Motor driven compressor system for natural gas liquefaction

Abstract
Natural gas liquefaction system employing electric motors as compressor drivers. A combination of motors and steam turbines can be powered by a cogeneration plant and employed as drivers.
Description




BACKGROUND OF THE INVENTION




1. Field of the Invention




This invention concerns a method and an apparatus for liquefying natural gas. In another aspect, the invention concerns an improved driver, compressor, and power source configurations for a cascade-type natural gas liquefaction plant.




2. Description of the Prior Art




The cryogenic liquefaction of natural gas is routinely practiced as a means of converting natural gas into a more convenient form for transportation and storage. Such liquefaction reduces the volume by about 600-fold and results in a product which can be stored and transported at near atmospheric pressure.




With regard to ease of storage, natural gas is frequently transported by pipeline from the source of supply to a distant market. It is desirable to operate the pipeline under a substantially constant and high load factor but often the deliverability or capacity of the pipeline will exceed demand while at other times the demand may exceed the deliverability of the pipeline. In order to shave off the peaks where demand exceeds supply or the valleys when supply exceeds demand, it is desirable to store the excess gas in such a manner that it can be delivered when the supply exceeds demand. Such practice allows future demand peaks to be met with material from storage. One practical means for doing this is to convert the gas to a liquefied state for storage and to then vaporize the liquid as demand requires.




The liquefaction of natural gas is of even greater importance when transporting gas from a supply source which is separated by great distances from the candidate market and a pipeline either is not available or is impractical. This is particularly true where transport must be made by ocean-going vessels. Ship transportation in the gaseous state is generally not practical because appreciable pressurization is required to significantly reduce the specific volume of the gas. Such pressurization requires the use of more expensive storage containers.




In order to store and transport natural gas in the liquid state, the natural gas is preferably cooled to −240° F. to −260° F. where the liquefied natural gas (LNG) possesses a near-atmospheric vapor pressure. Numerous systems exist in the prior art for the liquefaction of natural gas in which the gas is liquefied by sequentially passing the gas at an elevated pressure through a plurality of cooling stages whereupon the gas is cooled to successively lower temperatures in sequential refrigeration cycles until the liquefaction temperature is reached. Cooling is generally accomplished by heat exchange with one or more refrigerants such as propane, propylene, ethane, ethylene, methane, nitrogen or combinations of the preceding refrigerants (e.g., mixed refrigerant systems). A liquefaction methodology which is particularly applicable to the current invention employs a closed propane cycle as the initial refrigeration cycle, a closed ethylene cycle as the intermediate refrigerant cycle, and an open methane cycle as the final refrigeration cycle. In the open methane cycle a pressurized LNG-bearing stream is flashed and the flash vapors (i.e., the flash gas stream(s)) are subsequently employed as cooling agents, recompressed, cooled, combined with the processed natural gas feed stream and liquefied thereby producing the pressurized LNG-bearing stream.




Each of the refrigeration cycles of a cascade-type natural gas liquefaction plant includes a compressor, or a set of compressors, for increasing the pressure of the refrigerant after it has been used to cool the natural gas. The high pressure refrigerant exiting the compressor(s) is first cooled via indirect heat exchange and then expanded prior to being employed as a cooling agent to cool the natural gas stream. The refrigerant compressors employed in LNG plants are typically powered by large gas turbines such as, for example, Frame


5


or Frame


7


gas turbines that are available from GE Power Systems of Atlanta, Ga.




Although conventional gas turbines provide efficient power production, the use of gas turbine drivers in LNG plants has several drawbacks. For example, “off-the-shelf” gas turbines are available only in predetermined fixed sizes (i.e., load ratings) and it is generally too expensive to have a gas turbine custom designed and manufactured for a certain load requirement. Thus, in many instances commercially available gas turbines are either oversized or undersized for the given application in a LNG plant. This mismatching of optimum design load and actual plant load can require oversized gas turbines to be employed in a LNG plant. Such oversized gas turbines are typically more expensive than would be required if the actual plant load and designed turbine load were the same. Further, operating an oversized gas turbine at less than optimum design load causes the gas turbine to be less efficient.




Another disadvantage of employing gas turbine drivers to power the refrigerant compressors in a LNG plant is that the burning of fuel in the gas turbines causes emissions (e.g., NO


x


and SO


2


) that must be monitored in order to comply with local environmental standards. With the increasing stringency of emissions regulations, it can be difficult and expensive to monitor and comply with such regulations.




A further disadvantage of using gas turbines in LNG plants is the fact that only a handful of companies make suitable gas turbines. Thus, availability of an appropriately sized turbine can be severely limited if the demand for that particular turbine is high.




Another drawback of using gas turbines to power compressors in a LNG plant is that gas turbines can be difficult and time consuming to start up.




OBJECTS AND SUMMARY OF THE INVENTION




It is, therefore, an object of the present invention to provide a novel natural gas liquefaction system employing mechanical drivers that can be cost-effectively tailored to suit specific load requirements of the LNG plant.




A further object of the invention is to provide a novel natural gas liquefaction system having reduced emissions due to the use of low-emissions mechanical drivers.




Another object of the invention is to provide a novel natural gas liquefaction system employing mechanical drivers that are readily available from multiple sources throughout the world.




Still another object of the invention is to provide a novel natural gas liquefaction system employing mechanical drivers that are easy and quick to start.




It should be noted that the above objects are exemplary and need not all be accomplished by the claimed invention. Other objects and advantages of the invention will be apparent from the written description and drawings.




Accordingly, in one embodiment of the present invention, there is provided a process for liquefying natural gas comprising the steps of: (a) driving a first compressor and a second compressor with a first electric motor; (b) driving a third compressor and a fourth compressor with a second electric motor; (c) compressing a first refrigerant of a first refrigeration cycle in the first and third compressors; and (d) compressing a second refrigerant of a second refrigeration cycle in the second and fourth compressors.




In another embodiment of the present invention, there is provided a process for liquefying natural gas comprising the steps of: (a) generating steam and electricity in a cogeneration plant; (b) using at least a portion of the electricity to power a first electric motor; (c) using at least a portion of the steam to power a first steam turbine; (d) compressing a first refrigerant of a first refrigeration cycle in a first compressor driven by the first electric motor; and (e) compressing a second refrigerant of a second refrigeration cycle in a second compressor driven by the first steam turbine.




In still another embodiment of the present invention, there is provided an apparatus for liquefying natural gas by cooling the natural gas via a plurality of sequential refrigeration cycles. The apparatus comprises first, second, and third refrigeration cycles and first, second, and third electric motors. The first, second, and third refrigeration cycles include first, second, and third compressors for compressing first, second, and third refrigerants respectively. The first, second, and third electric motors are operable to drive the first, second, and third compressors respectively. The first refrigerant comprises in major portion a hydrocarbon selected from the group consisting of propane, propylene, and mixtures thereof. The second refrigerant comprises in major portion a hydrocarbon selected from the group consisting of ethane, ethylene, and mixtures thereof. The third refrigerant comprises in major portion methane.




In a still further embodiment of the present invention, there is provided an apparatus for liquefying natural gas by cooling the natural gas via a plurality of sequential refrigeration cycles. The apparatus comprises a first refrigeration cycle, a second refrigeration cycle, a cogeneration plant, a first electric motor, and a first steam turbine. The first refrigeration cycle includes a first compressor for compressing a first refrigerant. The second refrigeration cycle includes a second compressor for compressing a second refrigerant. The cogeneration plant is operable to simultaneously generate electricity and steam. The first electric motor is drivably coupled to the first compressor and is powered by at least a portion of the electricity generated by the cogeneration plant. The first steam turbine is drivingly coupled to the second compressor and is powered by at least a portion of the steam generated by the cogeneration plant.











BRIEF DESCRIPTION OF THE DRAWING FIGURES




A preferred embodiment of the present invention is described in detail below with reference to the attached drawing figures, wherein:





FIG. 1

is a simplified flow diagram of a cascaded refrigeration process for LNG production which employs a novel driver and compressor system. The numbering scheme in

FIG. 1

can be summarized as follows:






100


-


199


: Conduits for primarily methane streams






200


-


299


: Equipment and vessels for primarily methane streams






300


-


399


: Conduits for primarily propane streams






400


-


499


: Equipment and vessels for primarily propane streams






500


-


599


: Conduits for primarily ethylene streams






600


-


699


: Equipment and vessels for primarily ethylene streams






700


-


799


: Mechanical drivers





FIG. 2

is a simplified flow diagram similar to

FIG. 1

illustrating an alternative driver and power system for a LNG plant. The numbering scheme employed in

FIG. 2

is identical to that in

FIG. 1

, except in

FIG. 2

numerals


900


-


999


identify the drivers while numerals


1000


-


1099


identify the power system.





FIG. 3

is a simplified flow diagram similar to

FIGS. 1 and 2

illustrating an alternative driver and power system for a LNG plant. The numbering scheme employed in

FIG. 3

is identical to that in

FIGS. 1 and 2

, except in

FIG. 3

numerals


1100


-


1199


identify the drivers while numerals


1200


-


1299


identify the power system.











DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT




As used herein, the term open-cycle cascaded refrigeration process refers to a cascaded refrigeration process comprising at least one closed refrigeration cycle and one open refrigeration cycle where the boiling point of the refrigerant/cooling agent employed in the open cycle is less than the boiling point of the refrigerating agent or agents employed in the closed cycle(s) and a portion of the cooling duty to condense the compressed open-cycle refrigerant/cooling agent is provided by one or more of the closed cycles. In the current invention, methane or a predominately methane stream is employed as the refrigerant/cooling agent in the open cycle. This stream is comprised of the processed natural gas feed stream and the compressed open methane cycle gas streams.




The design of a cascaded refrigeration process involves a balancing of thermodynamic efficiencies and capital costs. In heat transfer processes, thermodynamic irreversibilities are reduced as the temperature gradients between heating and cooling fluids become smaller, but obtaining such small temperature gradients generally requires significant increases in the amount of heat transfer area, major modifications to various process equipment and the proper selection of flow rates through such equipment so as to ensure that both flowrates and approach and outlet temperatures are compatible with the required heating/cooling duty.




One of the most efficient and effective means of liquefying natural gas is via an optimized cascade-type operation in combination with expansion-type cooling. Such a liquefaction process is comprised of the sequential cooling of a natural gas stream at an elevated pressure, for example about 625 psia, by sequentially cooling the gas stream by passage through a multistage propane cycle, a multistage ethane or ethylene cycle, and an open-end methane cycle which utilizes a portion of the feed gas as a source of methane and which includes therein a multistage expansion cycle to further cool the same and reduce the pressure to near-atmospheric pressure. In the sequence of cooling cycles, the refrigerant having the highest boiling point is utilized first followed by a refrigerant having an intermediate boiling point and finally by a refrigerant having the lowest boiling point. As used herein, the term “propane chiller” shall denote a cooling system that employs a refrigerant having a boiling point the same as, or similar to, that of propane or propylene. As used herein, the term “ethylene chiller” shall denote a cooling system that employs a refrigerant having a boiling point the same as, or similar to, that of ethane or ethylene. As used herein, the terms “upstream” and “downstream” shall be used to describe the relative positions of various components of a natural gas liquefaction plant along the flow path of natural gas through the plant.




Various pretreatment steps provide a means for removing undesirable components, such as acid gases, mercaptan, mercury, and moisture from the natural gas feed stream delivered to the facility. The composition of this gas stream may vary significantly. As used herein, a natural gas stream is any stream principally comprised of methane which originates in major portion from a natural gas feed stream, such feed stream for example containing at least 85 percent methane by volume, with the balance being ethane, higher hydrocarbons, nitrogen, carbon dioxide and a minor amounts of other contaminants such as mercury, hydrogen sulfide, and mercaptan. The pretreatment steps may be separate steps located either upstream of the cooling cycles or located downstream of one of the early stages of cooling in the initial cycle. The following is a non-inclusive listing of some of the available means which are readily available to one skilled in the art. Acid gases and to a lesser extent mercaptan are routinely removed via a sorption process employing an aqueous amine-bearing solution. This treatment step is generally performed upstream of the cooling stages in the initial cycle. A major portion of the water is routinely removed as a liquid via two-phase gas-liquid separation following gas compression and cooling upstream of the initial cooling cycle and also downstream of the first cooling stage in the initial cooling cycle. Mercury is routinely removed via mercury sorbent beds. Residual amounts of water and acid gases are routinely removed via the use of properly selected sorbent beds such as regenerable molecular sieves.




The pretreated natural gas feed stream is generally delivered to the liquefaction process at an elevated pressure or is compressed to an elevated pressure, that being a pressure greater than 500 psia, preferably about 500 psia to about 900 psia, still more preferably about 500 psia to about 675 psia, still yet more preferably about 600 psia to about 675 psia, and most preferably about 625 psia. The stream temperature is typically near ambient to slightly above ambient. A representative temperature range being 60° F. to 138° F.




As previously noted, the natural gas feed stream is cooled in a plurality of multistage (for example, three) cycles or steps by indirect heat exchange with a plurality of refrigerants, preferably three. The overall cooling efficiency for a given cycle improves as the number of stages increases but this increase in efficiency is accompanied by corresponding increases in net capital cost and process complexity. The feed gas is preferably passed through an effective number of refrigeration stages, nominally two, preferably two to four, and more preferably three stages, in the first closed refrigeration cycle utilizing a relatively high boiling refrigerant. Such refrigerant is preferably comprised in major portion of propane, propylene or mixtures thereof, more preferably the refrigerant comprises at least about 75 mole percent propane, even more preferably at least 90 mole percent propane, and most preferably the refrigerant consists essentially of propane. Thereafter, the processed feed gas flows through an effective number of stages, nominally two, preferably two to four, and more preferably two or three, in a second closed refrigeration cycle in heat exchange with a refrigerant having a lower boiling point. Such refrigerant is preferably comprised in major portion of ethane, ethylene or mixtures thereof, more preferably the refrigerant comprises at least about 75 mole percent ethylene, even more preferably at least 90 mole percent ethylene, and most preferably the refrigerant consists essentially of ethylene. Each cooling stage comprises a separate cooling zone. As previously noted, the processed natural gas feed stream is combined with one or more recycle streams (i.e., compressed open methane cycle gas streams) at various locations in the second cycle thereby producing a liquefaction stream. In the last stage of the second cooling cycle, the liquefaction stream is condensed (i.e., liquefied) in major portion, preferably in its entirety thereby producing a pressurized LNG-bearing stream. Generally, the process pressure at this location is only slightly lower than the pressure of the pretreated feed gas to the first stage of the first cycle.




Generally, the natural gas feed stream will contain such quantities of C


2


+components so as to result in the formation of a C


2


+rich liquid in one or more of the cooling stages. This liquid is removed via gas-liquid separation means, preferably one or more conventional gas-liquid separators. Generally, the sequential cooling of the natural gas in each stage is controlled so as to remove as much as possible of the C


2


and higher molecular weight hydrocarbons from the gas to produce a gas stream predominating in methane and a liquid stream containing significant amounts of ethane and heavier components. An effective number of gas/liquid separation means are located at strategic locations downstream of the cooling zones for the removal of liquids streams rich in C


2


+components. The exact locations and number of gas/liquid separation means, preferably conventional gas/liquid separators, will be dependant on a number of operating parameters, such as the C


2


+composition of the natural gas feed stream, the desired BTU content of the LNG product, the value of the C


2


+components for other applications and other factors routinely considered by those skilled in the art of LNG plant and gas plant operation. The C


2


+hydrocarbon stream or streams may be demethanized via a single stage flash or a fractionation column. In the latter case, the resulting methane-rich stream can be directly returned at pressure to the liquefaction process. In the former case, this methane-rich stream can be repressurized and recycle or can be used as fuel gas. The C


2


+hydrocarbon stream or streams or the demethanized C


2


+hydrocarbon stream may be used as fuel or may be further processed such as by fractionation in one or more fractionation zones to produce individual streams rich in specific chemical constituents (ex., C


2


, C


3


, C


4


and C


5


+).




The pressurized LNG-bearing stream is then further cooled in a third cycle or step referred to as the open methane cycle via contact in a main methane economizer with flash gases (i.e., flash gas streams) generated in this third cycle in a manner to be described later and via expansion of the pressurized LNG-bearing stream to near atmospheric pressure. The flash gases used as a refrigerant in the third refrigeration cycle are preferably comprised in major portion of methane, more preferably the refrigerant comprises at least about 75 mole percent methane, still more preferably at least 90 mole percent methane, and most preferably the refrigerant consists essentially of methane. During expansion of the pressurized LNG-bearing stream to near atmospheric pressure, the pressurized LNG-bearing stream is cooled via at least one, preferably two to four, and more preferably three expansions where each expansion employs as a pressure reduction means either Joule-Thomson expansion valves or hydraulic expanders. The expansion is followed by a separation of the gas-liquid product with a separator. When a hydraulic expander is employed and properly operated, the greater efficiencies associated with the recovery of power, a greater reduction in stream temperature, and the production of less vapor during the flash step will frequently more than off-set the more expensive capital and operating costs associated with the expander. In one embodiment, additional cooling of the pressurized LNG-bearing stream prior to flashing is made possible by first flashing a portion of this stream via one or more hydraulic expanders and then via indirect heat exchange means employing said flash gas stream to cool the remaining portion of the pressurized LNG-bearing stream prior to flashing. The warmed flash gas stream is then recycled via return to an appropriate location, based on temperature and pressure considerations, in the open methane cycle and will be recompressed.




When the pressurized LNG-bearing stream, preferably a liquid stream, entering the third cycle is at a preferred pressure of about 550-650 psia, representative flash pressures for a three stage flash process are about 170-210, 45-75, and 10-40 psia. Flashing of the pressurized LNG-bearing stream, preferably a liquid stream, to near atmospheric pressure produces an LNG product possessing a temperature of about −240° F. to −260° F.




A cascaded process uses one or more refrigerants for transferring heat energy from the natural gas stream to the refrigerant and ultimately transferring said heat energy to the environment. In essence, the overall refrigeration system functions as a heat pump by removing heat energy from the natural gas stream as the stream is progressively cooled to lower and lower temperatures.




The liquefaction process may use one of several types of cooling which include but is not limited to (a) indirect heat exchange, (b) vaporization, and (c) expansion or pressure reduction. Indirect heat exchange, as used herein, refers to a process wherein the refrigerant cools the substance to be cooled without actual physical contact between the refrigerating agent and the substance to be cooled. Specific examples of indirect heat exchange means include heat exchange undergone in a shell-and-tube heat exchanger, a core-in-kettle heat exchanger, and a brazed aluminum plate-fin heat exchanger. The physical state of the refrigerant and substance to be cooled can vary depending on the demands of the system and the type of heat exchanger chosen. Thus, a shell-and-tube heat exchanger will typically be utilized where the refrigerating agent is in a liquid state and the substance to be cooled is in a liquid or gaseous state or when one of the substances undergoes a phase change and process conditions do not favor the use of a core-in-kettle heat exchanger. As an example, aluminum and aluminum alloys are preferred materials of construction for the core but such materials may not be suitable for use at the designated process conditions. A plate-fin heat exchanger will typically be utilized where the refrigerant is in a gaseous state and the substance to be cooled is in a liquid or gaseous state. Finally, the core-in-kettle heat exchanger will typically be utilized where the substance to be cooled is liquid or gas and the refrigerant undergoes a phase change from a liquid state to a gaseous state during the heat exchange.




Vaporization cooling refers to the cooling of a substance by the evaporation or vaporization of a portion of the substance with the system maintained at a constant pressure. Thus, during the vaporization, the portion of the substance which evaporates absorbs heat from the portion of the substance which remains in a liquid state and hence, cools the liquid portion.




Finally, expansion or pressure reduction cooling refers to cooling which occurs when the pressure of a gas, liquid or a two-phase system is decreased by passing through a pressure reduction means. In one embodiment, this expansion means is a Joule-Thomson expansion valve. In another embodiment, the expansion means is either a hydraulic or gas expander. Because expanders recover work energy from the expansion process, lower process stream temperatures are possible upon expansion.




The flow schematic and apparatus set forth in

FIG. 1

is a preferred embodiment of the inventive liquefaction process. Those skilled in the art will recognized that

FIG. 1

is a schematic representation only and therefore, many items of equipment that would be needed in a commercial plant for successful operation have been omitted for the sake of clarity. Such items might include, for example, compressor controls, flow and level measurements and corresponding controllers, temperature and pressure controls, pumps, motors, filters, additional heat exchangers, and valves, etc. These items would be provided in accordance with standard engineering practice.




To facilitate an understanding of

FIG. 1

, the following numbering nomenclature is employed. Items numbered


100


-


199


correspond to flow lines or conduits which contain primarily methane. Items numbered


200


-


299


are process vessels and equipment which contain and/or operate on a fluid stream comprising primarily methane. Items numbered


300


-


399


correspond to flow lines or conduits which contain primarily propane. Items numbered


400


-


499


are process vessels and equipment which contain and/or operate on a fluid stream comprising primarily propane. Items numbered


500


-


599


correspond to flow lines or conduits which contain primarily ethylene. Items numbered


600


-


699


are process vessels and equipment which contain and/or operate on a fluid stream comprising primarily ethylene. Items numbered


700


-


799


are mechanical drivers.




Referring to

FIG. 1

, a natural gas feed stream, as previously described, enters conduit


100


from a natural gas pipeline. In an inlet compressor


202


, the natural gas is compressed and air cooled so that the natural gas exiting compressor


202


has a pressure generally in the range of from about 500 psia to about 800 psia and a temperature generally in the range of from about 75° F. to about 175° F. The natural gas then flows to an acid gas removal unit


204


via conduit


102


. Acid gas removal unit


204


preferably employs an amine solvent (e.g., Diglycol Amine) to remove acid gases such as CO


2


and H


2


S. Preferably, acid gas removal unit


204


is operable to remove CO


2


down to less than 50 ppmv and H


2


S down to less than 2 ppmv. After acid gas removal, the natural gas is transferred, via a conduit


104


, to a dehydration unit


206


that is operable to remove substantially all water from the natural gas. Dehydration unit


206


preferably employs a multi-bed regenerable molecular sieve system for drying the natural gas. The dried natural gas can then be passed to a mercury removal system


208


via conduit


106


. Mercury removal system


208


preferably employs at least one fixed bed vessel containing a sulfur impregnated activated carbon to remove mercury from natural gas. The resulting pretreated natural gas is introduced to the liquefaction system through conduit


108


.




As part of the first refrigeration cycle, gaseous propane is compressed in first and second multistage propane compressors


400


,


402


driven by first and second electric motor drivers


700


,


702


, respectively. The three stages of compression are preferably provided by a single unit (i.e., body) although separate units mechanically coupled together to be driven by a single driver may be employed. Upon compression, the compressed propane from first and second propane compressors


400


,


402


are conducted via conduits


300


,


302


, respectively, to a common conduit


304


. The compressed propane is then passed through common conduit


304


to a cooler


404


. The pressure and temperature of the liquefied propane immediately downstream of cooler


404


are preferably about 100-130° F. and 170-210 psia. Although not illustrated in

FIG. 1

, it is preferable that a separation vessel be located downstream of cooler


404


and upstream of an expansion valve


406


for the removal of residual light components from the liquefied propane. Such vessels may be comprised of a single-stage gas liquid separator or may be more sophisticated and comprised of an accumulator section, a condenser section and an absorber section, the latter two of which may be continuously operated or periodically brought on-line for removing residual light components from the propane. The stream from this vessel or the stream from cooler


404


, as the case may be, is pass through a conduit


306


to a pressure reduction means such as expansion valve


406


wherein the pressure of the liquefied propane is reduced thereby evaporating or flashing a portion thereof. The resulting two-phase product then flows through conduit


308


into high-stage propane chiller


408


for indirect heat exchange with gaseous methane refrigerant introduced via conduit


158


, natural gas feed introduced via conduit


108


, and gaseous ethylene refrigerant introduced via conduit


506


via indirect heat exchange means


239


,


210


, and


606


, thereby producing cooled gas streams respectively transported via conduits


160


,


110


and


312


.




The flashed propane gas from chiller


408


is returned to the high stage inlets of first and second propane compressors


400


,


402


through conduit


310


. The remaining liquid propane is passed through conduit


312


, the pressure further reduced by passage through a pressure reduction means, illustrated as expansion valve


410


, whereupon an additional portion of the liquefied propane is flashed. The resulting two-phase stream is then fed to an intermediate-stage propane chiller


412


through conduit


314


, thereby providing a coolant for chiller


412


.




The cooled natural gas feed stream from high-stage propane chiller


408


flows via conduit


110


to a knock-out vessel


210


wherein gas and liquid phases are separated. The liquid phase, which is rich in C3+components, is removed via conduit


112


. The gaseous phase is removed via conduit


114


and conveyed to intermediate-stage propane chiller


412


. Ethylene refrigerant is introduced to chiller


412


via conduit


508


. In chiller


412


, the processed natural gas stream and an ethylene refrigerant stream are respectively cooled via indirect heat exchange means


214


and


608


thereby producing a cooled processed natural gas stream and an ethylene refrigerant stream via conduits


116


and


510


. The thus evaporated portion of the propane refrigerant is separated and passed through conduit


316


to the intermediate-stage inlets of propane compressors


400


,


402


. Liquid propane is passed through conduit


318


, the pressure further reduced by passage through a pressure reduction means, illustrated as expansion valve


414


, whereupon an additional portion of liquefied propane is flashed. The resulting two-phase stream is then fed to a low-stage propane chiller/condenser


416


through conduit


320


thereby providing coolant to chiller


416


.




As illustrated in

FIG. 1

, the cooled processed natural gas stream flows from intermediate-stage propane chiller


412


to low-stage propane chiller/condenser


416


via conduit


116


. In chiller


416


, the stream is cooled via indirect heat exchange means


216


. In a like manner, the ethylene refrigerant stream flows from intermediate-stage propane chiller


412


to low-stage propane chiller/condenser


416


via conduit


510


. In the latter, the ethylene refrigerant is condensed via an indirect heat exchange means


610


in nearly its entirety. The vaporized propane is removed from low-stage propane chiller/condenser


416


and returned to the low-stage inlets of propane compressors


400


,


402


via conduit


322


. Although

FIG. 1

illustrates cooling of streams provided by conduits


116


and


510


to occur in the same vessel, the chilling of stream


116


and the cooling and condensing of stream


510


may respectively take place in separate process vessels (ex., a separate chiller and a separate condenser, respectively).




As illustrated in

FIG. 1

, a portion of the cooled compressed open methane cycle gas stream is provided via conduit


162


, combined with the processed natural gas feed stream exiting low-stage propane chiller/condenser


416


via conduit


118


, thereby forming a liquefaction stream and this stream is then introduced to a high-stage ethylene chiller


618


via conduit


120


. Ethylene refrigerant exits low-stage propane chiller/condenser


416


via conduit


512


and is fed to a separation vessel


612


wherein light components are removed via conduit


513


and condensed ethylene is removed via conduit


514


. Separation vessel


612


is analogous to the earlier vessel discussed for the removal of light components from liquefied propane refrigerant and may be a single-stage gas/liquid separator or may be a multiple stage operation resulting in a greater selectivity of the light components removed from the system. The ethylene refrigerant at this location in the process is generally at a temperature in the range of from about −15° F. to about −30° F. and a pressure in the range of from about 270 psia to about 300 psia. The ethylene refrigerant, via conduit


514


, then flows to a main ethylene economizer


690


wherein it is cooled via indirect heat exchange means


614


and removed via conduit


516


and passed to a pressure reduction means, such as an expansion valve


616


, whereupon the refrigerant is flashed to a preselected temperature and pressure and fed to high-stage ethylene chiller


618


via conduit


518


. Vapor is removed from this chiller via conduit


520


and routed to main ethylene economizer


690


wherein the vapor functions as a coolant via indirect heat exchange means


619


. The ethylene vapor is then removed from ethylene economizer


690


via conduit


522


and fed to the high-stage inlets of first and second ethylene compressors


600


,


602


. The ethylene refrigerant which is not vaporized in high-stage ethylene chiller


618


is removed via conduit


524


and returned to ethylene economizer


690


for further cooling via indirect heat exchange means


620


, removed from ethylene economizer


690


via conduit


526


and flashed in a pressure reduction means, illustrated as expansion valve


622


, whereupon the resulting two-phase product is introduced into a low-stage ethylene chiller


624


via conduit


528


. The liquefaction stream is removed from the high-stage ethylene chiller


618


via conduit


122


and directly fed to low-stage ethylene chiller


624


wherein it undergoes additional cooling and partial condensation via indirect heat exchange means


220


. The resulting two-phase stream then flows via conduit


124


to a two phase separator


222


from which is produced a methane-rich vapor stream via conduit


128


and, via conduit


126


, a liquid stream rich in C


2


+components which is subsequently flashed or fractionated in vessel a


224


thereby producing, via conduit


132


, a heavies stream and a second methane-rich stream which is transferred via conduit


164


and, after combination with a second stream via conduit


150


, is fed to high-stage methane compressors


234


,


236


.




The stream in conduit


128


and a cooled compressed open methane cycle gas stream provided via conduit


129


are combined and fed via conduit


130


to a low-stage ethylene condenser


628


wherein this stream exchanges heat via indirect heat exchange means


226


with the liquid effluent from low-stage ethylene chiller


624


which is routed to low-stage ethylene condenser


628


via conduit


532


. In condenser


628


, the combined streams are condensed and produced from condenser


628


, via conduit


134


, is a pressurized LNG-bearing stream. The vapor from low-stage ethylene chiller


624


, via conduit


530


, and low-stage ethylene condenser


628


, via conduit


534


, are combined and routed via conduit


536


to main ethylene economizer


690


wherein the vapors function as a coolant via indirect heat exchange means


630


. The stream is then routed via conduit


538


from main ethylene economizer


690


to the low-stage inlets of ethylene compressors


600


,


602


. As noted in

FIG. 1

, the compressor effluent from vapor introduced via the low-stage inlets of compressors


600


,


602


is removed, cooled via inter-stage coolers


640


,


642


, and returned to ethylene compressors


600


,


602


for injection with the high-stage stream present in conduit


522


. Preferably, the two-stages are a single module although they may each be a separate module and the modules mechanically coupled to a common driver. The compressed ethylene product from ethylene compressors


600


,


602


is routed to a common conduit


504


via conduits


500


and


502


. The compressed ethylene is then conducted via common conduit


504


to a downstream cooler


604


. The product from cooler


604


flows via conduit


506


and is introduced, as previously discussed, to high-stage propane chiller


408


.




The pressurized LNG-bearing stream, preferably a liquid stream in its entirety, in conduit


134


is generally at a temperature in the range of from about −140° F. to about −110° F. and a pressure in the range of from about 600 psia to about 630 psia. This stream passes via conduit


134


through a main methane economizer


290


wherein the stream is further cooled by indirect heat exchange means


228


as hereinafter explained. From main methane economizer


290


the pressurized LNG-bearing stream passes through conduit


136


and its pressure is reduced by a pressure reductions means, illustrated as expansion valve


229


, which evaporates or flashes a portion of the gas stream thereby generating a flash gas stream. The flashed stream is then passed via conduit


138


to a high-stage methane flash drum


230


where it is separated into a flash gas stream discharged through conduit


140


and a liquid phase stream (i.e., pressurized LNG-bearing stream) discharged through conduit


166


. The flash gas stream is then transferred to main methane economizer


290


via conduit


140


wherein the stream functions as a coolant via indirect heat exchange means


232


. The flash gas stream (i.e., warmed flash gas stream) exits main methane economizer


290


via conduit


150


where it is combined with a gas stream delivered by conduit


164


. These streams are then fed to the inlets of high-stage methane compressors


234


,


236


. The liquid phase in conduit


166


is passed through a second methane economizer


244


wherein the liquid is further cooled via indirect heat exchange means


246


by a downstream flash gas stream. The cooled liquid exits second methane economizer


244


via conduit


168


and is expanded or flashed via a pressure reduction means, illustrated as expansion valve


248


, to further reduce the pressure and at the same time, evaporate a second portion thereof. This flash gas stream is then passed to intermediate-stage methane flash drum


250


where the stream is separated into a flash gas stream passing through conduit


172


and a liquid phase stream passing through conduit


170


. The flash gas stream flows through conduit


172


to second methane economizer


244


wherein the gas cools the liquid introduced to economizer


244


via conduit


166


via indirect heat exchanger means


252


. Conduit


174


serves as a flow conduit between indirect heat exchange means


252


in second methane economizer


244


and indirect heat exchange means


254


in main methane economizer


290


. The warmed flash gas stream leaves main methane economizer


290


via conduit


176


which is connected to the inlets of intermediate-stage methane compressors


256


,


258


. The liquid phase exiting intermediate stage flash drum


250


via conduit


170


is further reduced in pressure, preferably to about 25 psia, by passage through a pressure reduction means, illustrated as an expansion valve


260


. Again, a third portion of the liquefied gas is evaporated or flashed. The fluids from the expansion valve


260


are passed to final or low stage flash drum


262


. In flash drum


262


, a vapor phase is separated as a flash gas stream and passed through conduit


180


to second methane economizer


244


wherein the flash gas stream functions as a coolant via indirect heat exchange means


264


, exits second methane economizer


244


via conduit


182


which is connected to main methane economizer


290


wherein the flash gas stream functions as a coolant via indirect heat exchange means


266


and ultimately leaves main methane economizer


290


via conduit


184


which is connected to the inlets of low-stage methane compressors


268


,


270


. The liquefied natural gas product (i.e., the LNG stream) from flash drum


262


which is at approximately atmospheric pressure is passed through conduit


178


to the storage unit. The low pressure, low temperature LNG boil-off vapor stream from the storage unit is preferably recovered by combining such stream with the low pressure flash gases present in either conduits


180


,


182


, or


184


; the selected conduit being based on a desire to match gas stream temperatures as closely as possible. In accordance with conventional practice, the liquefied natural gas (LNG) in the storage unit can be transported to a desired location (typically via an ocean-going LNG tanker). The LNG can then be vaporized at an onshore LNG terminal for transport in the gaseous state via conventional natural gas pipelines.




As shown in

FIG. 1

, methane compressors


234


,


236


,


256


,


258


,


268


,


270


preferably exist as separate units that are mechanically coupled together to be driven by two drivers


704


,


706


. The compressed gas from the low-stage methane compressors


268


,


270


passes through inter-stage coolers


280


,


282


and is combined with the intermediate pressure gas in conduit


176


prior to the second-stage of compression. The compressed gas from intermediate-stage methane compressors


256


,


258


is passed through inter-stage coolers


284


,


286


and is combined with the high pressure gas provided via conduit


150


prior to the third-stage of compression. The compressed gas (i.e., compressed open methane cycle gas stream) is discharged from high-stage methane compressors


234


,


236


through conduits


152


,


154


and are combined in conduit


156


. The compressed methane gas is then cooled in cooler


238


and is routed to high-stage propane chiller


408


via conduit


158


as previously discussed. The stream is cooled in chiller


408


via indirect heat exchange means


239


and flows to main methane economizer


290


via conduit


160


. As used herein and previously noted, compressor also refers to each stage of compression and any equipment associated with interstage cooling.




As illustrated in

FIG. 1

, the compressed open methane cycle gas stream from chiller


408


which enters main methane economizer


290


undergoes cooling in its entirety via flow through indirect heat exchange means


240


. A portion of this cooled stream is then removed via conduit


162


and combined with the processed natural gas feed stream upstream of high-stage ethylene chiller


618


. The remaining portion of this cooled stream undergoes further cooling via indirect heat transfer means


242


in main methane economizer


290


and is produced therefrom via conduit


129


. This stream is combined with the stream in conduit


128


at a location upstream of ethylene condenser


628


and this liquefaction stream then undergoes liquefaction in major portion in the ethylene condenser


628


via flow through indirect heat exchange means


226


.




As illustrated in

FIG. 1

, it is preferred for first propane compressor


400


and first ethylene compressor


600


to be driven by a single first electric motor


700


, while second propane compressor


402


and second ethylene compressor


602


are driven by a single second electric motor


702


. First and second electric motors


700


,


702


can be any suitable commercially available electric motor. It can be seen from

FIG. 1

that both the propane compressors


400


,


402


and the ethylene compressors


600


,


602


are fluidly connected to their respective propane and ethylene refrigeration cycles in parallel, so that each compressor provides full pressure increase for approximately one-half of the refrigerant flow employed in that respective refrigeration cycle. Such a parallel configuration of multiple propane and ethylene compressors provides a “two-trains-in-one” design that significantly enhances the availability of the LNG plant. Thus, for example, if it is required to shut down first electric motor


700


for maintenance or repair, the entire LNG plant need not be shut down because second electric motor


702


, second propane compressor


402


, and second ethylene compressor


602


can still be used to keep the plant online.




Such a “two-trains-in-one” philosophy is further indicated by the use of two drivers


704


,


706


to power methane compressors


234


,


236


,


256


,


258


,


268


,


270


. A third electric motor


704


is used to power first high-stage methane compressor


234


, first intermediate-stage methane compressor


256


, and first low-stage methane compressor


268


, while a fourth electric motor


706


is used to power second high-stage methane compressor


236


, second intermediate-stage methane compressor


258


, and second low-stage methane compressor


270


. Third and fourth electric motors


704


,


706


can be any suitable commercially available electric motor. It can be seen from

FIG. 1

that first methane compressors


234


,


256


,


268


are fluidly connected to the open methane refrigeration cycle in series with one another and in parallel with second methane compressors


236


,


258


,


270


. Thus, first methane compressors


234


,


256


,


268


cooperate to provide full pressure increase for approximately one-half of the methane refrigerant flow in the open methane refrigeration cycle, with each first compressor


268


,


256


,


234


providing an incremental portion of such full pressure increase. Similarly, second methane compressors


236


,


258


,


270


cooperate to provide full pressure increase for the other approximately one-half of the methane refrigerant flow in the open methane refrigeration cycle, with each second compressor


270


,


258


,


236


providing an incremental portion of such full pressure increase. Such a configuration of methane drivers and compressors is consistent with the “two-trains-in-one” design philosophy. Thus, for example, if it is required to shut down third electric motor


704


for maintenance or repair, the entire LNG plant need not be shut down because fourth electric motor


706


and second methane compressors


236


,


258


,


270


can still be used to keep the plant online.




Various methods may be used to assist in starting-up electric motors


700


,


702


,


704


,


706


. The inertial and fluid drag forces associated with the initial turning of electric motors


700


,


702


,


704


,


706


and their associated compressor during start-up can be difficult to overcome. Thus, a variable frequency drive may be coupled to electric motors


700


,


702


,


704


,


706


to aid in start-up. Another method of assisting in start-up can include evacuating the compressors to minimize fluid drag forces that resist turning of the motors during start-up. Further, fluid couplings or torque converters can be placed between the motors and the compressors so that the motors can be started with little or no load from the compressors and then, when the motors are up to speed, the fluid couplings or torque converters can gradually apply the compressor load to the motors. If a torque converter is employed, it is preferred for the torque converter to use a mechanical lock-out mechanism that allows the electric motor and associated compressors to be directly mechanically coupled to one another once the motor and compressors are up to speed.




Referring now to

FIG. 2

, an alternative embodiment of the natural gas liquefaction system is illustrated. Although many components of the natural gas liquefaction system illustrated in

FIG. 2

are the same as those illustrated in

FIG. 1

, the system of

FIG. 2

employs an alternative driver and power system. The majority of the components in

FIG. 2

(i.e., components


100


-


699


) are the same as the components in FIG.


1


and are identically enumerated.




The natural gas liquefaction system illustrated in

FIG. 2

employs a cogeneration plant


1000


that is operable to simultaneously generate energy in the form of thermal energy (i.e., steam) and electrical energy via combustion of a fuel such as, for example, natural gas. First propane compressor


400


and first ethylene compressor


600


are driven by a first electric motor


900


, while second propane compressor


402


and second ethylene compressor


602


are driven by a second electric motor


902


. Electric motors


900


,


902


are powered with at least a portion of the electricity generated by cogeneration plant


1000


and conducted to motors


900


,


902


via electrical lines


1002


,


1003


,


1005


.




A first steam turbine


904


is used to power first high-stage compressor


234


, first intermediate-stage methane compressor


256


, and first low-stage methane compressor


268


, while a second steam turbine


906


is used to power second high-stage methane compressor


236


, second intermediate-stage methane compressor


258


, and second low-stage methane compressor


270


. Steam turbines


904


,


906


are powered with at least a portion of the steam generated by cogeneration plant


1000


and conducted to steam turbines


904


,


906


via steam conduits


1004


,


1006


,


1008


.




A first starter/helper motor


908


can be drivingly coupled to first electric motor


900


, while a second starter/helper motor


910


can be drivingly coupled to second electric motor


902


. Starter/helper motors


908


,


910


can operate in either a starting mode, wherein starter/helper motors


908


,


910


assist in turning the larger motors


900


,


902


during start-up, or starter/helper motors


908


,


910


can operate in a helping mode, wherein starter/helper motors


908


,


910


assist electric motors


900


,


902


in powering compressors


400


,


402


,


600


,


602


during normal operation. Starter/helper motors


908


,


910


are powered with electricity generated by cogeneration plant


1000


and conducted via electrical lines


1010


,


1012


,


1014


.




Referring now to

FIG. 3

, a natural gas liquefaction system similar to those illustrated in

FIGS. 1 and 2

is shown as including an alternative driver and power system. A cogeneration plant


1200


is used to power electric motors


1100


,


1102


via electricity conducted through electrical lines


1202


,


1203


,


1205


. Cogeneration plant


1200


is also operable to power steam turbines


1104


,


1106


via steam conducted through steam conduits


1204


,


1206


,


1208


,


1210


.




A first starter/helper steam turbine


1108


is drivingly coupled to first electric motor


1100


, while a second starter/helper steam turbine


1110


is drivingly coupled to second electric motor


1102


. Starter/helper steam turbines


1108


,


1110


are powered with steam generated by cogeneration plant


1200


and conducted to starter/helper steam turbines


1108


,


1110


via conduits


1204


,


1212


,


1214


,


1216


. During start-up, starter/helper steam turbines


1108


,


1110


can help turn electric motors


1100


,


1102


. During normal operation of the natural gas liquefaction system, starter/helper steam turbines


1108


,


1110


can assist electric motors


1100


,


1102


in driving compressors


400


,


402


,


600


,


602


.




The preferred forms of the invention described above are to be used as illustration only, and should not be used in a limiting sense to interpret the scope of the present invention. Obvious modifications to the exemplary embodiments, set forth above, could be readily made by those skilled in the art without departing from the spirit of the present invention.




The inventors hereby state their intent to rely on the Doctrine of Equivalents to determine and assess the reasonably fair scope of the present invention as pertains to any apparatus not materially departing from but outside the literal scope of the invention as set forth in the following claims.



Claims
  • 1. A process for liquefying natural gas, said process comprising the steps of:(a) driving a first compressor and a second compressor with a first electric motor; (b) driving a third compressor and a fourth compressor with a second electric motor; (c) compressing a first refrigerant of a first refrigeration cycle in the first and third compressors; and (d) compressing a second refrigerant of a second refrigeration cycle in the second and fourth compressors.
  • 2. The process according to claim 1,said first and third compressors being fluidly connected to the first refrigeration cycle in parallel, said second and fourth compressors being fluidly connected to the second refrigeration cycle in parallel.
  • 3. The process according to claim 2,said first refrigerant comprising in major portion a hydrocarbon selected from the group consisting of propane, propylene, and mixtures thereof.
  • 4. The process according to claim 3,said second refrigerant comprising in major portion a hydrocarbon selected from the group consisting of ethane, ethylene, and mixtures thereof.
  • 5. The process according to claim 3; and(e) driving a fifth compressor with a third electric motor; and (f) compressing a third refrigerant of a third refrigeration cycle in the fifth compressor.
  • 6. The process according to claim 5,said second refrigerant comprising in major portion a hydrocarbon selected from the group consisting of ethane, ethylene, and mixtures thereof, said third refrigerant comprising in major portion methane.
  • 7. The process according to claim 6; and(g) driving a sixth compressor with a fourth electric motor; and (h) compressing the third refrigerant of the third refrigeration cycle in the sixth compressor.
  • 8. The process according to claim 7,said fifth and sixth compressors being fluidly connected to the third refrigeration cycle in parallel.
  • 9. The process according to claim 8,said first refrigerant comprising in major portion propane, said second refrigerant comprising in major portion ethylene, said third refrigerant comprising in major portion methane.
  • 10. The process according to claim 1; and(i) vaporizing liquefied natural gas produced via steps (a)-(d).
  • 11. A process for liquefying natural gas, said process comprising the steps of:(a) generating steam and electricity in a cogeneration plant; (b) using at least a portion of the electricity to power a first electric motor; (c) using at least a portion of the steam to power a first steam turbine; (d) compressing a first refrigerant of a first refrigeration cycle in a first compressor driven by the first electric motor; (e) compressing a second refrigerant of a second refrigeration cycle in a second compressor driven by the first steam turbine; (f) using at least a portion of the electricity to power a second electric motor; (g) compressing the first refrigerant of the first refrigeration cycle in a third compressor driven by the second electric motor; (h) using at least a portion of the steam to power a second steam turbine; and (i) compressing the second refrigerant of the second refrigeration cycle in a fourth compressor driven by the second steam turbine, said first and third compressors being fluidly coupled to the first refrigeration cycle in parallel, said second and fourth compressors being fluidly coupled to the second refrigeration cycle in parallel.
  • 12. The process according to claim 11,said first refrigerant comprising in major portion propane, propylene, and mixtures thereof.
  • 13. The process according to claim 12,said second refrigerant comprising in major portion methane.
  • 14. The process according to claim 11,said first refrigerant comprising in major portion a hydrocarbon selected from the group consisting of propane, propylene, and mixtures thereof, said second refrigerant comprising in major portion methane.
  • 15. The process according to claim 14; and(j) compressing a third refrigerant of a third refrigeration cycle in a fifth compressor driven by the first electric motor; and (k) compressing the third refrigerant of the third refrigerant cycle in a sixth compressor driven by the second electric motor.
  • 16. The process according to claim 15,said fifth and sixth compressors being fluidly coupled to the third refrigeration cycle in parallel.
  • 17. The process according to claim 16,said first refrigerant comprising in major portion propane, said second refrigerant comprising in major portion methane, said third refrigerant comprising in major portion ethylene.
  • 18. The process according to claim 11; and(1) vaporizing liquefied natural gas produced via steps (a)-(e).
  • 19. An apparatus for liquefying natural gas by cooling the natural gas via a plurality of sequential refrigeration cycles employing different refrigerants, said apparatus comprising:a first refrigeration cycle including a first compressor for compressing a first refrigerant; a second refrigeration cycle including a second compressor for compressing a second refrigerant; a third refrigeration cycle including a third compressor for compressing a third refrigerant; a first electric motor for driving the first compressor; a second electric motor for driving the second compressor; and a third electric motor for driving the third compressor, said first refrigerant comprising in major portion a hydrocarbon selected from the group consisting of propane, propylene, and mixtures thereof, said second refrigerant comprising in major portion a hydrocarbon selected from the group consisting of ethane, ethylene, and mixtures thereof, said third refrigerant comprising in major portion methane, said second refrigeration cycle including a fourth compressor drivingly coupled to the first electric motor and operable to compress the second refrigerant, said first refrigeration cycle including a fifth compressor drivingly coupled to the second electric motor and operable to compress the first refrigerant, said first and fifth compressors being fluidly integrated in the first refrigeration cycle in parallel, said second and fourth compressors being fluidly integrated in the second refrigeration cycle in parallel.
  • 20. The apparatus according to claim 19,said first refrigeration cycle being located upstream of the second refrigeration cycle, said second refrigeration cycle being located upstream of the third refrigeration cycle.
  • 21. The apparatus according to claim 19,said third refrigeration cycle being an open methane cycle.
  • 22. The apparatus according to claim 19,said first refrigerant comprising in major portion propane, said second refrigerant comprising in major portion ethylene, said third refrigerant comprising in major portion methane.
  • 23. The apparatus according to claim 19,said first refrigerant comprising in major portion propane, said second refrigerant comprising in major portion ethylene.
  • 24. An apparatus for liquefying natural gas by cooling the natural gas via a plurality of sequential refrigeration cycles employing different refrigerants, said apparatus comprising:a first refrigeration cycle including a first compressor for compressing a first refrigerant; a second refrigeration cycle including a second compressor for compressing a second refrigerant; a third refrigeration cycle including a third compressor for compressing a third refrigerant; a first electric motor for driving the first compressor; a second electric motor for driving the second compressor; and a third electric motor for driving the third compressor, said first refrigerant comprising in major portion a hydrocarbon selected from the group consisting of propane, propylene, and mixtures thereof, said second refrigerant comprising in major portion a hydrocarbon selected from the croup consisting of ethane, ethylene, and mixtures thereof, said third refrigerant comprising in major portion methane; and a starter/helper motor drivingly coupled to the first electric motor, said starter/helper motor being operable to help start the turning of the first electric motor during start-up of the first electric motor when the starter/helper motor is operated in a starting mode, said starter/helper motor being operable to help the first electric motor drive the first compressor when the starter/helper motor is operated in a helping mode.
  • 25. An apparatus for liquefying natural gas by cooling the natural gas via a plurality of sequential refrigeration cycles employing different refrigerants, said apparatus comprising:a first refrigeration cycle including a first compressor for compressing a first refrigerant; a second refrigeration cycle including a second compressor for compressing a second refrigerant; a third refrigeration cycle including a third compressor for compressing a third refrigerant; a first electric motor for driving the first compressor; a second electric motor for driving the second compressor; a third electric motor for driving the third compressor, said first refrigerant comprising in major portion a hydrocarbon selected from the group consisting of propane, propylene, and mixtures thereof, said second refrigerant comprising in major portion a hydrocarbon selected from the group consisting of ethane, ethylene, and mixtures thereof, said third refrigerant comprising in major portion methane; and a steam turbine drivingly coupled to the first electric motor and operable to help start the first electric motor.
  • 26. An apparatus for liquefying natural gas by cooling the natural gas via a plurality of sequential refrigeration cycles employing different refrigerants, said apparatus comprising:a first refrigeration cycle including a first compressor for compressing a first refrigerant; a second refrigeration cycle including a second compressor for compressing a second refrigerant; a third refrigeration cycle including a third compressor for compressing a third refrigerant; a first electric motor for driving the first compressor; a second electric motor for driving the second compressor; a third electric motor for driving the third compressor, said first refrigerant comprising in major portion a hydrocarbon selected from the group consisting of propane, propylene, and mixtures thereof, said second refrigerant comprising in major portion a hydrocarbon selected from the group consisting of ethane, ethylene, and mixtures thereof, said third refrigerant comprising in major portion methane; a steam turbine drivingly coupled to the first electric motor and operable to help start the first electric motor; and a cogeneration plant operable to generate electricity and steam, said first, second, and third electric motors being powered by at least a portion of the electricity, said steam turbine being powered by at least a portion of the steam.
  • 27. An apparatus for liquefying natural gas by cooling the natural gas via a plurality of sequential refrigeration cycles employing different refrigerants, said apparatus comprising:a first refrigeration cycle including a first compressor for compressing a first refrigerant; a second refrigeration cycle including a second compressor for compressing a second refrigerant; a cogeneration plant for simultaneously generating electricity and steam; a first electric motor drivingly coupled to the first compressor and powered by at least a portion of the electricity; a first steam turbine drivingly coupled to the second compressor and powered by at least a portion of the steam; and a first starter steam turbine drivingly coupled to the first electric motor and powered by at least a portion of the steam.
  • 28. The apparatus according to claim 27,said first refrigerant comprising in major portion a hydrocarbon selected from the group consisting of propane, propylene, and mixtures thereof.
  • 29. The apparatus according to claim 28,said second refrigerant comprising in major portion methane.
  • 30. An apparatus for liquefying natural gas by cooling the natural gas via a plurality of sequential refrigeration cycles employing different refrigerants, said apparatus comprising:a first refrigeration cycle including a first compressor for compressing a first refrigerant; a second refrigeration cycle including a second compressor for compressing a second refrigerant; a cogeneration plant for simultaneously generating electricity and steam; a first electric motor drivingly coupled to the first compressor and powered by at least a portion of the electricity; a first steam turbine drivingly coupled to the second compressor and powered by at least a portion of the steam, said second refrigeration cycle including a third compressor for compressing the second refrigerant; and a second steam turbine drivingly coupled to the third compressor and powered by at least a portion of the steam, said second and third compressors being fluidly integrated in the second refrigeration cycle in parallel.
  • 31. The apparatus according to claim 30; anda third refrigeration cycle including a fourth compressor for compressing a third refrigerant; and a second electric motor drivingly coupled to the fourth compressor and powered by at least a portion of the electricity.
  • 32. The apparatus according to claim 31,said third refrigeration cycle including a fifth compressor being drivingly coupled to the first electric motor and operable to compress the third refrigerant; and said first refrigeration cycle including a sixth compressor being drivingly coupled to the second electric motor and operable to compress the first refrigerant.
  • 33. The apparatus according to claim 32,said first and sixth compressors being fluidly integrated in the first refrigeration cycle in parallel, said fourth and fifth compressors being fluidly integrated in the third refrigeration cycle in parallel.
  • 34. The apparatus according to claim 33,said first refrigerant comprising in major portion propane.
  • 35. The apparatus according to claim 34,said second refrigerant comprising in major portion methane, said third refrigerant comprising in major portion ethylene.
US Referenced Citations (15)
Number Name Date Kind
3548606 Kuerston Dec 1970 A
3581510 Hughes Jun 1971 A
4539028 Paradowski et al. Sep 1985 A
4566885 Haak Jan 1986 A
4680041 DeLong Jul 1987 A
4755200 Liu et al. Jul 1988 A
5473900 Low Dec 1995 A
5689141 Kikkawa et al. Nov 1997 A
5943881 Grenier Aug 1999 A
6070429 Low et al. Jun 2000 A
6272882 Hodges et al. Aug 2001 B1
6324867 Fanning et al. Dec 2001 B1
6367286 Price Apr 2002 B1
6446465 Dubar Sep 2002 B1
20020170312 Reijnen et al. Nov 2002 A1
Non-Patent Literature Citations (2)
Entry
Bauer, Heinz. “A Novel Concept.” Hydrocarbon Engineering May 2002: 59-63.
Siemens Aktiengsesellschaft. “The All Electric Driven LNG Plant.” Presented at the 1st BP Upstream Energy Conference, May 9, 2001, Sheraton Suites Houston, Texas.