JP4551446B2 - Natural gas liquefaction - Google Patents

Description

Background of the Invention

  The present invention treats a gas stream rich in natural gas or other methane to produce a liquefied natural gas (LNG) stream having a high methane purity and a liquid stream mainly containing hydrocarbons heavier than methane. Concerning the method.

  Natural gas is typically recovered from an oil well that has penetrated into an underground reservoir. It is mostly methane. That is, methane constitutes at least 50 mol% of the gas. Depending on the particular underground reservoir, natural gas also contains relatively small amounts of heavy hydrocarbons, such as ethane, propane, butane, pentane, and water, hydrogen, nitrogen, carbon dioxide, and other gases .

  Most natural gas is handled in gaseous form. The most common means for transporting natural gas from oil well heads to gas processing plants and from there to natural gas consumers is the high pressure gas transport pipeline. However, in many situations it has been found necessary and / or desirable to liquefy natural gas for either transportation or use. For example, in remote locations, there is often no pipeline infrastructure that allows convenient transportation of natural gas to the market. In such a case, when the specific volume of LNG is much smaller than that of natural gas in a gaseous state, it is possible to deliver LNG using a carrier ship and a transportation truck, and the transportation cost can be greatly reduced.

  Another situation where natural gas liquefaction is advantageous is when used as a vehicle fuel. In metropolitan areas, there are buses, taxis and trucks that can run on LNG if there are economical LNG sources available. Such LNG fueled transportation means that natural gas combustion is cleaner when compared to similar transportation means running on gasoline and diesel engines that burn higher molecular weight hydrocarbons, resulting in significant air pollution. Few. Furthermore, if the LNG is of high purity (ie, methane purity of 95 mol% or higher), the amount of carbon dioxide (greenhouse gas) produced is methane compared to all other hydrocarbon fuels. The carbon: hydrogen ratio is low because of its low ratio.

The present invention generally relates to, for example, natural gas liquid (NGL) composed of ethane, propane, butane and heavy hydrocarbon components, liquefied petroleum gas (LPG) composed of propane, butane and heavy hydrocarbon components, or butane. And liquefying natural gas while producing as a co-product a liquid stream composed primarily of hydrocarbons heavier than methane, such as condensation products composed of heavy hydrocarbon components. There are two important advantages to producing a co-product liquid stream: the LNG produced has a high methane purity, and the co-product liquid is useful for many other purposes. Product. A typical analysis of a natural gas stream to be treated according to the present invention is approximately mole percent, 84.2% methane, 7.9% ethane and other C ₂ components, propane and other C ₃ components. Is 4.9%, iso-butane is 1.0%, n-butane is 1.1%, pentane is 0.8%, and the remainder is nitrogen and carbon dioxide. Sulfur containing gases are also sometimes present.

  Many methods for liquefying natural gas are known. For example, to review many such methods, Finn, Adrian J., Grant L. Johnson, and Terry R. Tomlinson, "LNG Technology for Offshore and Mid-Scale Plants", Proceedings of the Seventy-Ninth Annual Convention of the Gas Processors Association, pp. 429-450, Atlanta, Gerogia, March 13-15, 2000 and Kikkawa, Yoshitsugi, Masaaki Ohishi, and Noriyoshi Nozawa, "Optimize the Power System of Baseload LNG Plant", Proceedings of the Eightieth See Annual Convention of the Gas Processors Association, San Antonio, Texas, March 12-14. U.S. Pat. Nos. 4,445,917; 4,525,185; 4,545,795; 4,755,200; 5,291,736; 5,363,655; 5,365,740; 5,600,969; 5,615,561; 5,651,269; 5,755,114; 6,014,869; 6,062,041; 6,119,479; 6,125,653; 6,250,105 B1; 6,269,655 B1; 6,272,882 B1; 6,308,531 B1; 6,324,867 B1; 6,347,532 B1; and 2002 Applicant's co-pending US patent application Ser. No. 10 / 161,780, filed June 4, also describes a related method. These methods generally include the steps of refining (by removing problematic compounds such as water and carbon dioxide and sulfur compounds), cooling, condensing and expanding natural gas. Natural gas cooling and condensation can be accomplished in many different ways. “Cascade cooling” uses heat exchange between natural gas and several refrigerants having boiling points that decrease continuously, such as propane, ethane and methane. Alternatively, this heat exchange can be performed with a single refrigerant by evaporating the refrigerant at several different pressure levels. “Multi-component cooling” uses heat exchange between natural gas and one or more refrigerant fluids consisting of several refrigerant components instead of multiple single-component refrigerants. Natural gas expansion can be done either isenthalpy (eg, using Joule-Thomson expansion) or isentropic (eg, using a work-expansion turbine).

  Regardless of the method used to liquefy the natural gas stream, it is generally necessary to remove a significant portion of the hydrocarbons heavier than methane before liquefying the methane-rich stream. There are many reasons for this hydrocarbon removal process, including the need to adjust the calorific value of the LNG stream and the product value of these heavy hydrocarbon components. Unfortunately, little attention has been paid to the efficiency of the hydrocarbon removal process so far.

  In accordance with the present invention, it has been found that careful incorporation of the hydrocarbon removal step into the LNG liquefaction process can produce both LNG and individual heavy hydrocarbon liquid products with much less energy usage than prior art methods. . The present invention can be applied at lower pressures, but is particularly advantageous when the feed gas is processed at 400-1500 psia [2,758-10,342 kPa (a)] or higher.

For a better understanding of the present invention, reference is made to the following examples and figures.
In the following description of the figure, the table gives an overview of the flow rates calculated for representative method conditions. In the table | surface shown in this specification, the value (mol / hour) of a flow rate is represented by the nearest integer for convenience. The overall flow rate shown in the table includes all non-hydrocarbon components and is therefore generally greater than the sum of the flow rates for the hydrocarbon components. The displayed temperature is an approximate value summarized to the nearest temperature. It should also be noted that the process design calculations performed to compare the processes shown in the figures are based on the assumption that there is no heat leak from ambient to process (or from process to ambient). Due to the quality of commercially available insulating materials, this is a very reasonable assumption and is typically done by those skilled in the art.

  For convenience, process parameters are shown in both traditional British units and International Unit System (SI) units. The molar flow rates in the table are shown as either pound moles / hour or kg moles / hour. Energy consumption, expressed as horsepower (HP) and / or 1000 British thermal units / hour (MBTU / Hr), corresponds to the stated molar flow rate in pound moles / hour. The energy consumption, expressed as kilowatts (kW), corresponds to the stated molar flow rate in kg mole / hour. Production expressed as lb / hr (Lb / Hr) corresponds to the stated molar flow rate in lbmol / hr. The production expressed as kg / hr (kg / Hr) corresponds to the stated molar flow rate in kg mol / hr.

DESCRIPTION OF THE INVENTION Reference is made to FIG. The process according to the invention is first described when it is desirable to produce an LPG co-product containing the majority of propane and heavy components in a natural gas feed stream. In this simulation of the present invention, the inlet gas enters the plant as stream 31 at 90 ° F. [32 ° C.] and 1285 psia [8,860 kPa (a)]. If the inlet gas contains carbon dioxide and / or sulfur compounds at a concentration that prevents the product stream from meeting specifications, these compounds are removed by appropriate pretreatment (not shown) of the feed gas. . Furthermore, the feed stream is usually dehydrated to prevent hydrate (ice) formation under cryogenic conditions. Solid desiccants are typically used for this purpose.

  The feed stream 31 is cooled in the heat exchanger 10 by heat exchange with the refrigerant stream and flushed separator liquid (stream 40a) at 14 ° F. [−26 ° C.]. It should be noted that in all cases, the heat exchanger 10 corresponds to either a number of individual heat exchangers, or a single multi-pass heat exchanger, or a combination thereof. (Determining whether to use one or more heat exchangers for the indicated cooling depends on many factors including, but not limited to, inlet gas flow rate, heat exchanger size, flow temperature, etc.) The cooled stream 31a enters the separator 11 at 23 ° F. [−5 ° C.] and 1278 psia [8,812 kPa (a)], where the vapor (stream 32) is separated from the condensate (stream 33).

  Vapor from separator 11 (stream 32) is divided into two streams, 34 and 36, which comprise about 42% of the total vapor. In some circumstances it may be convenient to combine stream 34 and some portion of condensate to form stream 35, but in this simulation there is no stream 39 stream. Composite stream 35 passes through heat exchanger 13 in heat exchange relationship with refrigerant stream 71e, and stream 35a is cooled and substantially condensed. A substantially condensed stream 35a of −90 ° F. [−68 ° C.] is suitable for an expansion device suitable for a pressure just above the operating pressure of the rectification column 19 (about 450 psia [3,103 kPa (a)]), for example Flash expansion is performed by the expansion valve 14. During expansion, part of the stream evaporates and cools the entire stream. In the method shown in FIG. 1, the expanded stream 35b exiting the expansion valve 14 reaches a temperature of -123 ° F [-86 ° C]. The expanded stream 35b is warmed to -78 ° F [-61 ° C] in the heat exchanger 21 while cooling and partially condensing the steam distillation stream 37 rising from the fractionation stage of the rectifying column 19, and further evaporating. To do. The warmed stream 35c is then fed at the upper central feed position of the deethanizer section 19b of the rectification column 19.

  The remaining 58% of vapor from the separator 11 (stream 36) enters the work expansion machine 15, where mechanical energy is extracted from this portion of the high pressure feed stream. Machine 15 expands steam substantially isentropically from a pressure of about 1278 psia [8,812 kPa (a)] to a tower operating pressure, and work expansion expands expanded stream 36 a to about −57 ° F. [− 49 ° C]. In general, commercially available expanders can recover as much as 80-85% of the theoretically available work with ideal isentropic expansion. The recovered work is often used, for example, to move a centrifugal compressor (eg, part 16) that can be used to recompress tower overhead gas (stream 49). Expanded and partially condensed stream 36a is fed as a feed stream to distillation column 19 at the lower central column feed point. The remaining portion of the separator liquid (stream 33), stream 40, is flash expanded by expansion valve 12 to a pressure slightly above the operating pressure of deethanizer 19 and cooled to -14 ° F [-26 ° C]. (Flow 40a), cooling the incoming gas as described above. Originally, the stream 40b at 75 ° F. [24 ° C.] then enters the deethanizer tower 19 at the second lower center tower feed position.

  The deethanizer column in the rectifying column 19 is a general one comprising a number of spaced, vertically arranged trays, one or more packed beds, or some combination of trays and packings. It is a distillation tower. As is often the case with natural gas processing plants, the rectification column can consist of two sections. The upper section 19a is a separator where the top feed is divided into respective vapor and liquid portions and the vapor rising from the lower distillation or deethanization section 19b is the vapor portion of the top feed (if any). Together with the formation of deethanizer overhead vapor (stream 37) exiting from the top of the tower. The lower deethanization section 19b contains trays and / or packings and provides the necessary contact between the flowing cold liquid and the rising steam. The deethanizer section also includes one or more reboilers (eg, reboiler 20) that heat and evaporate the liquid portion flowing down the tower to provide stripping vapor that flows above the tower. The liquid product stream 41 exits the bottom of the column at 213 ° F. [101 ° C.] based on the general specification of ethane to propane of 0.020: 1 on a bottom product molar basis.

  Overhead distillation stream 37 exits deethanizer 19 at -73 ° F [-59 ° C] and is cooled and partially condensed in reflux condenser 21 as described above. Partially condensed stream 37a enters reflux drum 22 at -94 ° F [-70 ° C], where condensate (stream 44) is separated from uncondensed vapor (stream 43). The condensate (stream 44) is sent by the pump 23 to the top feed position of the deethanizer 19 as reflux stream 44a.

  When the deethanizer section forms the lower part of the rectifying column, the reflux condenser 21 can be located inside the column above the column 19 as shown in FIG. The distillation stream is then cooled and separated in the column above the column fractionation stage, thereby eliminating the need for reflux drum 22 and reflux pump 23. Alternatively, if a dephlegmator (eg, dephlegmator 21 in FIG. 3) is used in place of the reflux cooler 21 of FIG. 1, the reflux drum and reflux pump are no longer needed, and this is in addition to those in the upper section of the deethanizer. An alternative simultaneous fractionation stage is also provided. If the dephlegmator is placed at a grade level in the plant, it is connected to a vapor / liquid separator and the liquid collected in the separator is sent to the top of the distillation column. The decision to include a reflux condenser inside the column or to use a dephlegmator depends on the size of the plant and the required heat exchanger surface.

  The non-condensed vapor (stream 43) from the reflux drum 22 is warmed to 93 ° F. [34 ° C.] in the heat exchanger 24, and a portion (stream 48) is then withdrawn to serve as fuel gas for the plant. . (The amount of fuel gas that must be removed depends on the fuel required for the plant gas compressor, for example, the engine and / or turbine that runs the refrigerant compressors 64, 66, and 68 in this example.) The remainder of the warmed steam (Stream 49) is compressed by the compressor 16 which is driven by the expansion machines 15, 61 and 63. After being cooled to 100 F [38 ° C.] in discharge cooler 25, stream 49 b is further cooled to −83 ° F. [−64 ° C.] in heat exchanger 24 by exchange with cold steam, stream 43.

  Stream 49c then enters heat exchanger 60 and is further cooled to −255 ° F. [−160 ° C.] by refrigerant stream 71d, condensed and secondary cooled, then enters work expansion machine 61, There, mechanical energy is extracted from the flow. Machine 61 expands liquid stream 49d from approximately 593 psia [4,085 kPa (a)] to an LNG storage pressure (15.5 psia [107 kPa (a)], just above atmospheric pressure, substantially isentropically. The pan cools the expanded stream 49e to a temperature of about -256 ° F [-160 ° C], after which the stream is sent to the LNG storage tank 62 containing the LNG product (stream 50).

  All cooling of streams 35 and 49c is performed by a closed cycle cooling circuit. The working fluid for this cycle is a mixture of hydrocarbon and nitrogen, and the composition of the mixture is adjusted as necessary to condense at a reasonable pressure using available cooling media while providing the required refrigerant temperature. To do. In this case, a refrigerant mixture consisting of nitrogen, methane, ethane, propane, and heavy hydrocarbons is used for the simulation of the method of FIG. The approximate mole percent stream composition is 8.7% nitrogen, 31.7% methane, 47.0% ethane and 8.6% propane, and the remaining heavy hydrocarbons.

  Refrigerant stream 71 exits discharge cooler 69 at 100 ° F. [38 ° C.] and 607 psia [4,185 kPa (a)]. It enters the heat exchanger 10 and is cooled to -34 ° F [-37 ° C] by the partially warmed expanded refrigerant stream 71f and by other refrigerant streams and partially condensed. In the simulation of FIG. 1, these other refrigerant streams were assumed to be commercial quality propane refrigerants at three different temperature and pressure levels. The partially condensed refrigerant stream 71a is further cooled to -90 ° F [-68 ° C] by the partially warmed and expanded refrigerant stream 71e and further condensed (stream 71b). Enter 13. The refrigerant is condensed and secondarily cooled to -255 ° F. [−160 ° C.] in the heat exchanger 60 by the expanded refrigerant stream 71d. The secondary cooled liquid stream 71c enters the work expansion machine 63 where it is substantially isentropic from a pressure of about 586 psia [4,040 kPa (a)] to a pressure of about 34 psia [234 kPa (a)]. As it is expanded, mechanical energy is extracted from this stream. During expansion, a portion of the stream evaporates and cools the entire stream to -264 ° F [-164 ° C] (stream 71d). Expanded stream 71d then enters heat exchangers 60, 13 and 10 where it cools stream 49c, stream 35 and refrigerant (streams 71, 71a and 71b) while being evaporated and superheated.

  The superheated refrigerant vapor (stream 71 g) leaves the heat exchanger 10 at 90 ° F. [32 ° C.] and is compressed to 617 psia [4,254 kPa (a)] in three stages. Each of the three compression stages (refrigerant compressors 64, 66, and 68) is powered by a supplemental power supply, followed by a cooler that removes the heat of compression (discharge coolers 65, 67, and 69). The compressed stream 71 from the discharge cooler 69 returns to the heat exchanger 10 to complete the cycle.

    An overview of the flow rate and energy consumption of the method shown in Figure 1 is given in the following table:

  The efficiency of the LNG production process is generally compared using the required “specific power (power) consumption”, which is the ratio of total cooling compression power to total liquid production. Information published on the specific power (electric power) consumption of the conventional method of LNG production is 0.168 HP-Hr / Lb [0.276 kW-Hr / kg] to 0.182 HP-Hr / Lb [0.300 kW-Hr / kg]. This is considered to be based on a 340 day / year circulation factor for the LNG production plant. On the same basis, the specific power (power) consumption of the FIG. 1 embodiment of the present invention is 0.148 HP-Hr / Lb [0.243 kW-Hr / kg], which is an efficiency improvement of 14-23% over the conventional method. It is.

  There are mainly two factors that explain the reason for improving the efficiency of the present invention. The first factor can be understood by examining the thermodynamics of the liquefaction process when applying a high pressure gas stream as contemplated in this example. Since the main component of this flow is methane, the thermodynamic properties of methane can be used to compare the liquefaction cycle used in the conventional method with the cycle used in the present invention. FIG. 4 is a pressure-enthalpy state diagram of methane. In most conventional liquefaction cycles, all cooling of the gas stream occurs while the stream is at high pressure (phase AB), after which the stream is brought to the pressure of the LNG storage vessel (slightly above atmospheric pressure). Inflated (Phase B-C). This expansion process may use a work expansion machine, which is generally capable of recovering as much as 75-80% of work that can theoretically be used with ideal isentropic expansion. For simplicity, the full isentropic expansion is shown in FIG. 4 for path BC. Nevertheless, since the constant entropy line is almost vertical in the liquid region of the phase diagram, the enthalpy reduction due to this work expansion is very small.

  This is contrasted with the liquefaction cycle of the present invention. After partial cooling at high pressure (path AA ′), the gas stream is work expanded to intermediate pressure (path A′-A ″). (Also, full isentropic expansion is shown for simplicity.) The remaining cooling takes place at intermediate pressure (path A ″ -B ′) and the flow is then expanded to the pressure of the LNG storage vessel (path B′-C). Since the line of constant entropy gradient is not so steep in the vapor region of the phase diagram, the first work expansion process (path A′-A ″) of the present invention results in a much larger enthalpy reduction. The total amount of cooling required (sum of path AA ′ and path A ″ -A ″) is less than the cooling required for the conventional process (path AB), and the cooling required for liquefaction of the gas stream (and hence cooling compression). ) Less.

  The second factor that explains the efficiency improvement reasons of the present invention is the superior performance of the hydrocarbon distillation system at lower operating pressures. Most conventional hydrocarbon removal steps are performed at high pressure, generally using a scrub column that removes heavy hydrocarbons from the inlet gas stream using a cold hydrocarbon liquid as the absorbent stream. The operation of the scrub column at high pressure will simultaneously absorb a significant portion of methane and ethane from the gas stream and must be subsequently stripped from the absorbent liquid and cooled to become part of the LNG product. It is very inefficient. In the present invention, the hydrocarbon removal step is carried out at medium pressure, where vapor-liquid equilibration is much more advantageous, so that the desired heavy hydrocarbons in the co-product liquid stream are recovered very efficiently. .

Other Embodiments It will be appreciated by those skilled in the art that the present invention can be adapted to any type of LNG liquefaction plant so that the simultaneous generation of NGL, LPG or condensate streams can be met as much as possible in a given plant configuration It will be obvious to you. It will also be apparent that various process configurations can be used to recover the liquid coproduct stream. The present invention is not a LPG coproduct generate as above, C ₄ components present in NGL is recovered flow, or feed gas containing a substantial portion of the C ₂ components present in the feed gas And can be adapted to recover a condensed stream containing only heavy components.

  FIG. 1 illustrates a preferred embodiment of the present invention for display processing conditions. Figures 5 to 10 show alternative aspects of the invention that may be considered for individual applications. Depending on the amount of heavy hydrocarbons in the feed gas and the feed gas pressure, the cooled feed stream 31a exiting the heat exchanger 10 does not contain any liquid (because it is above its dew point or its cricon denbar ( As a result, the separator 11 shown in FIGS. 1 and 6-10 is not necessary, and the cooled feed stream flows directly to a suitable expansion device, for example the work expansion machine 15 Can do. If the inlet gas is richer than previously described, an embodiment of the invention as shown in FIG. 5 may be used. The condensate stream 33 passes through the heat exchanger 18 and is divided into two parts. The first part (stream 40) passes through the expansion valve 12 where it expands for flash evaporation while the pressure is reduced to approximately the pressure of the distillation column 19. The cold stream 40a from the expansion valve 12 passes through the heat exchanger 18 where it is partially warmed while being used for secondary cooling of the stream 33 as described above. The partially warmed stream 40 b is further warmed by the heat exchanger 10 and flows to the lower central feed position of the rectification column 19. The still high pressure second liquid portion (stream 39) is either (1) combined with a portion 34 of the vapor stream from the separator 11, or (2) combined with a substantially condensed stream 35a, or (3) Expanded with expansion valve 17 and then fed to rectification column 19 at the upper central feed position or combined with expanded stream 35b. Alternatively, the portion of flow 39 may follow any or all of the flow paths described so far and shown in FIG.

  Treatment of the remaining gas stream after recovery of the liquid coproduct stream (stream 43 in FIGS. 1 and 6-10) before being fed to heat exchanger 60 for condensation and secondary cooling should be done in a number of ways. Can do. In the method of FIG. 1, the stream is heated, compressed to a higher pressure using energy from one or more work expansion machines, partially cooled with a discharge cooler, and It is further cooled by mutual exchange. As shown in FIG. 6, in some applications it may be appropriate to compress the flow to a higher pressure, for example using a refill compressor 59 that is powered by an external power source. As indicated by the dotted line apparatus in FIG. 1 (heat exchanger 24 and discharge cooler 25), in some situations, the facility can be reduced by reducing or eliminating pre-cooling of the compressed stream 60 before entering the heat exchanger 60. It may be preferable to reduce capital costs (at the expense of increased cooling load of the heat exchanger 60 and increased power consumption of the refrigerant compressors 64, 66, and 68). In such a case, the flow 49a exiting the compressor flows directly to the heat exchanger 24 as shown in FIG. 7 or directly to the heat exchanger 60 as shown in FIG. If the work expansion machine is not used to expand any part of the high pressure feed gas, a compressor powered by an external power source, such as the compressor 59 shown in FIG. The other situation does not justify any compression of the flow, so the flow is as shown in FIG. 10 and by the dotted line device of FIG. 1 (heat exchanger 24, compressor 16 and discharge cooler 25). It flows directly to the heat exchanger 60. If the heat exchanger 24 that heats the stream is not included before the plant fuel gas (stream 48) is removed, a utility stream or other process stream that supplies the necessary heat as shown in FIGS. A replenisher heater 58 may be required to use and warm the fuel gas before consumption. Since such requirements as gas composition, plant size, desired co-product stream recovery level, and available equipment all have to be taken into account, such choices must generally be evaluated for each application.

  In the present invention, the inlet gas stream and the feed stream to the LNG production section can be done in a number of ways. In the method of FIGS. 1 and 5-10, the inlet gas stream 31 is cooled and condensed by the external refrigerant stream and the flushed separator liquid. However, it is also possible to supply some of the cooling to the high pressure refrigerant (stream 71a) using a cold process stream. In addition, any flow that is cooler than the cooled flow can be used. For example, a side draw of steam from the rectification column 19 can be drawn and used for cooling. As with the process flow selection for a particular heat exchange, the use and distribution of tower liquids and / or steam for process heat exchange, and the individual arrangement of heat exchangers for cooling the inlet gas and feed gas can be tailored to the individual application. Must be evaluated. The choice of cooling source is based on many factors including, but not limited to, feed gas composition and condition, plant size, heat exchanger size, potential cooling source temperature, and the like. It will be apparent to those skilled in the art that any combination of the above cooling sources or cooling methods can be used to obtain the desired feed stream temperature.

  In addition, supplemental external cooling supplied to the inlet gas stream and the feed stream to the LNG production section is also performed in many different ways. 1 and 6-10, boiling single-component refrigerant is considered for high-level external cooling, vaporized multi-component refrigerant is considered for low-level external cooling, and single-component refrigerant is used for pre-cooling the multi-component refrigerant flow. . Alternatively, both high level cooling and low level cooling use a single component refrigerant with a continuously decreasing boiling point (ie, “cascade cooling”) or with a continuously decreasing evaporation pressure. Can be used. Alternatively, both high level cooling and low level cooling can be performed using multi-component refrigerant streams having respective compositions adjusted to provide the required cooling temperature. The choice of external cooling method is based on a number of factors including, but not limited to, feed gas composition and condition, plant size, compressor driver size, heat exchanger size, ambient cooling radiator temperature, and the like. It will be apparent to those skilled in the art that any combination of the above external cooling methods can be used to obtain the desired feed stream temperature.

  Secondary cooling of the condensed liquid stream exiting heat exchanger 60 (stream 49d in FIG. 1, stream 49e in FIG. 6, stream 49c in FIG. 7, streams 49b in FIGS. 8 and 9 and stream 49a in FIG. 10) Reduce or eliminate the amount of flash vapor that can be generated while expanding the flow to the operating pressure of the LNG storage tank 62. This generally reduces specific power consumption for LNG generation by eliminating the need for flash gas compression. However, in some circumstances it may be preferable to reduce the capital cost of the facility by reducing the size of the heat exchanger 60 and by using flash gas compression or other means of treating the flash gas that may occur. .

  Individual flow expansions are shown with specific expansion devices, but other expansion means may be used if appropriate. For example, work expansion of the feed stream with conditions substantially condensed (stream 35a in FIGS. 1 and 5-10) may be ensured. In addition, an isenthalpy flash expansion may be applied to the secondary cooled liquid stream exiting heat exchanger 60 (stream 49d in FIG. 1, stream 49e in FIG. 6, stream 49c in FIG. 7, streams 49b in FIGS. 8 and 9; and 10 may be used in place of the work expansion of stream 49a), but is further subcooled in heat exchanger 60 to avoid the formation of flash steam during expansion, or a flash steam compressor. Or other means of treating the resulting flash vapor need to be added. Similarly, isenthalpy flash expansion may be used in place of work expansion of the secondary cooled high pressure refrigerant stream exiting heat exchanger 60 (stream 71c of FIGS. 1 and 6-10) The power consumption for compression increases.

  Having described what is considered to be a preferred embodiment of the invention, it will be understood that other and further modifications may be made without departing from the spirit of the invention as defined in the claims, e.g. It will be apparent to those skilled in the art that the type or other requirements can be adapted.

FIG. 1 is a flow diagram of a natural gas liquefaction plant adapted for simultaneous production of LPG according to the present invention. FIG. 2 is a flow diagram of an alternative fractionation system that can be used in the method of the present invention. FIG. 3 is a flow diagram of an alternative fractionation system that can be used in the method of the present invention. FIG. 4 is a pressure-enthalpy phase diagram of methane used to illustrate the advantages of the present invention over prior art methods. FIG. 5 is a flow diagram of an alternative natural gas liquefaction plant adapted for simultaneous production of liquid streams in accordance with the present invention. FIG. 6 is a flow diagram of an alternative natural gas liquefaction plant adapted for simultaneous production of liquid streams in accordance with the present invention. FIG. 7 is a flow diagram of an alternative natural gas liquefaction plant adapted for simultaneous production of liquid streams in accordance with the present invention. FIG. 8 is a flow diagram of an alternative natural gas liquefaction plant adapted for simultaneous production of liquid streams in accordance with the present invention. FIG. 9 is a flow diagram of an alternative natural gas liquefaction plant adapted for simultaneous production of liquid streams according to the present invention. FIG. 10 is a flow diagram of an alternative natural gas liquefaction plant adapted for simultaneous production of liquid streams according to the present invention.

Claims (11)

A method for liquefying a natural gas stream containing methane and a hydrocarbon component heavier than methane,
(A) cooling the natural gas stream under pressure to condense at least a portion thereof to form a condensed stream; and (b) expanding the condensed stream to a low pressure to form a liquefied natural gas stream. In said method,
(1) treating said natural gas stream in one or more cooling steps;
(2) dividing the cooled natural gas stream into at least a first gaseous stream and a second gaseous stream;
(3) cooling the first gaseous stream to condense substantially all of it and then expanding to medium pressure , where the medium pressure is the pressure of the distillation column ;
(4) said first gaseous stream substantially condensed thereby inflated, the feed to the heat exchange with the high vapor distillation stream volatile rising from fractionation stages of the distillation column, warmed by it;
(5) expanding the second gaseous stream to the medium pressure;
(6) sending said expanded and warmed first gaseous stream and said expanded second gaseous stream to said distillation column, where these streams are said highly volatile steam distillation stream; Separating into a relatively less volatile fraction containing the majority of the hydrocarbon components heavier than methane;
(7) The highly volatile vapor distillation stream is sufficiently cooled by the substantially condensed and expanded first gaseous stream, partially condensed, and then separated, Forming a volatile residual gas fraction containing most and light components and a reflux stream;
(8) sending the reflux stream as top feed to the distillation column; and (9) cooling the volatile residual gas fraction under pressure to condense at least a portion thereof, thereby An improved method of forming. A method for liquefying a natural gas stream containing methane and a hydrocarbon component heavier than methane,
(A) cooling the natural gas stream under pressure to condense at least a portion thereof to form a condensed stream; and (b) expanding the condensed stream to a low pressure to form a liquefied natural gas stream. In said method,
(1) the natural gas stream is treated in one or more cooling steps to be partially condensed;
(2) separating the partially condensed natural gas stream, thereby providing a vapor stream and a liquid stream;
(3) dividing the vapor stream into at least a first gaseous stream and a second gaseous stream;
(4) cooling the first gaseous stream to condense substantially all of it and then expanding to medium pressure , where the medium pressure is the pressure of the distillation column ;
(5) said first gaseous stream substantially condensed thereby inflated, the feed to the heat exchange with the high vapor distillation stream volatile rising from fractionation stages of the distillation column, warmed by it;
(6) expanding the second gaseous stream to the medium pressure;
(7) expanding the liquid stream to the medium pressure;
(8) sending the expanded and warmed first gaseous stream, the expanded second gaseous stream and the expanded liquid stream to the distillation column, where these streams are Separating into a highly volatile steam distillation stream and a relatively less volatile fraction containing a majority of the hydrocarbon components heavier than the methane;
(9) The highly volatile steam distillation stream is sufficiently cooled by the substantially condensed and expanded first gaseous stream, partially condensed, and then separated to provide Forming a volatile residual gas fraction containing most and light components and a reflux stream;
(10) sending the reflux stream as top feed to the distillation column; and (11) cooling the volatile residual gas fraction under pressure to condense at least a portion thereof, thereby An improved method of forming. A method for liquefying a natural gas stream containing methane and a hydrocarbon component heavier than methane,
(A) cooling the natural gas stream under pressure to condense at least a portion thereof to form a condensed stream; and (b) expanding the condensed stream to a low pressure to form a liquefied natural gas stream. In said method,
(1) the natural gas stream is treated in one or more cooling steps to be partially condensed;
(2) separating the partially condensed natural gas stream, thereby providing a vapor stream and a liquid stream;
(3) dividing the vapor stream into at least a first gaseous stream and a second gaseous stream;
(4) combining the first gaseous stream with at least a portion of the liquid stream, thereby forming a composite stream;
(5) cooling the composite stream to condense substantially all of it and then expanding to medium pressure , where the medium pressure is the pressure of the distillation column ;
(6) the composite stream inflated said substantially condensed and sent to the heat exchange with the high vapor distillation stream volatile rising from fractionation stages of the distillation column, warmed by it;
(7) expanding the second gaseous stream to the medium pressure;
(8) inflating all remaining portions of the liquid stream to the medium pressure;
(9) sending the expanded and warmed composite stream, the expanded second gaseous stream and the remaining portion of the expanded liquid stream to the distillation column, where these streams are Separation into a high-efficiency steam distillation stream and a relatively less volatile fraction containing the majority of the hydrocarbon components heavier than the methane;
(10) The highly volatile steam distillation stream is sufficiently cooled by the substantially condensed and expanded composite stream, partially condensed and then separated to obtain a majority of the methane and light components. Forming a volatile residual gas fraction containing and a reflux stream;
(11) sending the reflux stream as top feed to the distillation column; and (12) cooling the volatile residual gas fraction under pressure to condense at least a portion thereof, thereby An improved method of forming. A method for liquefying a natural gas stream containing methane and a hydrocarbon component heavier than methane,
(A) cooling the natural gas stream under pressure to condense at least a portion thereof to form a condensed stream; and (b) expanding the condensed stream to a low pressure to form a liquefied natural gas stream. In said method,
(1) the natural gas stream is treated in one or more cooling steps and partially condensed;
(2) separating the partially condensed natural gas stream, thereby providing a vapor stream and a liquid stream;
(3) dividing the vapor stream into at least a first gaseous stream and a second gaseous stream;
(4) cooling the first gaseous stream to condense substantially all of it and then expanding to medium pressure , where the medium pressure is the pressure of the distillation column ;
(5) sending the substantially condensed and expanded first gaseous stream to heat exchange with a highly volatile steam distillation stream rising from the fractionation stage of the distillation column and thereby warming;
(6) expanding the second gaseous stream to the medium pressure;
(7) cooling the liquid stream and then dividing it into at least a first part and a second part;
(8) inflating the first part to the medium pressure and then warming;
(9) inflating the second part to the medium pressure;
(10) The expanded and warmed first gaseous stream, the expanded second gaseous stream, the expanded and warmed first part, and the expanded second part are Sent to a distillation column where the streams are separated into the highly volatile steam distillation stream and the relatively less volatile fraction containing the majority of the hydrocarbon components heavier than the methane;
(11) The highly volatile vapor distillation stream is sufficiently cooled by the substantially condensed and expanded first gaseous stream, partially condensed, and then separated to obtain a large amount of methane. Forming a volatile residual gas fraction containing partial and light components and a reflux stream;
(12) sending the reflux stream as top feed to the distillation column; and (13) cooling the volatile residual gas fraction under pressure to condense at least a portion thereof, thereby An improved method of forming. A method for liquefying a natural gas stream containing methane and a hydrocarbon component heavier than methane,
(A) cooling the natural gas stream under pressure to condense at least a portion thereof to form a condensed stream; and (b) expanding the condensed stream to a low pressure to form a liquefied natural gas stream. In said method,
(1) the natural gas stream is treated in one or more cooling steps and partially condensed;
(2) separating the partially condensed natural gas stream, thereby providing a vapor stream and a liquid stream;
(3) dividing the vapor stream into at least a first gaseous stream and a second gaseous stream;
(4) cooling the first gaseous stream to condense substantially all of it;
(5) cooling the liquid stream and then dividing it into at least a first part and a second part;
(6) expanding said first part to medium pressure and then warming , where said medium pressure is the pressure of the distillation column ;
(7) combining the second portion with the substantially condensed first gaseous flow, thereby forming a composite flow, and then expanding the composite flow to the medium pressure;
(8) the feed the composite stream that is expanded, to heat exchange with the high vapor distillation stream volatile rising from fractionation stages of the distillation column, warmed by it;
(9) expanding the second gaseous stream to the medium pressure;
(10) sending the expanded and warmed composite stream, the expanded second gaseous stream and the expanded and warmed first portion to a distillation column, where these streams are sent to the volatile Separating into a higher steam distillation stream and a relatively less volatile fraction containing the majority of the hydrocarbon components heavier than the methane;
(11) The highly volatile steam distillation stream is sufficiently cooled by the expanded composite stream, partially condensed, and then separated to contain the majority of the methane and light components. Forming a volatile residual gas fraction and a reflux stream;
(12) sending the reflux stream as top feed to the distillation column; and (13) cooling the volatile residual gas fraction under pressure to condense at least a portion thereof, thereby An improved method of forming.   A distillation column is in the lower section of the rectification column, and the highly volatile vapor distillation stream is sufficiently cooled in the upper part of the rectification column above the distillation column, partially condensed and simultaneously separated. 6. A process according to any one of the preceding claims, wherein a volatile residual gas fraction and a reflux stream are formed, after which the reflux stream flows to the top part stage of the distillation column.   The highly volatile steam distillation stream is sufficiently cooled in a dephlegmator, partially condensed and simultaneously separated to form a volatile residual gas fraction and a reflux stream, after which the reflux 6. A process according to any one of the preceding claims, wherein a stream flows from the dephlegmator to the top fractional stage of the distillation column.   8. A method according to any one of the preceding claims, wherein the volatile residual gas fraction is compressed and then cooled under pressure to condense at least a portion thereof, thereby forming a condensed stream.   8. The volatile residual gas fraction is heated, compressed and then cooled under pressure to condense at least a portion thereof, thereby forming a condensed stream. the method of. Volatile residual gas fraction, most of the methane, lighter components, and containing C ₂ components, the method according to any one of claims 1-9. Volatile residual gas fraction, most of the methane, lighter components, containing C ₂ components and C ₃ components, the method according to any one of claims 1-9.

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