MXPA97003373A

MXPA97003373A - Production of natural liquid gas in processing plants of natural gas criogen

Info

Publication number: MXPA97003373A
Application number: MXPA/A/1997/003373A
Authority: MX
Inventors: Houshmand Mory
Original assignee: Williams Field Services Company
Priority date: 1994-11-08
Filing date: 1997-05-08
Publication date: 1998-02-01

Abstract

The present invention relates to a method for liquefying a natural gas stream, characterized in that it comprises the steps of a. cooling the natural gas stream in a heat exchanger to produce a stream of condensed natural gas, wherein the natural gas stream comprises compressed waste gas from a cryogenic plant, wherein the cryogenic plant uses a separation medium to separate methane gas of the liquefied heavier hydrocarbons, in which the cooling is provided in the heat exchanger by a retrograde stream of the separated methane gas taken as the vapors projecting from the upper part of the separation medium, and in which the cooling and expansion are sufficient to liquefy at least a portion of the natural gas stream

Description

PRODUCTION OF LIQUID NATURAL GAS IN CRYOGENIC NATURAL GAS PROCESSING PLANTS DESCRIPTION OF THE INVENTION This invention relates to a new and useful method for liquefying natural gas. In particular, this invention relates to a method for producing liquid natural gas (LNG) having a high purity methane, which is very suitable for integration with cryogenic gas processing plants used to recover liquids from natural gas ( NGL). The natural gas that is recovered from the oil deposits is usually made up mostly of methane. Depending on the formation from which the natural gas is recovered, the gas will usually also contain varying amounts of heavier hydrocarbons than methane, such as ethane, propane, butanes and pentanes as well as some aromatic hydrocarbons. The natural gas may also contain non-hydrocarbons, such as water, nitrogen, carbon dioxide, sulfur compounds, hydrogen sulfide and the like. It is advantageous to liquefy natural gas for many reasons: natural gas can be stored more easily as a liquid than in the gaseous form, because it occupies a smaller volume and does not need to be stored at high pressures; the LNG can be transported in liquid form by trucks of liansporte or railway wagons; and the 1 NC stored can be evaporated and a network df pipe inserted to be used during the periods of peak demand. LNGs which have been highly purified (ie from approximately 95 to 99% by moles of methane purity) are suitable for use as a vehicular fuel, since they are clean burning, significantly lower costs than petroleum or other fuels. Purified, they provide almost the same d-displacement range between those filled as gasoline or diesel and requires the same filling time. The LNG with high purity methane can also be economically converted into compressed natural gas (CNG), another fuel for economical, purified vehicle. Clean Air, Clean Fuel (CAAA) and the 1992 Energy Policy Act that are forcing companies with large vehicle fleets are particularly urgent due to the Clean Air Act (CAAA) and the 1992 Energy Policy Act that are forcing companies with large vehicle fleets. that operate in areas with ozone problems, railroads and some stationary unit operators to convert the purest burning fuels Many methods are known to liquefy natural gas, which consists mainly of methane with secondary concentration of ethane and heavier hydrocarbons These methods generally include stages in which the gas is compressed, cooled, condensed and expanded.Cooling and condensation can be accomplished by heat exchange with various cooling fluids having successively lower boiling points ("Cascade System"). ), for example as described in Haak (U.S. Patent No. 4,566,459) and aher e t al. (U.S. Patent No. 3,195,316). Alternatively, a single refrigerant can be used at various different pressures to provide different temperature levels. A single fluid refrigerant which contains several refrigerant components ("Multiple Component System") can also be used. A typical combination of refrigerants is propane, ethylene and methane. Nitrogen is sometimes used. Swenson (U.S. Patent No. 4,033,735), Garier et al. (U.S. Patent No. 4,274,849), Caetani et al. (U.S. Patent No. 4,339,253) and Paradowski et al. (U.S. Patent No. 4,539,028) describe variants of the multicomponent cooling approach. The expansion is generally isenthal (by means of a throat device such as a Joule-Thomson valve) or isentropic (which occurs in the expansion turbine that produces the work). Despite the availability of these methods, here there are very few facilities in the United States that can produce significant amounts of vehicular grade LNG. In principle, any of the above methods can be used to liquefy natural gas. However, the capital cost of building and maintaining refrigeration systems to produce LNG can be high. Auxiliary cooling systems have high energy costs, using considerable amounts of fuel gas or electricity and producing significant air emissions (if combustible gas is used). The various existing LNG production processes and the possibility of producing LNG to various types of natural gas processing plants will now be considered. It will be observed that the need remains for an economic liquefaction process, which is compatible with the commonly available types of natural gas processing plants and which makes it possible to produce LNG in large volumes and with high purity, which would be necessary for be practical as a vehicle fuel (see also "LNG Supply", LNG Express, Volume IV, No. 1, pp. 1-4, January 1994, for another discussion of the need for LNG production of vehicle grade increased in the United States, the possible methods to produce LNG and the ability to modify existing plants to produce LNG).

Plants to save the maximum LNG are used to liquefy natural gas, which is stored for later use during periods of peak demand, to ensure that the municipal gas distribution grids have adequate gas supplies during the severely cold weather. These plants typically use cascade or multi-component refrigeration systems to liquefy pipeline quality gas. LNG Maximum Savings Plants produce the most LNG in the United States, but only a fraction of their capacity is available for use in transportation. In addition, most peak savers do not produce an LNG product with methane content high enough to be used as a vehicle fuel. Peak LNG Savers usually liquefy pipe quality gas, which typically contains too much ethane and heavier hydrocarbons to make a vehicle grade LNG product. Pachaly (U.S. Patent No. 3,724,226) discloses a plant which combines cryogenic fractionation with an expanding cycle refrigeration process to produce LNG. The intended purpose of this plant is the liquefaction of natural gas in remote locations, to facilitate transportation. This plant, however, does not produce LNG with high purity methane and, in addition, the design is such that operating costs will be high. The "Exteriors" or dedicated LNG plants are new plants designed and installed specifically for the purpose of producing vehicle grade LNG. These plants may have several designs, but all tend to use auxiliary refrigeration systems similar to those described above. The main disadvantage of this type of plant is that installing a new factory is more expensive than modifying an existing factory. The Nitrogen Reject Units (NRU) use cryogenic fractionation to liquefy methane and separate it from gaseous nitrogen. NRUs are used at sites where natural gas has a high nitrogen content, whether it occurs naturally or because nitrogen is injected into the oil reservoir to maintain reservoir pressure and increase oil recovery and / or gas. The methane purity of the LNG produced in these plants is often high enough to be used as a vehicle fuel. However, there are not a large number of these sites and they are often in remote areas, such NRUs do not represent a major source of LNG in the United States. In addition, they require the use of a large amount of auxiliary cooling.

Another type of plant that processes natural gas is the natural gas liquid (NGL) plant, which is used to recover the NGL. The NGL recovery comprises liquefying and separating the heavier hydrocarbon components from natural gas (ethane, propane, butanes, gasolines, etc.) from the methane fraction mainly, which remains in gaseous form (waste gas). The heavier hydrocarbons are commercially more valuable as liquids than as natural gas. NGLs are sold as supplies of petrochemical feeds, gasoline and fuel blending components. These plants also typically remove non-hydrocarbons such as water and carbon dioxide to meet the gas pipeline restrictions on these components. There are hundreds of such NGL plants throughout the United States. NGL plants include poor oil absorption plants, refrigeration plants and cryogenic plants. To the best knowledge of the inventors, such plants are not used to produce LNG (liquid natural gas). However, if a cost-effective process to liquefy residual natural gas can be integrated with these plants, NGL gas processing plants can become a significant source of vehicle fuel in the United States. The existing LGN Pico Savers, NRUs and natural gas processing plants used to recover NGL can be modified to produce vehicular grade LNG fuel by the addition of fractionation systems and auxiliary cooling systems. Additional cryogenic distillation systems can be used to increase the purity of the LNG by removing ethane and the heavier hydrocarbons from natural gas to produce LNG of fuel quality. However, since the installation of splitters and auxiliary cooling systems is very expensive, this is not always an economically feasible approach to produce high purity LNG suitable for vehicle fuel. A novel form has been discovered in which a basic, cryogenic NGL plant design can be modified to form a plant to produce LNG with high purity methane, without the need for additional fractionation and cooling systems. The invention is a process design for producing liquefied natural gas (LNG), which in the preferred embodiment of the invention is a high purity methane form of LNG that can be used as a vehicular fuel. Although less preferred, the invention can also be used to produce LNG of lower purity. The process can be incorporated with existing cryogenic natural gas liquid plants. The invention can also be used in new cryogenic plants. The term cryogenic refers to plants, which operate at temperatures below -45.55 degrees centigrade (-50 ° Fahrenheit). Not all cryogenic plants are NGL plants. However, the term "cryogenic" as used herein will always refer to the cryogenic plants used to produce the NGL. The inventive process produces LNG by liquefaction of a retrograde stream of waste gas leaving a cryogenic plant. The retrograde stream is preferably compressed first in the waste gas compressor of the cryogenic plant. The retrograde stream is condensed to a liquid using the top gas from the de-ethanizer of the cryogenic plant (or comparable cold gas stream from the plant) as a cooling medium. The condensed liquid then expands isentálpicamente to a series of pressures progressively minors using the effect of Joule-Thomson (JT) to take the LNG to a temperature and pressure in which it can be stored and transported conveniently. The invention offers gas processors at low cost, simple and effective means for reconversion of their existing factories to produce LNG and requires only minor additions of equipment. Both of the capital and energy costs are minimized. A key advantage of converting gas processing plants, especially cryogenic plants to produce LNG is the purity of the feed gas available from these factories. The invention is especially well suited for cryogenic plants with high ethane recoveries which produces a waste gas which easily meets the high methane purity restriction and low ethane content required in the LNG used as vehicle fuels. However, plants designed for recoveries with low ethane content can be used with some additional modifications. Natural gas often contains heavy hydrocarbons and does not contain hydrocarbons, water and CO2 in particular, which must be removed before liquefaction. Heavy hydrocarbons reduce the purity of the LNG and make it unusable for vehicle fuel due to the pre-ignition problems that occur, while CO2 and water must cause frozen crystals and hydrate formation, respectively, in the process of liquefaction of LNG. Cryogenic plants typically have the equipment in place to remove C02, water, and heavy hydrocarbons (such as NGLs). In these cases, the cost of pretreatment of the feed for the liquefaction process can be eliminated. The cost of pretreatment is a major capital cost of the new LNG liquefaction plants.

The invention also utilizes the cooling capacities of the upper streams of the cold demetallizer to condense the LNG feed, eliminating or reducing the need for an auxiliary cooling system. Depending on the relative capacity of the cryogenic plant and the production speed of the LNG, small additions to existing NGL plant cooling systems may be required. If the objective is to produce LNG for maximum savings purposes (to be vaporized and introduced into the pipeline to meet peak demand periods) the recovery of ethane is not critical and the invention can be integrated with almost any cryogenic plant. An object of the invention is to provide a method for the liquefaction of natural gas, which requires a lower capital investment than conventional refrigeration or progressive fractionation for existing cryogenic plants. Another object of the invention is to provide a method for the liquefaction of natural gas, which requires less energy and less operating costs than systems using conventional refrigeration systems. Still another object of the invention is to provide a method for manufacturing liquid natural gas, which has high purity, very consistent methane and which can be used as a vehicle fuel.

BRIEF DESCRIPTION OF THE DRAWINGS Figure 1 is a schematic diagram of the invention and a cryogenic plant with which it is used. Figure 2 shows an example of the use of the invention in combination with a turboexpander plant. Figure 3 shows an example of the use of the invention in combination with a JT plant. Figure 4 shows alternative points from which the feed gas for LNG process can be taken in a turboexpansion plant (4a and 4b) or a Joule-Thomson plant (4c and 4b). Figure 5 illustrates the use of the LNG taken from (a) the first vaporization cylinder, (b) the second vaporization cylinder, or (c) the storage tank as refrigerant in the condenser. The invention is a method and system for liquefying natural gas. In particular, this method is very suitable for producing liquid natural gas that has high purity methane. The invention can be used with almost any plant which uses a cryogenic process to recover natural gas liquids. The two main types of cryogenic plants that can be integrated with the invention are turboexpansor plants (TXP) and Joule-Thomson (JT) plants. The differences between these two types of plants will be discussed subsequently.

The invention is preferably implemented in combination with an existing cryogenic plant. However, the invention can be incorporated into the design of new plants as well. Figure 1 is a schematic diagram showing the invention used in combination with a typical cryogenic plant. The inlet cooling train 20, the expansion inlet separator 30, the expansion medium 40, the expansion outlet separator 50, the liquid fractionation means 60 and the waste gas compressor 70 are components of the cryogenic plant 1 The components are common for most cryogenic plants. The boundaries of the cryogenic plant 1 are indicated by a dotted line. The natural gas feed material (ie, the plant feed) is introduced into the inlet 10 and cooled in the inlet cooling train 20, which causes some of the heavier hydrocarbon components to condense in such a manner that the resulting cooled natural gas is a first gas / liquid mixture. The inlet cooling train 20 may consist of one or more of the following types of heat exchangers: plate fin heat exchanger, shell and tube heat exchanger, or cooler with refrigeration; or other heat exchangers. These exchangers can use the upper gas 208 of the liquid fractionation means 60, a supplemental coolant 24, such as propane or liquid from liquid fractionation means 60 as a cooling medium. The first gas / liquid mixture is separated into a first liquid fraction and a first gas fraction in the expansion inlet separator 30, which is a conventional two-phase separator or comparable separation means. The first gas fraction is directed to the expansion medium 40, where it is expanded to cause the cooling and reduction of the pressure, so that it forms a second gas / liquid mixture. The expansion means 40 is preferably a turboexpander (in a turboexpansion plant); alternatively, it may consist of one or more Joule-Thomson (JT) valves or some other means of expansion. The second gas / liquid mixture produced in the expansion medium is displaced via line 206 to the expansion outlet of the separator 50, which may be a two-phase separator or may be the enlarged upper portion of a demethanizer ( which functions as a two-phase separator) where it is separated into a second gas fraction and a second liquid fraction. The second liquid fraction of the expansion outlet separator 50 and the first liquid fraction of the inlet expansion of the separator 30 are introduced to the liquid fractionation means 60.

The liquid fractionation means 60 is usually known as a demethanizer, but it can also be mentioned as a fractionation column with boiler options and / or a higher condenser. The main purpose of the liquid fractionation means 60 is to remove the methane, which may have condensed with the liquids formed during the expansion. The liquid fractionation means 60 separates the upper gas (also called waste gas) comprising mainly methane, from heavier hydrocarbons such as ethane, butane, propane, etc. which leaves the fractionation means 60 as liquid. In a general sense, the expansion inlet spacer 30, the expansion means 40, the expansion outlet spacer 50 and the liquid fractionation means 60, together serve as a fractionation means, and some other arrangement of similar components may be used to perform the same fractionation function (for example separation of methane gas mainly from heavier hydrocarbon liquids). Although the configuration shown here is preferred and is more commonly found in cryogenic plants, any other configuration of the components which perform a fractionation function may alternatively be used in the practice of the invention.

The upper stream 208 (upper gas and / or second gas fraction of the expansion outlet separator 50) is used as a refrigerant in the inventive process. The upper stream 208 is used as a refrigerant because it provides the lowest temperature available in the cryogenic plant and allows the liquefaction of the residual gas stream at moderate pressure. The invention is preferably used in cryogenic plants in which the upper stream 208 has a temperature of about -128.88 to -73.33 degrees centigrade (-200 to -100 degrees F) and a pressure of 7.03 to 42.18 kg / cm2 (100 to 600 psig). A retrograde stream 209 of the upper stream 208 serves as a refrigerant in the waste gas condenser 80. The upper stream 208 is also preferably used as a cooling medium in the incoming cooling stream 20. The upper stream 208 is compressed in the compression train 70. In the case that the expansion means 40 is a turboexpander, the compression train 70 preferably comprises the auxiliary compressor of the turboexpander plus one or more additional compressors (various types of compressors can be used, example, centrifugal compressors, reciprocating compressors, screw compressors, or other compressors) to provide additional compression. In the case where the expansion means 50 is somewhat different from a turbo expander, the compression train 70 comprises one or more compressors of the types listed in the foregoing, or the like, but not the auxiliary compressor driven by the turboexpander. A retrograde stream 210 of the compressed top stream (waste gas) is used as the feed gas to a waste gas condenser 80, where it condenses to form the condensed stream 214, which comprises liquid natural gas, which has been cooled at its bubble point or at a lower temperature. The retrograde stream 210 typically has a temperature between about 17.78 and about 204.44 degrees centigrade (about 0 and about 400 degrees.

F) and a pressure between approximately 7.03 and 84.36 kg / cm2 (approximately 100 and 1200 psig). It is preferable that the retrograde stream 210 have a temperature between about -6.66 and about 93.33 degrees centigrade (about 20 and about 200 degrees.

F) and a pressure between approximately 21.09 and 63.27 kg / cm2 (approximately 300 and 900 psig). The retrograde stream 210 is also referred to as the feed of the condenser 210. The waste gas condenser 80 is cooled by the retrograde stream 209 and optionally other cold gas streams taken from other stages in the cryogenic plant or LNG plant., or by an auxiliary refrigerant stream 230. The feed of the condenser 210 is condensed in the waste gas condenser 80 at the bubble point temperature or lower. The condensed stream 214 is typically at a pressure of approximately 7.03 to 49.21 kg / cm2 (approximately 100 to 700 psig) with the associated bubble point temperatures of -130.56 to -73.33 degrees centigrade (-203 to -100 degrees F), and preferably at a pressure of approximately 21.09 to 49.21 kg / cm2 (approximately 300 to 700 psig), with the associated bubble point temperatures of -106.11 to -100 degrees centigrade (-159 to -100 degrees F). The condensed stream 214 is expanded in the expansion means 90 to further reduce the temperature and pressure of the LNG. During expansion a secondary portion of the liquid is vaporized. The expansion means 90 preferably comprises one or more vaporization cylinders in which the natural gas stream is isenthapically expanded ("evaporated") using the Joule-Thomson effect (JT). Alternatively, the expansion means may also consist of an expander. The expansion step carried out in the expansion means 90 reduces the pressure of the liquid natural gas to a level at which it can be conveniently stored and transported. The LNG product will typically have a pressure of about 0.07 to 7.03 kg / cm2 (about 0.0 to 100 psig) and a temperature of about -161.66 to -128.88 degrees centigrade (about -259 to -200 degrees F) and preferably has a pressure from approximately 0.03 to 0.70 kg / cm2 (approximately 0.5 to 10 psig) and a temperature of approximately -161.11 to -155 degrees centigrade (approximately -258 to -247 degrees F). The LNG product can be taken from exit 11 for storage or transportation or any other desired use. For the invention to be integrated with an existing cryogenic plant, it is necessary that the cryogenic plant meets certain specifications (for example, that it has certain components and certain operating conditions). Furthermore, it is important that the invention be integrated with the existing plant in such a way that the operation of the existing plant in its original capacity (for example production of natural gas liquids, etc.) is not degraded. Assuming that the design of the cryogenic plant is suitable for integration with the invention, the details of the preferred embodiment of the invention depend on the design of the cryogenic plant with which it is to be integrated. The best mode of the invention is therefore determined by taking into account the following guidelines. Many variables affect the quantity and quality of the LNG produced with the invention as well as the energy requirements. The following is discussed as the supply quality of the condenser, the pressure of the capacitor, the condensing temperature and the number of expansion stages that affect the invention. The typical operating parameters for the invention are also discussed. The temperatures and pressures in a given plant can be calculated with the use of Process Simulation Modeling. Software to perform such simulations is readily available (for example: HYSIMMR, CHEMSHAREMR, and PROSIMMR) and familiar to those with ordinary skill in the art. Condenser Power Quality The condenser feed (ie, the retrograde stream of the compressed waste gas from the cryogenic plant) must contain less than 50 ppm of carbon dioxide and virtually free of water to prevent the formation of hydrate and frozen fragments of C02 occurring in the LNG liquefaction process. The water is typically removed from the natural gas stream of the cryogenic plant by dehydration with glycol (absorption) followed by a molecular sieve bed (adsorption). Alternatively, a molecular sieve bed alone, or other conventional methods can be used to remove the water. The molecular sieve dehydration units are usually installed upstream of the cryogenic plant to remove the water before the gas enters the cooling train.

If natural gas is not treated at the inlet of the cryogenic plant to eliminate CO2, it may be necessary to install a CO2 elimination system 79 to remove the CO2 from the waste gas, which is used as a feed for the inventive process, in which case the DC removal system 79 would be placed between the output of the compression train 70 and the inlet of the waste gas condenser 80. Some of the possible treatment systems, which must be installed to eliminate the C02 are a system amine or a molecular sieve. If an amine system is used, the exhaust gas from this system must also be dehydrated. These methods are well known to people with ordinary skill in the art. Before the feed gas is introduced into the turboexpander or the JT plant, the gas can be treated to remove non-hydrocarbon components such as hydrogen sulfide (H2S), sulfur, mercury, etc. if they are present in quantities that may adversely affect the operation of the cryogenic plant. Numerous methods, which can be used to eliminate these components, are known to those of ordinary skill in the art and will not be discussed here. The amount of methane, inert gases (such as nitrogen), ethane and hydrocarbons heavier than ethane in the condenser feed, will determine the quality of the LNG produced. The evaporation gases produced during the process will be predominantly methane with a high percentage of nitrogen, while ethane and heavy hydrocarbons will remain in liquid form throughout the process of LNG liquefaction. Therefore, ethane and heavy hydrocarbons tend to be concentrated in the LNG, such that the mole fraction of ethane and heavy hydrocarbons in the LNG contained in the storage tank will be greater than that of the condenser feed. It is preferred that the cryogenic processes integrated with the invention be capable of removing high percentages of ethane and essentially all of the heavier hydrocarbons and propane from the inlet stream of the cryogenic plant to meet the high purity of methane required for vehicle fuel. LNG The feed composition of the plant and the required ethane recoveries will depend on the purity of the desired LNG and the conditions of the LNG process. It may be necessary to modify the operation of the cryogenic plant to increase the recovery of ethane. The possibilities to increase the recovery of ethane include the installation of an additional fractionator (often called a cold fractionator) modify the flow scheme with an intense ethane recovery process and / or install an additional residual gas recompressor, which would allow that the operating pressure of the demethanizer is decreased. Pressure in the Supply Current The pressure of the supply of the condenser that enters the residual gas condenser is critical for the design of the process, since it determines the condensing temperature of the supply current LNG. By increasing the condenser feed pressure, the temperature required to liquefy the LNG feed stream will also increase. The condensation pressure must be greater than the operating pressure of the demethanizer, but preferably less than the critical methane pressure (48.51 kg / cm2 (690 psig) The condenser supply must be of sufficiently high pressure so that it can be condensed by the available cooling of the demetallizer's upper streams, plus any of the vaporizing vapors directed to the gas condenser residual and any additional cooling (if required) As discussed in the following (see Condensation Temperature) it is advantageous to condense the feed to its bubble point (100% saturated liquid), or at a lower temperature. Feeding also affects the amount of vaporizing vapors that are produced in the vaporization stages.If the condenser supply is condensed to its bubble point, the higher its pressure, the more vapors of vaporization will be generated during the vaporization stages. Increasing the amount of vaporizing vapors and also decreasing the quality of the LNG product such as ethane and the heavier components concentrated in the LNG product. Condensation Temperature The condensation temperature is another critical operation parameter. As mentioned in the foregoing, the condenser feed is preferably condensed at its bubble point temperature or below the feed stream pressure LNG. The bubble point temperature for a given pressure is defined as the temperature at which the first vapor bubble is formed, when a liquid is heated to constant pressure. At the bubble point, the mixture is saturated liquid. If the higher demetallizer streams provide sufficient cooling, it is preferred that the feed is not condensed to its bubble point, but also that it is cooled to subcool the liquid. The subcooling of the liquid reduces the amount of vapors formed during the expansion stages. Therefore, more liquid will be produced in the liquefaction process. A lower flow rate of the condenser feed is then required to produce a given amount of the liquid product LNG if the feed is subcooled rather than just condensed to its bubble point. Number of Vaporization Stages The selection of the number of vaporization stages affects the quality and quantity of the LNG produced. In most cases, the number of vaporization stages and the vaporization pressures are established in such a way that vaporisation vapors can be used in other plant processes, such as plant fuel systems, without the need for recompression. Alternatively, the vaporization vapor can be recompressed to pipe sales or recycled in the LNG production process from the amount of vapors generated at these levels exceeds the fuel gas demand of the plant. The greater the number of vaporization chambers used (and thus the greater the pressure increases between the vaporization chambers), the less vaporization vapor is produced and the greater the amount of liquid natural gas, which can be recovered. The amount of vaporization vapors produced affects the quality of the LNG as well as the amount of LNG produced (or the amount of feed gas required to produce a given amount of LNG). Since the number of vaporization stages is increased, the benefits of reducing the amount of vaporization gas produced in each additional stage, however deteriorates very rapidly. The more vaporization chambers are used, the expense associated with the purchase and maintenance of the equipment increases. In this way, a commitment must be reached between maximizing the quantity and quality of the LNG and minimizing equipment costs. In the preferred embodiment of the invention of Example 1 (shown in Figure 2), it is considered optimal to perform three sprays (ie, two vaporization cylinders and a storage tank). However, a greater or lesser number of evaporation chambers should be preferable in a different plant, and they can be used without departing from the essential nature of the invention. Cooling Capacity The volume of the plant must be large enough, so that the vapors leaving the top of the demethanizer are sufficient to provide cooling of both the waste gas condenser and the inlet cooling train. The temperature of the vapors projecting from the top of the demethanizer and the quantity of vapors leaving the top of the demethanizer that can be used as a cooling medium (with equivalent loss of cooling in the inlet train of the cryogenic plant) can limit the amount of cooling that must be carried out in the waste gas condenser. By the use of the vapors from the top of the demethanizer to condense the waste gas, an equivalent amount of refrigeration is lost in the inlet cooling train of the cryogenic plant and NGL recoveries may be reduced. The operation of the cryogenic plant under the other conditions needs to be evaluated. To compensate for this loss and to maintain the plant's natural gas liquid (NGL) recoveries, additional high cooling may be required in the inlet cooling train of the cryogenic plant. In cases where sufficient demethanizer and vaporizing vapors are available to cool the LNG feed to its bubble point, but additional cooling may be required to subcool the liquid, the capital required to install such a cooling system would probably not be cost effective . EXAMPLE 1 The following example is presented to illustrate the operation of the preferred embodiment of the invention more clearly. This embodiment of the invention is illustrated in Figure 2. In this example, the invention is integrated with a turboexpanded cryogenic plant, which was designed for the primary function of processing natural gas to produce natural gas liquids (e.g., ethane, propane and heavier hydrocarbons in liquid form) and pipeline quality natural gas. As mentioned previously, the invention can be used with other plant configurations and the example is intended to illustrate the use of the invention, but should not be considered as limiting the invention for use with this particular type of plant. This cryogenic plant, turboexpansora processes 350 mmscfd (feeding of standard cubic millions per day) of natural gas. When used in combination with the invention, the plant is capable of producing 37,100 liters (10,000 gallons) per day of LNG. The natural gas, the feed of the plant which has been previously dehydrated and treated to remove the carbon dioxide gas, is introduced into the inlet 10 of the cryogenic plant. Alternatively, the carbon dioxide can be removed from the gas in later stages of the process, however it must be removed before the condensation steps (liquefaction), which is carried out in the waste gas condenser 80, because the Low temperatures used will cause the C02 to freeze in the LNG process. The feed of the plant has a molar composition of 92.76% by moles of methane, 4.39% by moles of ethane, 1.52% by moles of propane, 0.91% by moles of butane and heavier hydrocarbons and 0.42% by moles of nitrogen.

The inrush current 10 is divided into 2 streams with the stream 202 flowing "through the gas / gas heat exchanger 21 and the inlet cooler 22 and the stream 203 flowing through the coil 23 of the demethanizer. of gas / gas heat 21, the inlet gas cooler 22 and the coil 23 of the demethanizer together comprise the inlet cooling train 20 in this example.The gas / gas exchanger 21 uses the waste gas left by the turboexpansion plant To cool the inlet current, this heat exchanger can be of the shell and tube heat exchanger type or aluminum plate fin heat exchanger, or some equivalent type of heat exchanger. It uses a cooler or coolant 24 to further cool the inlet stream.Propane is the refrigerant normally used in the coolers of turboexpansion plants, without Other refrigerants may be used. The gas / gas exchanger 21 and the inlet cooler 22 can also be combined in a heat exchanger with multiple flow paths. More than one gas / gas exchanger and / or inlet cooler can be used in the practice of the invention, as individual components combined in a heat exchanger.

The stream 203 is cooled in the coil 23 of the demethanizer by the cold liquid streams 62 and 63 extracted from demethanizer 61. The concomitant heating of the cold liquid streams by the hot inlet gas stream provides the heat required for the proper operation of the liquid. demethanizer 61. Demethanizer 61 is a fractionator for removing any methane that may have condensed with liquid hydrocarbons (eg, ethane, propane, butane) which are a product of the cryogenic plant. In the inlet cooling train 20, some of the heavy hydrocarbons are condensed from the inlet stream. Therefore, the stream 204 which is formed of the combined streams leaving the inlet cooler 22 and the coil of demethanizer 23 will be a two-phase stream consisting of liquid and gas. The stream 204 is introduced into the expander inlet separator 30, where the liquid which condenses in the inlet cooling train 20 is separated from the gas phase. The liquid fraction is directed to the midpoint of the demethanizer 61. The gas fraction is directed to the expander 40 of the turboexpander 41, where the gas is isentropically expanded until it reaches the same pressure as the demethanizer 61. In the turboexpander, the arrow of the expander 40 it is connected to the compressor 71, so that the work created during the expansion can be used to drive the compressor 71. The encentric expansion reduces the temperature of the gas substantially, which causes ethane and heavy hydrocarbons to condense from the methane gas predominantly, forming a two phase liquid / gas stream 206. Instead of a turbo expander, a JT valve can be used to perform expansion, although this is less preferred (this alternative is described in Example 2). The two phase stream 206 is fed to the top of the demethanizer 61. In this example, the enlarged upper portion of the demethanizer 61 functions as the expander outlet separator 50 and the attached bottom portion serves as the fractionation means 60. The vapors leaving the top of the demethanizer as the waste gas (vapors projecting from the top) and the liquid fraction is fed to the fractionation section of the demethanizer. Alternatively, a separate expander outlet separator may be installed between the expander and the demethanizer, if desired to reduce the size of the enlarged upper section of the demethanizer. In this example, the top demethanizer gas (residue taken from the top of the demethanizer) is preferably about -106.66 degrees centigrade (about -160 degrees Fahrenheit), and at a pressure of approximately 18.27 kg / cm2 (approximately 260 psig). In general, the required temperature and pressure will vary "depending on the pressure of the inlet stream 10, the amount of recompression of the available residue, and the required ethane recoveries.The temperatures are in the range of about -128.88 degrees to -73.33 degrees. Celsius (approximately -200 to -100 degrees Fahrenheit and pressures of 7.03 to 42.18 kg / cm2 (100 to 600 psig) are generally adequate The vapors projecting from the top of the demethanizer are divided into a main stream 208 and a retrograde stream 209 The retrograde stream 209 is directed by the waste gas to the condenser 80, where it is used as a cooling medium during the LNG liquefaction process, the retrograde stream 209 subsequently meets the main stream 208, which is directed to the gas exchanger. / gas 21 for the cold gas stream 202. The gas distribution between the retrograde stream and the main stream is controlled by the temperature control valve 81. In the preferred embodiment of the invention, the valve is controlled such that the temperature at which the LNG is cooled in the condenser offgas is kept constant. For example, the control valve 81 can be software controlled or controlled by a hardware control system. The design and use of such a control system is known to those with ordinary skill in the art. The compression train (70 in Figure 1) consists of the reinforcing compressor 71, which is part of a turbo expander 41 and two additional compression covers. The gas in the main stream 208 is compressed in the booster compressor 71. The compressed gas, which leaves the booster compressor 71 is compressed in the compressor 72 in the first stage and cooled in the first stage after the cooler 73. first stage discharge gas (first stage outlet after cooler 73) is divided into a retrograde stream 210 and a main stream 211. Retrograde stream 210 serves as the feed for a waste gas condenser 80, while the main stream 211 is compressed in the compressor 74 in the second stage and cooled in the second stage after the cooler 75, after which it is preferably sent to a natural gas pipeline, either directly or after additional recompression, according to be necessary. The feed of the capacitor 210 may alternatively be from some other point of the compression train, as shown in Figure 4a and 4b. It is preferred to take the feed of the condenser 210 of the compression train after it has been cooled. In the present example, the feed of the condenser 210 has a molar composition of 98.83 mole% methane, 0.70 mole% ethane, 0.02 mole% propane and 0.45 mole% nitrogen, a temperature of 23.33 degrees centigrade ( 74 degrees F) and a pressure of 31.28 kg / cm2 (445 psig). In a turboexpander plant that has a different compression train arrangement shown here, the condenser feed can be taken from any point or points in the recompression train, which provides adequate temperature and pressure levels (see Feed Pressure of Condenser, Previous Condensation Temperature The feed pressure of the condenser 210 is preferably in the range of about 7.03 to 84.36 kg / cm2 (about 100 to 1200 psig) and more preferably between about 21.09 and 63.27 kg / cm2 (about 300 and 900 psig) The temperature of preference is between about 17.71 degrees Celsius and 204.44 degrees Celsius (of about 0 and 400 degrees F) and more preferably between about -6.66 and 93.33 degrees Celsius (about 20 and 200 degrees Celsius) F) The supply of the condenser 210 is directed to the waste gas condenser 80, where it is liquefied under pressure by exchange of heat with the vapors leaving the top of the demethanizer and the steaming vapors.

The feed of the condenser 210 is preferably cooled to its bubble point. In other embodiments of the invention, it may be preferable to cool the condenser feed to a still lower temperature (this is called subcooling). In the present example, the feed of the condenser 210 is taken after the waste gas from the turboexpander process has withstood a recompression step at 31.28 kg / cm2 and 23.33 degrees centigrade (445 psig and 74 degrees F). To condense the feed to its bubble point at 31.28 kg / cm2 (445 psig), the current needs to be cooled to -94.44 degrees centigrade (-138 degrees Fahrenheit). In general, the condensed natural gas stream 214 will preferably have a temperature of about -130.55 to -73.33 degrees centigrade (about -203 to -100 degrees F) and the pressure of about 7.03 to 49.21 kg / cm2 (from about 100 to 700 psig) and more preferably from about -106.11 to -73.33 degrees centigrade (about -159 to -100 degrees F) and pressure of about 21.09 to 49.21 kg / cm2 (about 300 to 700 psig). In the preferred embodiment of the invention, the waste gas condenser 80 is an aluminum plate fin heat exchanger welded with brass with multiple flow paths (four in this example). Alternatively, a series of cover and ubo heat exchangers may be used, instead of a plate fin heat exchanger. The retrograde stream 209 of the vapors projecting from the top of the demethanizer is the main coolant and is used because it has the lowest temperature of any current in the cryogenic plant and allows the liquefaction of the inlet stream of natural gas 210 to moderate temperature and pressure. Vaporization vapor streams 212 and 213 provide complementary condensation work and help reduce the amount of steam leaving the top of the demethanizer to condense the inlet stream LNG 210. In the present embodiment of the invention, the condensed natural gas stream 214 is expanded isentálpicamente or "evaporated" through several Joule-Thomson valves (JT) to reduce the temperature and pressure of condensed liquid, so that it can be stored or transported conveniently. of condensed natural gas 214 leaving the residue condenser 80 is introduced to the cylinder of 91 high pressure vaporization (HP) through the Joule-Thomson (JT) 92 valve (also known as an expansion valve). The 91 HP evaporating cylinder is a two-phase separator, which separates the liquid stream 215 and the vaporization vapor stream 212 produced during expansion or "vaporization". Steam vapor HP in stream 212 is directed back to the waste gas condenser 80 which serves as the supplemental cooling medium and subsequently to the 220 HP fuel gas line of the plant. The temperature of the gas and liquid in the HP vaporization cylinder is -113.88 degrees Celsius (-173 degrees F), and the pressure in the HP vaporization drum is set at 14.76 kg / cm2 (210 psig), since it is It is the same as the pressure of the HP fuel line of the cryogenic plant and therefore recompression is not required before introducing the evaporation gas to the HP fuel line. The HP evaporated liquid 215 is directed to the low pressure (LP) evaporation cylinder 93 by means of the Joule-Thomson 94 (JT) valve. The evaporation cylinder LP is also a two-phase separator, which separates the liquid stream 216 and the evaporation vapor stream 213 produced during evaporation through the valve 94 JT. The evaporation vapor stream LT 213 is directed back to the waste gas condenser 80 to serve as supplemental cooling and subsequently to the LP 221 fuel line of the cryogenic plant. The pressure in the LP evaporation cylinder is set at 5.48 kg / cm2 (78 psig), which is the pressure of the LP 221 fuel line of the plant used in this example and the temperature is -133.88 degrees Celsius (-209 degrees F). The cylinders 91 and 93 evaporators are preferably stainless steel pressure vessels, ASME Code, which function as two-phase separators to separate the vaporization vapor from the liquid LNG. HP and LP vaporization vapors are concentrated in methane and nitrogen. The vapors of the HP evaporation cylinder are 98.81% by moles of methane, 0.95% by moles of ethane, 0.03% by moles of propane, and 0.21% by moles of nitrogen, while the vapors of the LP evaporator cylinder are 98.72% by weight. moles of methane, 1.17% in moles of ethane, 0.03% in moles of propane and 0.08% in moles of nitrogen. The LNG taken from the 93 LP evaporator cylinder is sent to the LNG storage tank 95 via a final 96 Joule Thomson valve. The LNG is expanded through the valve at a pressure between 0.07 and 7.03 kg / cm2 (0.0 and 100 psig) and -162.22 and -153.82 degrees centigrade (-260 and -245 degrees F), in which it can be easily stored. The LNG product is most preferred at a pressure of 0.03-0.70 kg / cm2 (0.5-10 psig) and at a temperature of -161.11 to -155.0 degrees centigrade (-258 to -247 degrees Fahrenheit).

The vapors 217 formed in the final evaporation through the JT 96 valve are heated in the boiler exchanger 101 and compressed by the kettle compressor 102 and cooled in the re-cooler 103 to be used as a fuel gas in the gas processing plant or sent to a sales gas pipeline. The total evaporation vapors generated in the HP evaporator cylinder, the LP evaporation cylinder and the storage tank is 0.846 mmscfd. The final LNG product is 98.5 mole% methane, 1.45% mole ethane, 0.04 mole% propane and 0.01 mole% nitrogen. Although it is preferred to return the vapors from the evaporation chambers to the lowest pressure at which the vapors can be used (ie in the plant fuel lines) this is not essential for the practice of the invention and the steaming vapors they could also be removed by some other means, for example when burned or vented to the atmosphere. Alternatively, evaporation vapor streams 212, 213 and 217 can be recycled, combined with stream 210 and used as the feed to the LNG liquefaction process. Storage tank 95 can take several forms: storage tanks with capacities less than 265,370 liters (70,000 gallons) would typically be shop-made containers, ASME Code. These tanks usually have carbon steel, stainless steel, an outer cover of nickel or aluminum; a container of stainless steel, nickel or an inner aluminum cover and are vacuum-lined with an insulation between the two covers. Tanks greater than 265,370 liters (70,000 gallons) are usually tanks erected in the field. Concrete containers can also be used. EXAMPLE 2 In Example 1 (illustrated in Figure 2), the invention is integrated with a Turboexpansive Plant (TXP =) in the present example, the invention is integrated with a type of cryogenic plant known as a Joule-Thomson or JT plant , as shown in Figure 3. The plant JT shown in Figure 3 is similar to the TXP shown in Figure 2, with the difference that as the expansion medium 40, the JT plant uses an expander or a valve 42. Joule-Thomson (JT) instead of the expander used in the TXP to reduce the temperature of the gas stream. As a consequence, the reinforcing compressing portion of the turboexpander is no longer present, and the compression train comprises only the compressors 72 and 74 and their associated re-coolers 73 and 75. In case the plant JT has only one recompressor, the power supply of the condenser 210 would be taken after the recompressor 72 and the re-cooler 73. Alternatively, if the plant JT has two stages of recompression (as shown) the power supply of the condenser can taken after the first stage of recompression and re-cooling (see Figure 4c), or after both stages of recompression and cooling have been performed as shown in Figure 4d. In addition, if any other compression configuration is used, the capacitor supply can be taken at any point or points in the recompression train, which provides adequate pressure and temperature levels (see Pressure of Condenser Supply, Condensation Temperature, previous). The expansion through a JT valve, as shown in the present example, is an isentálpica expansion, instead of an isentropic expansion as it happens through a turboexpansor. An isentropic expansion removes energy from the gas in the form of external work, while an isentálpica expansion eliminates no energy of the gas. Thus, using an isentálpica expansion to reduce the temperature of the entrance gas is less efficient than to use an isentropic expansion. The temperatures of the gas leaving the isenthalpan expansion (JT) are greater than the temperatures produced during an isentropic expansion, giving the same conditions of initial temperature, pressure and outlet pressure. The turboexpander used in Example 1 therefore produces lower temperatures than the expander JT used in the present example, causing more liquids to condense (mostly ethane) which increases the recovery of the NGL product in the cryogenic plant. Due to the lower ethane recoveries of the JT plant, the JT plant may require modifications to the cooling system of the inlet cooling train of the JT plant or the addition of the inlet cascade cooling system to increase ethane recoveries , to produce vehicle grade LNG. If the invention is to be used to produce an LNG product with lower methane purity (for example in the peak savings application), these modifications to the cooling system will probably not be necessary. A JT expansion, although generally smaller preferred for reasons of efficiency, can be used without departing from the essential nature of the invention. ALTERNATE MODALITIES OF THE INVENTION Use of LNG as a Cooling Medium Some of the liquid streams produced in the LNG liquefaction process (ie cooled LNG streams) can also be used as the cooling media to help condense the current LNG feed in the waste gas condenser 80. For example, a retrograde current can be taken from any of the following streams, as shown in Figure 5: a) the retrograde current 223 of Current 215 of the Cylinder Fluid of evaporation HP. In the plant shown in Example 1, this could have a temperature of -113.88 degrees centigrade (-173 degrees F); b) the retrograde current 224 of the Liquid Current 216 of the Evaporation Cylinder "" LP. In the plant shown in Example 1, this would have a temperature of -133.88 degrees centigrade (-209 degrees F); or c) the retrograde current 225 of Stream 218 of the storage tank product. In the Plant shown in Example 1, this would have a temperature of -162.22 degrees centigrade (-260 degrees F). One or more of the retrograde currents 223, 224 or 225 could be directed back to the waste gas condenser 80 to help condense the LNG feed stream. This would require that at least one additional flow path be added to the waste gas condenser. The gases of the retrograde stream leaving the waste gas condenser 80 could be directed to a plant fuel system, recommended for pipeline sales or recycled in the LNG process at an appropriate location. The current or retrograde currents selected as the supplemental cooling medium could more likely be cooled than the stream of vapors leaving the top of the demethanizer, such that the LNG feed could be cooled to a lower temperature than if the only the current of the vapors leaving the top of the demethanizer will be used. If the input stream LNG is cooled to a much lower temperature, the invention can be integrated into a cryogenic plant, where only low pressure LNg feeds are available and the vapors leaving the top of the demethanizer are not cold enough to liquefy to the input current. The preferred embodiment of the invention was illustrated by Example 1. As mentioned previously, the preferred embodiment of the invention is partially dependent on the design of the cryogenic plant with which the invention is to be integrated. Therefore, in addition to the presented examples in which the invention is used in combination with particular cryogenic plant designs, an extensive general description of a guide for the implementation of the invention has been provided. Although the present invention has been described and illustrated along with many specific embodiments, those skilled in the art will appreciate that variations and modifications can be made without departing from the principles of the invention as illustrated, described and claimed herein. The modalities described are going to be considered in all aspects only as illustrative and not restrictive. The scope of the invention is therefore indicated by the appended claims, rather than by the foregoing description. All changes, which come within the meaning and range of equivalence of the claims are encompassed within its scope.

Claims

CLAIMS 1. A method for liquefying a stream of natural gas, characterized in that it comprises the steps of a. cooling the natural gas stream in a heat exchanger to produce a stream of condensed natural gas; wherein the natural gas stream comprises compressed waste gas from a cryogenic plant; wherein the cryogenic plant uses a separation medium to separate methane gas from the heavier liquefied hydrocarbons; wherein the cooling is provided in the heat exchanger by a retrograde stream of the separated methane gas taken as the vapors projecting from the upper part of the separation medium; and wherein the cooling and expansion stages are sufficient to liquefy at least a portion of the natural gas stream.
2. The method of compliance with the claim 1, further characterized by comprising the steps of: b. expand the stream of condensed natural gas to produce a liquid natural gas product.
3. The method of compliance with the claim 2, characterized in that step b) comprises carrying out at least one isotopically "evaporative" expansion of the condensed natural gas stream by means of a Joule-Thomson valve.
4. The method according to claim 2, characterized the compressed residual gas of the cryogenic plant has a pressure of about 7.03 to 84.36 kg / cm2 (about 100 to 1200 psig) and a temperature of about 17.78 to 204.44 degrees centigrade (about 0 to about 400 degrees F); wherein the condensed natural gas stream has a pressure of about 7.03 to 49.21 kg / cm2 (about 100 to 700 psig) and a temperature of about -130.55 to -73.33 degrees centigrade (about -203 to -100 degrees F); and wherein the liquid natural gas product has a pressure of about 0.07 to 7.03 kg / cm- ^ (about 0 to 100 psig) and a temperature of about -161.66 to 128.88 degrees centigrade (about -259 to -200 degrees F) ).
5. The method of compliance with the claim 2, characterized in that the compressed residual gas from the cryogenic plant has a pressure of approximately 21.09 to 63.27 kg / cm2 (approximately 300 to 900 psig) and a temperature of approximately -6.66 to 93.33 degrees centigrade (approximately 20 to 200 degrees F); wherein the condensed natural gas stream has a pressure of about 21.09 to 49.21 kg / cm2 (about 300 to 700 psig) and a temperature of about -106.11 to 73.33 degrees centigrade (about -159 to -100 degrees F); and wherein the liquid natural gas product has a pressure of about 0.070 to 7.03 kg / cm2 (about 0 to 100 psig) and a temperature of about -161.66 to -128.88 degrees centigrade (about -259 to -200 degrees F) .
6. The method of compliance with the claim 2, characterized in that step b comprises the sub steps of: i. perform a first expansion of isenthalpic "evaporation" of the condensed natural gas stream through a first Joule Thomson valve to produce a first liquid fraction and first vapor fraction; ii. perform a second expansion of isthnopal "evaporation" of the first liquid fraction through a second Joule-Thomson valve, to produce a second liquid fraction and a second vapor fraction; and iii. perform a third expansion of isenthalpic "evaporation" of the second liquid fraction through a third Joule-Thomson valve to produce a liquid natural gas product and a third vapor fraction.
The method according to claim 4, characterized in that the gas from the vapors projecting from the upper part of the separation means has a temperature of about -128.88 to -73.33 degrees centigrade (about -200 to 100 degrees F).
8. The method for liquefying a stream of natural gas in accordance with claim 6, characterized in that at least a portion of at least one of the first vapor fraction, the second vapor fraction and the third vapor fraction is directed to the heat exchanger to be used as an auxiliary cooling medium to provide cooling to the current of natural gas.
The method according to claim 8, characterized the compressed waste gas of the cryogenic plant has a pressure of about 7.03 to 84.36 kg / cm2 (about 100 to 1200 psig) and a temperature of about 17.18 to 204.44 degrees centigrade (about 0 to 400 degrees F); wherein the condensed natural gas stream has a pressure of approximately 7.03 to 49.21 kg / cm2 (approximately 100 to 700 psig) and a temperature of approximately -130.55 to -73.33 degrees centigrade (approximately 203 to -100 degrees F); and wherein the liquid natural gas product has a pressure of about 0.07 to 7.03 kg / cm2 (about 0 to 100 psig) and a temperature of about -161.66 to -128.88 degrees centigrade (about -259 to -200 degrees F) .
The method according to claim 8, characterized in that the compressed residual gas of the cryogenic plant has a pressure of approximately 21.09 to 63.27 kg / cm2 (approximately 300 to 900 psig) and a temperature of approximately -6.66 to 93.33 degrees. centigrade (approximately 20 to 200 degrees F); wherein the condensed natural gas stream has a pressure of about 21.09 to 49.21 kg / cm2 (about 300 to 700 psig) and a temperature of about -106.11 to -73.33 degrees centigrade (about -159 to -100 degrees F); and wherein the liquid natural gas product has a pressure of about 0.07 to 7.03 kg / cm2 (about 0 to 100 psig) and a temperature of about -106.
11 to -77.33 degrees centigrade (approximately -159 to -100 degrees F); and wherein the liquid natural gas product has a pressure of about 0.07 to 7.03 kg / cm2 (about 0.0 to 100 psig) and a temperature of about -161-66 to -128.88 degrees centigrade (-259 to -200 degrees F) ). The method according to claim 8, characterized in that the gas from the vapors projecting from the upper part of the separation means has a temperature of about -128.88 to -73.33 degrees centigrade (about -200 to -100 degrees F).
12. A process for producing liquid natural gas characterized in that it comprises the steps of: a. cooling a natural gas feed with a cooling medium to obtain a liquid / cold gas mixture; b. separating the liquid / cold gas mixture in a separation medium, to obtain a gas fraction comprising mainly methane and a liquid fraction comprising mainly ethane and heavier hydrocarbons; c. compress the gas fraction to obtain a fraction of compressed gas; and c. cooling at least a portion of the fraction of compressed gas by means of heat exchange with at least a portion of the fraction of gas taken from the separation medium, to obtain a liquefied natural gas fraction.
13. The process in accordance with the claim 12, further characterized in that it comprises the step of: e. expand the liquefied natural gas fraction to reduce the temperature and pressure of the liquefied natural gas fraction.
14. The process in accordance with the claim 13, characterized in that the separation means comprises a demethanizer and in which the fraction of gas taken from the separating medium comprises gases from the vapors projecting from the top of the demethanizer.
15. The process according to claim 13, characterized in that the separating means comprises an expander outlet separator and a demethanizer and wherein the fraction of gas taken from the separation means comprises gases from the vapors projecting from the upper part of the separator. Demetanizer and expander outlet separator.
16. The process according to claim 13, characterized in that the separating means comprises an expander outlet separator and a demethanizer and in which the gas fraction taken from the separation means comprises gases from the vapors projecting from the upper part of the separator. Demetanizer.
17. A process for producing liquid natural gas characterized in that it comprises the steps of: a. cooling a natural gas feed with a cooling medium to obtain a liquid / cold gas mixture; b. separating the liquid / cold gas mixture in a separation medium, to obtain a gas fraction comprising mainly methane and a liquid fraction comprising mainly ethane and heavier hydrocarbons and a small amount of methane; c. recover the methane from the liquid fraction with the fractionation medium; d. combine the fraction of gas and methane recovered from the liquid fraction to form a residual gas; and. compress the waste gas to obtain a fraction of compressed gas; F. cooling at least a part of the fraction of compressed gas by means of heat exchange with at least a portion of the waste gas to obtain a liquefied natural gas fraction; g. expand the liquefied natural gas fraction to reduce the temperature and pressure of the liquefied natural gas fraction to produce a liquid natural gas product.
18. The process according to claim 17, characterized in that the fractionating means comprises a demethanizer.
19. The process according to claim 18, characterized in that the separation means is a liquid / gas separator.
20. The method of compliance with the claim 17, characterized in that the fraction of compressed gas has a pressure of about 7.03 to 84.36 kg / cm2 (about 100 to 1200 psig) and a temperature of about 17.78 to 204.44 degrees centigrade (about 0 to 400 degrees F); wherein the waste gas has a pressure of about 7.03 to 42.18 kg / cm2 (about 100 to 600 psig) and a temperature of about -128.88 to -73.33 degrees centigrade (about -200 to -100 degrees F); in the liquefied natural gas fraction it has a pressure of approximately 7.03 to 49.21 kg / cm3 (approximately 100 to 700 psig) and a temperature of approximately -130.55 to -73.33 degrees centigrade (approximately -203 to -100 degrees F); and wherein the liquid natural gas product has a pressure of about 0.07 to 7.03 kg / cm2 (about 0 to 100 psig) and a temperature of about -161.66 to -128.88 degrees centigrade (-259 to -200). The method according to claim 17, characterized in that the fraction of compressed gas has a pressure of approximately 21.09 to 63.27 kg / cm2 (approximately 300 to 900 psig) and a temperature of approximately -6.66 to 128.88 degrees centigrade (approximately 20 at 200 degrees F); wherein the waste gas has a pressure of about 7.03 to 42.18 kg / cm2 (about 100 to 600 psig) and a temperature of about -128.80 to -73.33 degrees centigrade (about -120 to -100 degrees F); in the liquefied natural gas fraction it has a pressure of approximately 21.09 to 49.
21 kg / cm2 (approximately 300 to 700 psig) and a temperature of approximately -106.11 a -73.33 degrees Celsius (approximately -159 to -100 degrees F); and wherein the liquid natural gas product has a pressure of about 0.07 to 7.03 kg / cm2 (approximately 0 to 100 psig) and a temperature of approximately -161.66 to -128.88 degrees centigrade (approximately -259 to -200 degrees F).
22. A process for producing liquid natural gas characterized in that it comprises the steps of: a. cooling a natural gas feed with a cooling medium to obtain a cooled liquid / gas stream; b. separating the cooled liquid / gas stream into a gaseous fraction and a liquid fraction in an expanding inlet separator; c. perform a first expansion of the gaseous fraction to obtain an expanded gas fraction; d. introducing the expanded gas fraction to a demethanizer; and. introduce the liquid fraction to the demethanizer; F. dividing the vapors gases from the top of the demethanizer into a retrograde stream and a main stream; g. directing the retrograde current through a waste gas condenser as a cooling medium; h. recombining the retrograde current and the main stream to form a waste gas stream; i. compress the waste gas stream to obtain a compressed waste gas stream; j. cooling the compressed waste gas stream to obtain the compressed, cooled stream; k. further cooling at least a part of the compressed waste gas stream, cooled in the waste gas condenser to obtain a condensed waste gas stream; 1. perform a second expansion of the condensed waste gas stream to obtain a liquid natural gas product and a vapor fraction of evaporation.
23. The process according to claim 22, characterized in that at least a portion of the evaporation vapor fraction is sent to the waste gas condenser as a refrigerant;
24. The process according to claim 22, characterized in that the gas distribution of the vapors leaving the top of the demethanizer between the retrograde stream and the main stream is regulated by a valve; and wherein the valve opening is controlled, such that the gas flow of the retrograde stream in the waste condenser is sufficient to keep the waste gas stream condensed at a constant temperature.
25. The process according to claim 22, characterized in that the gas distribution of the upper vapors leaving the demethanizer between the retrograde stream and the main stream is regulated by a valve; and wherein the valve opening is controlled, such that the gas flow of the retrograde stream in the waste gas condenser is sufficient to maintain the condensed waste gas stream at the bubble point of the gas stream residual.
26. The process according to claim 22, characterized in that the gas distribution of the vapors leaving the top of the demethanizer between the retrograde stream and the main stream is regulated by a valve; and wherein the valve opening is controlled in such a manner that the flow of retrograde gas in the waste gas condenser is sufficient to maintain the condensed waste gas stream at a temperature below the bubble point of the current of residual gas.
27. The process according to claim 22, characterized in that the first expansion comprises the isentropic expansion in a turboexpander and the second expansion comprises the isenthalpan expansion through at least one Joule Thomson valve.
28. The process according to claim 22, characterized in that the first expansion comprises the isenthalpic expansion through at least one Joule-Thomson valve and the second expansion comprises the isenthalpic expansion through at least one Joule-Thomson valve.
29. The process according to claim 22, characterized in that the first expansion comprises the isenthal expansion through at least one Joule-Thomson valve and the second expansion comprises the isentropic expansion in a turboexpander.
30. The process according to claim 22, characterized in that the first expansion comprises the isentropic expansion in a turboexpander and the second expansion comprises the isentropic expansion in a turbo expander.
The process according to claim 22, characterized in that the compressed, cooled waste gas is at a pressure of approximately 7.03 to 47.80 kg / cm2 (approximately 100 to 680 psig) and at a temperature of 17.18 to 204.44 degrees centigrade (approximately 0 at 400 degrees Fahrenheit); and wherein the condensed waste gas stream is at a temperature of about 130.55 to -73.35 degrees centigrade (about -203 to -100 degrees Fahrenheit and a pressure of about 7.03 to 49.21 kg / cm2 (about 100 to 700 psig).
32. The process according to claim 22, characterized in that the compressed, cooled waste gas is at a pressure of about 21.09 to 63.27 kg / cm2 (about 300 to 900 psig) and at a temperature of about -6.66 to 93.33 degrees centigrade ( approximately 20 to 200 degrees Fahrenheit), and in which the condensed waste gas stream is at a temperature of approximately -106.11 to -73.33 degrees Celsius and at a pressure of approximately 21.09 to 49.21 kg / cm2. Claim 22, characterized in that the retrograde current has a temperature of about -128.88 to -73.
33 degrees centigrade (about -200 to -100 gr. ados Fahrenheit).
34. The process according to claim 22, characterized in that the first expansion comprises the isentropic expansion in a turbo expander and in which the second expansion comprises the following steps: i. a first isenthalpic expansion of the condensate gas stream condensed through a first Joule-Thomson valve in a first vaporization chamber, thereby forming a first liquid fraction and a first gas fraction; ii. a second isthcalpic expansion of the first liquid fraction through a second Joule-Thomson valve in a second evaporation chamber, thereby forming a second liquid fraction and a second gas fraction; and iii. a third isenthalpic expansion of the second liquid fraction through a third valve Joule-Thomson in a liquid natural gas storage tank, thereby forming a liquid natural gas product and a third gas fraction.
35. The process in accordance with the claim 31, characterized in that the retrograde stream has a temperature of about -128.88 to -73.33 degrees centigrade (about -200 to -100 degrees F).
36. The process in accordance with the claim 32, characterized in that the retrograde current has a temperature of about -128.88 to -73.33 degrees centigrade (about -200 to -100 degrees F).
37. The process according to claim 34, characterized in that the process is carried out at least in part in a cryogenic plant, in which the first liquid fraction has a pressure which is the same as the pressure fuel line high of the cryogenic plant and in which the second liquid fraction has a pressure, which is the same as the low pressure fuel line of the cryogenic plant.
38. A process for producing liquid natural gas, characterized in that it comprises the steps of: a. cooling the natural gas feed with a cooling medium to obtain a cooled liquid / gas stream; b. separating the cooled liquid / gas stream into a gaseous fraction and a liquid fraction in an expanding inlet separator; c. perform a first expansion of the gaseous fraction to obtain an expanded gas fraction; d. introducing the expanded gas fraction to a demethanizer; and. introduce the liquid fraction to the demethanizer; F. fractionating the expanded gas fraction and the liquid fraction in the demethanizer to obtain a stream of vapors leaving the upper part which mainly comprise methane in gaseous form and the stream of the bottoms comprising liquid ethane and heavier hydrocarbons; g. dividing the stream of vapors from the upper part into a retrograde stream and a main stream; h. directing the retrograde current through a waste gas condenser as a cooling medium; i. recirculating the retrograde current and the main stream to form a waste gas stream; j. compress the waste gas stream to obtain a compressed waste gas stream; k. cooling the compressed waste gas stream to obtain a stream of compressed, cooled gas; 1. cooling at least part of the compressed waste gas stream in the waste gas condenser to obtain a gas stream of condensed waste; m. perform a second expansion of the condensed residue gas stream to obtain a liquid natural gas product and a vaporization vapor fraction.
39. The process in accordance with the claim 38, characterized in that the vapor stream from the upper part has a temperature of approximately -128.88 to -73.33 degrees centigrade (approximately -200 to -100 degrees F), and a pressure of approximately 7.03 to 42.18 kg / cm2 (approximately 100 a 600 psig), in which the compressed residual gas has a temperature of 17.78 to 204.44 degrees centigrade (about -17 to -400 degrees F) and a pressure of about 70.3 to 42.18 kg / cm2 (about 100 to 1200 psig); and wherein the compressed waste gas has a temperature of 17 -.78 to 204.44 degrees centigrade and a pressure of 7.03 to 84.36 kg / cm2 and in which the liquid natural gas product has a temperature of -161.66 to -128.88 degrees. centigrade (-259 to -200 degrees F), and a pressure of 0.07 to 7.03 kg / cm2 (0 to 100 psig).
40. The process according to claim 38, characterized in that the current of the vapors leaving the upper part has a temperature of -128.88 to -73.33 degrees centigrade and a pressure of 7.03 to 42.18 kg / cm2; wherein the compressed waste gas has a temperature of -6.66 to 93.33 degrees centigrade and a pressure of 21.09 to 63.27 kg / cm2; and wherein the liquid natural gas product has a temperature of -161.66 to -128.88 degrees centigrade and a pressure of about 0.07 to about 7.03 kg / cm2.
41. The process according to claim 38, characterized in that the stream of cooled compressed gas is subcooled to produce a condensed waste gas stream which has been cooled below its bubble point.
42. The process according to claim 38, characterized in that the second expansion comprises the following steps: i. a first isthcalpic expansion comprising the expansion of the residual gas stream condensed through a first Joule-Thomson valve in a first vaporization chamber, thereby forming a first liquid fraction and a first gas fraction, ii. a second isthcalpic expansion of the first liquid fraction through a second Joule-Thomson valve in a second evaporation chamber, thereby forming a second liquid fraction and a second gas fraction; and iii. a third isenthalpic expansion of the second liquid fraction through a third valve Joule-Thomson in a liquid natural gas storage tank, thereby forming a liquid natural gas product and a third gas fraction.
43. The process according to claim 42, characterized in that at least a portion of at least one of the first gas fraction, the second gas fraction and the third gas fraction is returned to the waste gas condenser to serve as a gas. auxiliary cooling medium.
44. The process according to claim 42, characterized in that at least a portion of at least one of the first liquid fraction, the second liquid fraction and the liquid natural gas product are returned to the waste gas condenser to serve as an auxiliary cooling medium.
45. An apparatus for liquefying a stream of natural gas, characterized in that it comprises: a. a heat exchanger; wherein the natural gas stream comprises compressed waste gas from a cryogenic plant; wherein the cryogenic plant uses a means of separation; wherein the cooling is provided in the heat exchanger by a retrograde gas stream taken from the vapors projecting from the upper part of the separating means; and wherein the cooling provided by the heat exchanger is sufficient to condense the natural gas stream to produce a stream of liquid natural gas.
46. The apparatus in accordance with the claim 45, further characterized by comprising: b. a means of expansion; wherein the pressure and temperature of the liquid natural gas stream are reduced to a suitable level for storage and transport by expansion of the condensed natural gas stream in the expansion medium.
47. The apparatus in accordance with the claim 46, characterized in that the expansion means comprises at least one Joule-Thomson valve.
48. The apparatus according to claim 46, characterized in that the expansion means comprises a turboexpander.
49. The apparatus according to claim 46, characterized in that the expansion means comprises: i. a first Joule-Thomson valve; ii. a first evaporation chamber; iii. a second Joule-Thomson valve; iv. a second evaporation chamber; v. a third Joule-Thomson valve; and I saw . a liquid natural gas storage tank; wherein the stream of compressed natural gas is expanded in the first evaporation chamber through the first Joule-Thomson valve to produce a first liquid fraction and a first gas fraction; wherein the first liquid fraction is expanded in the second evaporation chamber through the second Joule-Thomson valve to produce a second liquid fraction and a second gas fraction; and wherein the second liquid fraction is expanded to a liquid natural gas storage tank, the third Joule-Thomson valve to produce a liquid natural gas product and a third gas fraction.
50. The apparatus according to claim 49, characterized in that the heat exchanger has multiple flow channels to accommodate the natural gas stream, the retrograde gas gas stream taken from the vapors projecting from the upper part of the separation medium. and at least one stream of supplemental cooling medium.
51. An apparatus for producing liquid natural gas, characterized in that it comprises: a. a cooling medium; b. a means of separation; c. a compression medium; d. a heat exchanger; and e. a means of expansion; wherein the natural gas feed is cooled in the cooling medium to produce a cooled liquid / gas mixture; wherein the cooled liquid / gas mixture is separated in the separation medium in a gas fraction comprising mainly methane and a liquid fraction comprising mainly ethane and heavier hydrocarbons; wherein at least a portion of the gas fraction is sent through the heat exchanger, where it serves as a cooling medium and subsequently through the compression medium, where it is compressed to form a fraction of compressed gas; wherein the fraction of compressed gas is cooled in the heat exchanger, such that it is condensed to a liquid; and wherein the liquid is expanded in the expansion medium, thereby reducing the temperature and pressure of the liquid, to form a liquid natural gas product.
52. The apparatus according to claim 51, characterized in that the expansion means comprises at least one Joule-Thomson valve.
53. The apparatus according to claim 51, characterized in that the expansion means comprises a turboexpander.
54. The apparatus in accordance with the claim 51, characterized in that the expansion means comprises: i. a first Joule-Thomson valve; ii. a first evaporation chamber; iii. a second Joule-Thomson valve; iv. a second evaporation chamber; v. a third Joule-Thomson valve; and I saw. a liquid natural gas storage tank; wherein the stream of compressed natural gas is expanded in the first evaporation chamber through the first Joule-Thomson valve to produce a first liquid fraction and a first gas fraction; wherein the first liquid fraction is expanded in the second evaporation chamber through the second Joule-Thomson valve to produce a second liquid fraction and a second gas fraction; and wherein the second liquid fraction is expanded to a liquid natural gas storage tank through the third Joule-Thomson valve to produce a liquid natural gas product and a third gas fraction.
55. An apparatus for producing liquid natural gas characterized in that it comprises: a. a cooling medium; b. a liquid / gas separator; c. a first means of expansion; d. a demetanizer; and. a compression medium; g. a residual gas condenser; and h. a second means of expansion; wherein the natural gas feed is cooled in the cooling medium to produce a cooled liquid / gas mixture; wherein the cooled liquid / gas mixture is separated in the liquid / gas separator in a first gas fraction and a first liquid fraction; wherein the gas fraction is expanded in the first expansion medium to form a second liquid / gas mixture; wherein the first liquid fraction and the liquid / gas mixture are introduced to the demethanizer, in which they are fractionated to obtain a gas from the vapors leaving the upper part which mainly comprise methane and a stream from the bottoms comprising mainly ethane liquid and heavier hydrocarbons; wherein at least a portion of the gas from the vapors projecting from the upper part is sent through the heat exchanger, where it serves as a cooling medium and subsequently through the compression medium, where it is compressed to form a fraction of compressed gas; wherein the fraction of compressed gas is cooled in the heat exchanger, such that it is condensed to a liquid; and wherein the liquid is expanded in the expansion medium, thereby reducing the temperature and pressure of the liquid, to form a liquid natural gas product.
56. The apparatus according to claim 55, characterized in that the medium of expansion comprises at least one Joule-Thomson valve.
57. The apparatus in accordance with the claim 55, characterized in that the expansion means comprises a turboexpander.
58. The apparatus according to claim 55, characterized in that the expansion means comprises: i. a first Joule-Thomson valve; ii. a first evaporation chamber; iii. a second Joule-Thomson valve; iv. a second evaporation chamber; v. a third Joule-Thomson valve; and I saw . a liquid natural gas storage tank; wherein the stream of compressed natural gas is expanded in the first evaporation chamber through the first Joule-Thomson valve to produce a first liquid fraction and a first gas fraction; wherein the first liquid fraction is expanded in the second evaporation chamber through the second Joule-Thomson valve to produce a second liquid fraction and a second gas fraction; and wherein the second liquid fraction is expanded to a liquid natural gas storage tank through the third Joule-Thomson valve to produce a liquid natural gas product and a third gas fraction.
59. The apparatus according to claim 55, characterized in that the heat exchanger has multiple flow channels to accommodate the natural gas stream, the gas retrograde gas stream taken from the vapors projecting from the upper part of the separation medium. and at least one stream of supplemental cooling medium.