 psia and will flow at a rate of approximately 265 ibm/hr. 10 At state point 430, the gas exiting the separator 180 will be approximately 240*F at a pressure'of approximately 35 psia with a flow rate of approximately 263 lbm/hr. At state point 434, thergas in the motive stream entering into the eductor will be approximately -105*F at approximately 764 psia. The flow rate at state point 434 will be 15 . approximately 1,205 lbm/hr. At state point 436, subsequent the eductori the mixed stream will be approximately -217*F at approximately 70 psia with a combined flow rate of approximately 698, lbm/hr.. At state point 438, prior to JT valve 174', the gas will be aproximately -205*F at a pressure of approximately 761 psig with a flow rate of approximately 2,147 lbm/hr. At 20 state point 440, after passing through JT valve 174' whereby solid , C02is formed, the slurry will be approximately -221"F with a pressure of approximately 685 psia. At state point 442, upon exiting heat exchanger 224, the temperature of the gas will be approximately -195*F and the pressure will be approximately 65 psia. The flow rate at state point 442 will be approximately 3,897 Ibm/hr. At state point 444, after combining 25 two streams, the gas will have a temperature of approximately -15 1*F anda pressure of approximately 65 psia. At state point 446, upon exit from the high efficiency heat exchanger 146, and prior to discharge into the pipeline 104, the gas will ,ave a temperature of approximately 99*F and pressure of approximately 65.psia. The flow rate at state point 446 will be 30 approximately 8,962 ibm/hr. In light of the above disclosure it will be appreciated that the liquefaction process depicted ind described, herein provides for low cost, efficient and effective means of producing LNG without the requisite "purification" of the gas before subjecting the gas to the liquefaction cycle. Such allows the usdof relatively "dirty" gas typically found in 35 residential and industrial service lines, and eliminates the requirement for expensive -32- 33 pretreatment equipment and provides a significant reduction in operating costs for processing such relatively "dirty" gas. While the invention may be susceptible to various modifications and alternative forms, specific embodiments which have been shown by way of example in the 5 drawings and have been described in detail herein, it should be understood that the invention is not intended to be limited to the particular forms disclosed. Rather, the invention includes all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the following appended claims. Throughout the description and claims of the specification the word "comprise" 10 and variations of the word, such as "comprising" and "comprises", is not intended to exclude other additives, components, integers or steps. C of\xwordSPEC-825981.doc

Claims (29)

1. A liquefaction plant including: a plant inlet configured to be sealingly and fluidly coupled with a source of 5 unpurified natural gas; a turbo expander positioned and configured to receive a first stream of natural gas drawn through the plant inlet and produce an expanded cooling stream therefrom; a compressor mechanically coupled to the turbo expander and positioned and configured to receive a second stream of natural gas drawn through the plant inlet 10 and produce a compressed process stream therefrom; a high efficiency countercurrent flow heat exchanger positioned and configured to receive the compressed process stream and the expanded cooling stream in a countercurrent flow arrangement to cool the compressed process stream; a tube-in-shell heat exchanger positioned and configured to receive the cooled 15 compressed process stream therethrough, the tube-in-shell heat exchanger including a plurality of vertically stacked corrosion resistant coils within a corrosion resistant tank and at least one diverter valve, the at least one diverter valve for maintaining continuous flow through one coil of the plurality of coils and transitory flow through at least one other coil of the plurality of coils of the tube-in-shell heat exchanger; 20 a first plant outlet positioned and configured to be sealingly and fluidly coupled with the source of unpurified gas and to discharge the expanded cooling stream thereinto subsequent to passage thereof through the high efficiency countercurrent flow heat exchanger; a first expansion valve positioned and configured to receive and expand a first 25 portion of the cooled compressed process stream to form an additional cooling stream, the plant further including conduit structure to combine the additional cooling stream with the expanded cooling stream prior to the expanded cooling stream entering the high efficiency countercurrent flow heat exchanger; a second expansion valve positioned and configured to receive and expand a 30 second portion of the cooled compressed process stream to form a mixed gas, liquid natural gas and solid carbon dioxide therefrom; a first gas-liquid separator positioned and configured to receive the mixed gas, liquid natural gas and solid carbon dioxide; and C:\poword\SPEC-825981doc 35 a second plant outlet positioned and configured to be sealingly and fluidly coupled with a storage vessel, the first gas-liquid separator being positioned and configured to deliver a liquid contained therein to the second plant outlet. 5

2. The liquefaction plant of claim 1, further including a hydrocyclone operably coupled between the first gas-liquid separator and the second plant outlet.

3. The liquefaction plant of claim 2, further including a pump operably coupled between the hydrocyclone and the first gas-liquid separator to manage the state of a 10 liquid to be introduced to the hydrocyclone.

4. The liquefaction plant of claim 2 or 3, further including at least one screen filter disposed between the hydrocyclone and the second plant outlet. 15

5. The liquefaction plant of claim 4, further including a filter configured to remove water, the liquid filter being disposed within a flowpath of the compressed process stream at a position along the flowpath within the high efficiency countercurrent flow heat exchanger. 20

6. The liquefaction plant of claim 5, further including a second gas-liquid separator disposed within the flowpath of the compressed processing stream adjacent the liquid filter.

7. The liquefaction plant of claim 6, wherein the high efficiency countercurrent 25 flow heat exchanger includes a plurality of corrosion resistant plates.

8. The liquefaction plant of claim 1, wherein at least one of the plurality of vertically stacked corrosion resistant coils includes stainless steel. 30

9. The liquefaction plant of claim 8, wherein the corrosion resistant tank includes stainless steel. C:\Aort\SPEC-825981.doc 36

10. The liquefaction plant of claim 8 or 9, wherein the tube-in-shell heat exchanger includes at least one innermost splash jacket positioned within at least one of the vertically stacked corrosion resistant coils. 5

11. The liquefaction plant of claim 10, wherein the at least one innermost splash jacket includes stainless steel.

12. The liquefaction plant of any one of claims 8 to 11, wherein the tube-in-shell heat exchanger includes at least one outermost splash jacket positioned between at 10 least one of the vertically stacked corrosion resistant coils and the corrosion resistant tank.

13. The liquefaction plant of claim 12 wherein the at least one outermost splash jacket includes stainless steel. 15

14. The liquefaction plant of any one of claims 8 to 13, further including a support structure, wherein the turbo expander, the compressor, the high efficiency countercurrent flow heat exchanger, the tube-in-shell heat exchanger, the hydrocyclone, the at least one screen filter, the liquid filter, the first gas-liquid 20 separator and the second gas-liquid separator are each carried on the support structure.

15. The liquefaction plant of any one of claims 8 to 14, wherein the support structure is approximately 8 feet wide and approximately 30 feet long. 25

16. The liquefaction plant of claim 15, further including a framework mounted to the support structure, the framework substantially defining an outer volumetric periphery of the liquefaction plant. 30

17. The liquefaction plant of claim 16, wherein the framework exhibits a nominal height of approximately 17 feet. CaPofAworSPEC-825981 doc 37

18. The liquefaction plant of claim 17, wherein the framework includes at least a first portion and a second removable portion, wherein the second removable portion may be removed to reduce the maximum height of the framework. 5

19. The liquefaction plant of any one of claims 16 to 18, further including at least one insulated wall mounted to the framework positioned such that the turbo expander and compressor are located on a first side of the at least one insulated wall and the high efficiency countercurrent flow heat exchanger and the tube-in-shell heat exchanger are positioned on a second opposing side of the at least one insulated 10 wall.

20. The liquefaction plant of claim 19, wherein the plant is configured to be transportable as a substantially intact unit. 15

21. The liquefaction plant of any one of claims 16 to 20, further including a control unit configured to facilitate remote telemetry monitoring and control of the plant.

22. The liquefaction plant of any one of claims 14 to 21 further including component interconnect piping that is individually insulated. 20

23. The liquefaction plant of claim 22, further including a least one of the turbo expander, the compressor, the high efficiency countercurrent flow heat exchanger, the tube-in-shell heat exchanger each being individually insulated. 25

24. A method of producing liquid natural gas, the method including: providing a source of unpurified natural gas; flowing a portion of natural gas from the source; dividing the portion of natural gas into a process stream and a first cooling stream; 30 flowing the first cooling stream through a turbo expander having an expanded first cooling stream exiting therefrom and producing work output therefrom; powering a compressor with the work output of the turbo expander; flowing the process stream through the compressor having a compressed process stream exiting therefrom; C:\ofwrd\SPEC-825981 doc 38 cooling the compressed processed stream with at least the first expanded cooling stream using a plurality of heat exchangers, the plurality of heat exchangers including a high efficiency heat exchanger cooling the compressed process stream to a cooled stream of natural gas having a temperature that does not generate solid carbon 5 dioxide therein and a tube-in-shell heat exchanger cooling the cooled stream from the high efficiency heat exchanger forming a cooled process stream of natural gas, the tube-in-shell heat exchanger having a plurality of coils of tubing therein; maintaining a steady state flow of at least a portion of the cooled stream from the high efficiency heat exchanger through one coil of the plurality of coils of tubing of 10 the tube-in-shell heat exchanger; maintaining a steady state flow of at least a portion of the cooled stream from the high efficiency heat exchanger through one coil of the plurality of coils of tubing of the tube-in-shell heat exchanger; diverting some of the flow of at least a portion of the cooled stream from the 15 high efficiency heat exchanger through at least one other coil of the plurality of coils of tubing of the tube-in-shell heat exchanger; dividing the cooled compressed process stream from the tube-in-shell heat exchanger into a product stream and a second cooling stream; expanding the second cooling stream and combining the expanded second 20 cooling stream with the expanded first cooling stream; expanding the product stream to form a mixture including mixed gas, liquid natural gas and solid carbon dioxide; separating liquid natural gas and solid carbon dioxide from the mixed gas, liquid natural gas and solid carbon dioxide forming a thickened slush used for cooling 25 in the tube-in-shell heat exchanger; and separating at least a portion of the liquid natural gas from the solid carbon dioxide and liquid natural gas.

25. The method according to claim 24 wherein separating the at least a portion of 30 the liquid natural gas from the solid carbon dioxide includes subjecting the solid carbon dioxide and liquid natural gas to a centrifugal force. C\pofAwrd\SPEC-825981doc 39

26. The method according to claim 25, further including combining the solid carbon dioxide and at least another portion of the liquid natural gas with the expanded first cooling stream and the expanded second cooling stream forming a combined cooling stream. 5

27. The method according to claim 26, further including discharging the combined cooling stream back into the source of unpurified natural gas.

28. A liquefaction plant in accordance with any one of the embodiments 10 substantially as herein described.

29. A method in accordance with any one of the embodiments substantially as herein described. 15 20 C:\powOrd\SPEC-825981 doc