EA010743B1 - Plant (embodiments) and method of lng regasification - Google Patents

Abstract

LNG composition of LNG from a storage tank or other source is modified in a process in which the LNG is pumped to a first pressure and split into two portions. One portion of the pressurized LNG is then reduced in pressure and heavier components are separated from the reduced pressure LNG to thereby form a lean LNG. The lean LNG is then pumped to a higher pressure and combined with the other portion to form a leaner LNG. Preferably, separation is performed using a demethanizer, wherein part of the demethanizer overhead product is condensed to form the lean LNG, while another portion is used for column reflux. In further preferred configurations, ethane recovery is variable and in yet other configurations, propane or ethane can be delivered via a batching pipeline.

Description

The invention relates to the processing of gas, in particular, it relates to the regasification of liquefied natural gas to control the calorific value and the extraction or selection of components C2 and C3 + for sale.

As the demand for natural gas in the United States has risen sharply in recent years, the market price of natural gas has become more and more energy dependent. Consequently, there is renewed interest in the import of liquefied natural gas (LNG) as an alternative source of natural gas. However, most of the imported LNG has a higher calorific value and is richer in heavy hydrocarbons than allowed by typical pipeline specifications for natural gas in North America. For example, at a time when some countries generally allow for the use of richer and more heat-generating LNG, the demands of the North American market are driven by environmental and environmental concerns and may additionally depend on the specific use of LNG.

One of the problems with LNG imports is that a substantial part of the global LNG supply is made up of rich LNG with inadequate calorific value. As the LNG import market grows, local LNG trading is becoming increasingly common, similar to the modern crude oil trading market. With the growth of LNG trade between various LNG producers and regasification sites in North America, LNG terminals must be configured to accept LNG with different compositions and calorific values so that it remains regulated and cost competitive. In some markets, rich LNG can be made effective, since the ethane content in it can be used as feedstock for a petrochemical plant, the propane content can be sold as LPG, and liquid butane plus can be used for blending with gasoline. Additionally, processing steps for selecting heavier components from rich LNG are needed to meet the stringent calorific value specifications for pipelines in North America.

In most LNG liquefaction plants located at the beginning of the stream, the removal of pentane, hexane and heavier hydrocarbons is required only to prevent the formation of paraffins in the heat exchanger for cryogenic liquefaction. The components of the LPG (C2, C3 and C4 +) are typically not removed and liquefied with the methane component, resulting in LNG with a fairly high total calorific value. The approximate calorific values of LNG from a number of installations for exporting LNG in the Atlantic, Pacific Ocean and LNG installations in the Middle East are shown in FIG. 8. Higher calorific values indicate a higher proportion of non-methane components. Compositions of ethane, propane and butane, and heavier components for these LNG are shown in FIG. 9.

In North America, many pipeline operators require very poor gas to be transported, and in some regions of the Midwest, the total calorific value of natural gas is between 35769.6 and 39123 kJ / m ³ (960 and 1050 BTU / normal cubic feet). In California, the acceptable total calorific value is between 36,142.2 and 42,849 kJ / m ³ (970 and 1150 BTU / normal cubic feet). California also imposes restrictions on specific gas components for consumption of compressed natural gas. Currently, an acceptable LNG that meets California specifications is limited to sources such as Kenai, Alaska LNG or Atlantic LNG from Trinidad. Therefore, in order to comply with the North American technical specifications for natural gas, the terminals for regasification must have equipment that is capable of handling non-compliant LNG. Most commonly, the calorific value of LNG and the Wobbe index are controlled by diluting with nitrogen or mixing with leaner natural gas. However, there are limits to the maximum amount of nitrogen and inert substances that can be introduced into the pipeline gas. In addition, dilution with nitrogen often requires an air separation unit to produce nitrogen, which is expensive and has no other equipment advantage, and the poor gas source is often not available for mixing in relatively large LNG regasification equipment.

As environmental regulations have become more stringent, more stringent controls on LNG compositions than in current technical conditions are expected in North American markets, requiring new processes that can economically remove C2 + components from LNG. In addition, such processes should provide the facility with sufficient flexibility to process a wide range of LNG, enabling importers to buy LNG in various low-cost markets, rather than being limited to sources that are in line with North American specifications.

Traditional regasification processes for rich LNG, such as LNG from Indonesia, typically range from 44,712 to 48,438 kJ / m ³ (1,200 to 1,300 BTU / normal cubic feet), which include heating LNG in fuel fired heaters or in seawater preheaters and then diluting evaporated LNG with nitrogen or lean gas to meet the heating conditions. However, both the heating process is undesirable, since fuel gas heaters produce emissions and pollutants of CO ₂ , and seawater heaters require expensive seawater installations and also have a negative impact on the ocean environment. In addition, dilution with nitrogen to control the calorific value

- 1,010,743 natural gas is usually uneconomical, since it generally requires a nitrogen source (for example, an air separation unit), which is relatively expensive to operate. While dilution methods can produce “cost-effective” calorific values, the effects on LNG compositions are relatively small, and the final composition (especially as regards C2 and C3 + components) may still be unacceptable for North American environmental standards. or other environmentally sensitive markets. Consequently, the LNG light ends distillation process or another gas fractionation stage should be used, which generally require evaporation of the LNG in the evaporation drum and distillation of the light fractions in the demethanizer operating at low pressures, with the flash evaporation steam and / or the upper pursuit of the demethanizer shrinking to more high pressure and re-condense in the form of a liquid using the incoming LNG as a coolant, and then is injected and evaporated in the evaporators. These processes are energy inefficient when high extracts of propane and ethane are required to process richer LNG (LNG with high ethane and propane and heavier hydrocarbons) to control compliance, because these processes would require the evaporation drum and demethanizer to work even lower. pressure, which would significantly increase the cost of compression. An exemplary regasification process and configuration is described in US Pat. No. 6,556,579 to MeSayieu.

In addition to removing the C2 + components to match the calorific value of the gas being sold, there are also opportunities to generate revenue through the production of C2 and C3 for sale, since the value of these components in IGU is generally higher than that in natural gas, especially when ethane can be used as a feedstock for petrochemicals, and propane and heavier components can be sold as transported fuel. Unfortunately, the markets for consumers of these liquid products are usually located at a considerable distance from the LNG regasification terminals and specialized pipeline transport systems must be installed. Additionally, the C2 or C3 market is often subject to seasonal fluctuations. Therefore, there is a need to provide flexibility that allows equipment to operate either to extract ethane, or to remove ethane (to extract only propane), or it allows a varying level of extraction of ethane. Unfortunately, the most up-to-date FGS plants refuse to apply to these modes of operation, subsequently losing the potential benefits of income when working from ethane extraction to ethane removal or vice versa.

Consequently, while numerous processes and installations for the regasification of LNG are known in the art, all or almost all of them have one or more disadvantages. Most notably, many of the currently known processes are energy-inefficient and inflexible when meeting the requirements for calorific values and compositions. Thus, there is still a need to provide improved equipment and gas treatment methods for LNG regasification.

The present invention relates to installations and methods for treating LNG, in which the pressure of one part of LNG is defined as the treatment pressure at which LNG treatment takes place, in order to thereby produce a treated (typically poor) LNG. The treated LNG thus formed can then be further compressed to supply pressure and combined with the second part (typically untreated) LNG at supply pressure, so as to produce LNG with the desired and specified chemical composition and calorific value. Preferably, the processing of LNG is carried out in an irrigation demethanizer, which allows the removal and / or extraction of at least 99% propane and more than 70% ethane from LNG.

In one aspect of the invention, the LNG processing facility comprises an LNG source that provides the first part of the LNG and the second part of the LNG. The processing unit is in fluid communication with the LNG source and receives the first part, the unit removing the heavier components from the first part to thereby produce lean LNG. The combining unit then combines the poor LNG and the second part of the LNG to form the treated LNG.

Preferably, the contemplated LNG treatment installations comprise a pump that pumps at least one of the first and second parts up to the feed pressure, and additionally includes a demethanizer that takes at least a fraction of the second part at a pressure lower than the feed pressure. Most preferably, the demethanizer produces an overhead product, wherein the heat exchanger cools at least a fraction of the overhead vapor of the demethanizer to thereby produce an irrigation flow for the demethanizer, and / or the heat exchanger condenses at least a portion of the overhead vapor from the irrigation fraction collection demethanizer to thereby produce poor LNG.

In further preferred aspects, the considered LNG processing facilities are configured to combine the first portion and the lean LNG to thereby form the treated LNG, and the treated LNG is then injected and evaporated at a pressure in the pipeline in a manner well known in the art. In addition, the plants in question may also include a control loop, which is configured to

- 2 010743 to denote the mass expenditure ratio between the first and second part. When using such control circuits, it is necessary to estimate that the calorific value of the combined processed and untreated LNG can be maintained at a given level, while the LNG entering the plant may have variable chemical compositions and / or calorific values. Where desirable, the installation may additionally include a turbo-generator, which is driven by expanding the heated and compressed portion of the first part of the LNG to thereby produce energy.

In another aspect of the invention, the LNG processing unit has a heat exchanger that is configured such that at least the proportion of LNG cold content passing through the heat exchanger provides cooling for the demethanizer reflux flow and then provides cooling to condense the demethanizer reflux collector overhead, and in which the irrigation flow and the overhead product of the demethanizer irrigation fraction are produced from LNG passing through the heat exchanger. Particularly preferred installations also include a demethanizer that is connected to a heat exchanger, so that at least the fraction of LNG passing through the heat exchanger is fed to the demethanizer to thereby form at least one of the demethanizer reflux stream and the condensed overhead product of the reflux collection demethanizer. Most typically, LNG passing through a heat exchanger has a pressure of between 2068 and 4136 kPa (300 and 600 pounds per square inch man). A heat pump can be connected to the heat exchanger, which injects the condensed product of the demethanizer irrigation fraction collector up to delivery pressure, and a combining unit can be included in which the condensed product of the demethanizer irrigation fraction collector is combined with LNG.

Therefore, a method for processing LNG has been proposed, in which at one stage LNG is provided and injected to feed pressure. At a further stage, the LNG is split at the feed pressure to the first and second parts. At the next stage, the pressure of the first part is reduced to the separation pressure, and the heavier components are separated from the first part at the separation pressure in order to thereby form a poor LNG. At another stage, the poor LNG is pressurized to supply pressure, and the poor LNG and the second part of the LNG are combined to form treated LNG.

The preferred feed pressure is between about 4826 and 8963 kPa (700 and 1300 pounds per square inch man.), While the separation pressure is preferably between about 2068 and 4482 kPa (300 and 650 pounds per square inch man.) and the supply pressure is preferably between about 4826 and 8963 kPa (700 and 1300 psi). The separation of heavier components from the first part is typically carried out in a demethanizer, which produces a demethanizer overhead product, in which most preferably at least part of the demethanizer overhead product condenses to thereby form a poor LNG, and possibly another part of the demethanizer overhead product cools to form an irrigation stream for the demethanizer.

In particularly preferred installations where ethane recovery or ethane removal, or varying levels of ethane recovery are desirable, residues from the bottom of the demethanizer can be further processed in the deethanizer column to produce overhead liquid C2 and residual product C3 +. In this case, the heat consumption for the formation of irrigation from the overhead of the de-ethanizer can be provided by the cold content of the incoming LNG. The removal of ethane or the varying level of extraction of ethane can be effectively achieved by rejecting at least part of the product of liquid ethane from the deethanizer overhead for mixing with the poor LNG. This configuration allows the flexibility to switch between the method of ethane extraction and ethane removal or vice versa, without changing the process conditions at the beginning of the stream.

The various objectives, features, aspects and advantages of the present invention will become more apparent from the following detailed description of preferred embodiments of the invention, along with the accompanying drawings, in which:

FIG. 1 is a schematic view of a first exemplary installation in accordance with the subject matter of the invention with removal or removal of 99% of the propane from the incoming LNG;

FIG. 2 is a schematic view of a second exemplary installation in accordance with the subject matter of the invention with the removal or removal of more than 70% ethane and 99% propane from the incoming LNG;

FIG. 3 is a schematic view of a third exemplary installation in accordance with the subject matter of the invention, with removal or removal of 99% of the propane from the incoming LNG using an integrated heat exchanger to condense the irrigation;

FIG. 4 is a schematic view of a fourth exemplary installation in accordance with the subject matter of the invention for the installation in which C2 and C3 are extracted, at the same time energy is produced;

FIG. 5 is a schematic view of the fifth exemplary installation in accordance with the subject matter of the invention for the installation in which C3 is extracted, at the same time energy is produced;

FIG. 6 is a schematic view of the sixth exemplary installation in accordance with

- 3 010743 of the invention with the removal or extraction of 99% propane and the extraction of 2 to 70% ethane from the incoming LNG, demonstrating a method of switching between ethane extraction and ethane removal or changing levels of ethane extraction;

FIG. 7 is a schematic view of a seventh exemplary installation in accordance with the subject matter of the invention for the supply of propane or ethane using a PGK metering pipeline;

FIG. 8 is a graph depicting calorific values of LNG from various installations for exporting LNG to the markets of the Atlantic, Pacific Oceans and the Middle East;

FIG. 9 is a diagram showing the chemical composition of the LNG LNG of FIG. eight.

It has been found that LNG can be processed in a manner that takes advantage of the relatively large cold content of LNG. More specifically, it was found that the LNG stream can be injected to the desired pressure and then used to supply the demethanizer with cooling irrigation and heat consumption to condense the steam from the demethanizer reflux fraction to thereby produce a poor LNG that can then be combined with the untreated LNG.

It may also be possible for the cold content of LNG to be supplied with cooling irrigation to the de-ethanizer. Most preferably, the injected LNG stream is processed in a demethanizer (and possibly in a de-ethanizer) to thereby form streams that are cooled by the injected LNG. Such plants allow the removal or extraction of at least 99% propane and more than 70% ethane from LNG. When ethane removal or varying levels of ethane recovery are desired, residues from the bottom of the demethanizer can be further processed in the deethanizer column to produce C2 overhead fluid and C3 + residual product in which ethane removal or changing ethane recovery can be effectively achieved by deflecting at a lower level. as part of a liquid ethane product from a de-ethanizer overhead to mix with poor LNG.

In one preferred aspect of the subject matter, as shown in FIG. 1, LNG is injected and divided into two parts (streams 2 and 3), as is necessary to control the calorific value. The first part undergoes heat exchange with a demethanizer overhead, producing cold irrigation and a condensed product of a demethanizer overhead (poor LNG), while the second part (rich in LNG) bypasses the calorific value control. Rich LNG and poor LNG streams can then be combined to produce an LNG product with the desired chemical composition and calorific value.

More specifically, and with further reference to FIG. 1, LNG consumption at the plant is equivalent to 500 million normal cubic feet per day of natural gas with a typical gas composition shown in the table below. LNG stream 1 from a storage or condenser to re-liquefy steam (or another suitable source) is at a pressure of from about 103.35 to 551.2 kPa (15 to 80 pounds per square inch abs.) And a temperature typically from about -162 , 2 to -151.1 ° С (from -260 to -240 ° Р). Flow 1 is pumped by the 51 LNG pump to a suitable pressure, typically from about 4826 to about 8963 kPa (from about 700 to about 1300 psig) and most typically about 6890 kPa (1000 psig) for formation of a stream of compressed LNG, which is divided into stream 2 and stream 3, as is necessary to control the calorific value. Higher flow rate 3 will allow more LNG flow into the calorific value control unit, thus lowering the calorific value of the pipeline gas 16. Where high propane recoveries are desired (for example, due to market requirements), most of the LNG flow 1 will be processed in the calorific value control unit. Thus, it must be recognized that by changing the cost relationship between streams 2 and 3, the number of C2 + components in the pipeline gas can be controlled to meet specific market requirements.

The pressure of stream 3 is reduced in valve 53 to form stream 4 at about 3101.5 to 3446.7 kPa (450 to 500 psi), which is heated and partially evaporated in heat exchanger 54 through heat exchange with overhead stream 8 demethanizer and steam flow 10 from the irrigation separator. The stream 5 leaving the heat exchanger is at about -84.4 to 95.5 ° C (-120 to -140 ° P) and then heated in the preheater 55 using a heat transfer medium (for example, glycol (stream 91)), forming stream 6 at about -84.4 to -81.7 ° C (-120 to -115 ° P). The biphasic stream 6 is then fed to the upper section of the demethanizer 56. The demethanizer produces poor natural overhead steam 8, in which propane and heavier components are reduced (or even depleted) and the ethane is at least partially depleted.

The demethanizer 56 preferably operates at from 3,101.5 to 3,446.7 kPa (450 to 500 psi). It should be noted that the reboiler 57 side fractions can be used to help distill light components in stream 17 discharged from the lower section of the demethanizer with heat supply from glycol stream 92. The composition of the residue at the bottom of the demethanizer is controlled by the temperature of stream 7 at from about 37.8 ° C (100 ° P), ethane recovery to 93.3 ° C (200 ° P), extraction

- 4 010743 propane only, using reboiler 58 residues from the bottom. Thus, it is necessary to specifically assess that in most aspects of the configurations under consideration, the target temperature of residues from the bottom of the demethanizer will control extraction levels and ensure control of the calorific value of the incoming LNG. The residual pressure of the product 7 can then be reduced using valve 63, and it is produced as LPG stream 20.

The upper cut is 8 demethanizer, which is usually at a pressure of from about 3101.5 to 3446.7 kPa (from 450 to 500 psig) and at a temperature from about -67.8 to -28.9 ° С (from -90 to -20 ° P), is cooled and partially condensed in the heat exchanger 54 at a temperature of from about -78.9 to -95.6 ° C (from -110 to -140 ° P). The two-phase flow 9 thus produced is then separated in the separator 59 into a fluid flow 11 and a poor steam flow 10. A fluid stream 11 containing residual components propane and / or ethane is injected through the irrigation pump 60 and returns to the top of the demethanizer, like cold irrigation stream 12. The steam stream 10 from the separator is returned to the heat exchanger 54 and then cooled and condensed, forming stream 13.

It should be specifically noted that the upper shoulder heat exchanger 54 provides two functions, supplying the demethanizer with irrigation, which is essential to achieve high recovery of propane and ethane and to condense the steam from the separator into the liquid, which makes it possible to inject fluid, thus significantly reducing capital costs and operating costs. costs. Flow 13 of a poor liquid, usually at a temperature of from about -90 to -95.6 ° C (from -130 to -140 ° P), is pumped by means of a pump 61 to a pressure of about 6890 kPa (1000 pounds per square inch man.) as needed for pipeline transport or merging with a stream 2 rich in LNG. Compressed stream 14 of lean LNG is mixed with stream 2 of rich LNG and then heated in an evaporator 62 to about 10 ° C (50 ° P) or other temperature needed to meet pipeline requirements. It should be noted that suitable heat sources for the LNG evaporator include all known heat sources (direct heat sources, such as fired heaters, sea-water heat exchangers, etc., or indirect heat sources, such as heat transfer plants with glycol). Valves 52 and 53 are preferably controlled by a control system (not shown) that regulates the mass flow between streams 2 and 3 to a predetermined ratio (most typically, to achieve the desired chemical composition and / or calorific value).

Alternatively, the heat integration and configuration processes in question may also be used to extract ethane, as depicted in the exemplary plant of FIG. 2. Here, the extraction of ethane can be changed from 5% up to 80%, as is necessary to control the calorific value of stream 1 rich in LNG. As for the numbers related to the components in FIG. 2, it should be noted that the same components in FIG. 1 and 2 have the same numbers in FIG. 2

In general, the front side of the configuration of FIG. 2 is similar to that shown in FIG. 1. However, a second column 64 (de-ethanizer) is added, so that the de-ethanizer receives fluid flow 7 from demethanizer 56. Flow pressure 7 is reduced using valve 63 to a pressure from about 1378 to 2412.5 kPa (200 to 350 psi man.) to form a stream 19, which is fed to the middle section of de-ethanizer 64. It must be appreciated that the working pressure of the de-ethanizer can be changed as required to meet the pressure requirements of the ethane product. The deethanizer overhead stream 21 is advantageously at least partially condensed in the heat exchanger 65 using the cold content of stream 14 that is poor in LNG.

The two-phase stream 22 at from about 0 to -1.1 ° C (from 0 to 30 ° P) is separated in the separator 66 into the liquid stream 23 and the ethane vapor product stream 25. A part of the fluid flow is pumped through the irrigation pump 67 and returns to the de-ethanizer overhead as the irrigation flow 24. Perhaps where a liquid ethane product is desired, some of the liquid can be produced as stream 26. Ethane vapor can be used as a fuel source in an LNG evaporator with submerged burning, used to fuel a power plant, and / or for petrochemical production. The deethanizer produces a residual product stream 20 with heat supplied from the reboiler 68 (for example, using a heat transfer unit with glycol as the heat source). The stream 15 of lean cooled LNG can then be combined with rich LNG and evaporated in preheater 62 to form pipeline gas 16 having the desired chemical composition and / or calorific value.

Alternatively, the reflux heat exchanger from the overhead in the demethanizer can be built into the column, as shown in the exemplary installation of FIG. 3. Here, the injected rich LNG is used in an irrigation condenser 69 from an overhead stream embedded in the column, producing an internal irrigation stream 10 that flows freely into the lower section of the column. The stream 6 of the heated LNG from the heat exchanger 69 is directed to the upper section of the demethanizer, below the irrigation heat exchanger 69. Again, with regard to the numbers related to the components in FIG. 3, it should be noted that the same components in FIG. 1 and 3 have the same numbers in FIG. 3

It is therefore necessary to recognize that numerous benefits can be achieved with

- 5 010743 using the installation in accordance with the subject invention. By the way, it is necessary to estimate that the facilities in question (by changing the separation ratio of the LNG inlet flow and temperature in the calorific value control section) make it possible to process LNG with varying composition and heat content, while at the same time producing “with a benefit” natural gas and / or transported LNG fuel for the North American market or other emissions sensitive market. In addition, the plants in question will produce high-purity ethane as a commercial product or as an energy source for a combined cycle power plant.

In a still further aspect considered, energy can be generated using LNG. Most preferably, the heat source heats the liquid portion of the LNG (usually after passing the LNG through the heat exchanger), and the LNG may additionally be injected to a higher pressure before heating. The LNG thus injected and heated in this manner is then expanded to produce open-cycle work (usually without typical LNG recirculation in known configurations) before entering the demethanizer. In particularly preferred installations, the LNG treatment unit has a demethanizer and de-ethanizer, in which the demethanizer removes C2 + components from the LNG using expanded steam from the expander, as a medium for stripping light fractions, and in which the heat consumption for the formation of reflux in the overhead condenser of demethanizer and de-ethanizer provided by cooling the LNG in a manner substantially similar to that described in FIG. 1-3. Preferably, the open LNG expansion cycle supplies at least a portion of the energy required for the installation of the LNG regasification. However, in alternative aspects, the energy thus generated may also be used in other parts of the installation or sold above the nominal value.

Therefore, it should be noted that the plants in question may contain a pump and a heat source that heats the first part of liquefied natural gas and an expander in which the injected and heated liquefied natural gas expands to produce work. Further, it is still preferred that at least a portion of the expanded gas is supplied to the demethanizer as purified gas to produce lean gas (at least partially depleted in ethane) and a residual product of the demethanizer in which the lean gas can be re-condensed using at least measure the proportion of cold content of LNG. The residual product of the demethanizer may then be fed to the deethanizer, which produces the product ethane and the product liquefied petroleum gas.

Additionally or alternatively, at least part of the heat consumption for the formation of reflux in the demethanizer and de-ethanizer condenser is provided by the cold content of a portion of liquefied natural gas before the heat source heats the liquid portion of liquefied natural gas, and / or the second portion of liquefied natural gas (steam portion) in the demethanizer it is divided into a lean gas and a residual product of demethanizer.

With regard to installations producing energy according to FIG. 4 and 5, it should be noted that the same considerations apply to the respective components and operating conditions, as described above for installations in accordance with FIG. 1-3. Here in FIG. 4 shows an installation in which energy is generated and in which components C2 and C3 are extracted, while in FIG. 5 shows an installation in which energy is generated and in which components of C3 are extracted.

In these plants, after the LNG is pumped by the pump 51 and heated in the heat exchanger 54 to a two-phase flow, the LNG is separated in the separator 151. The steam flow 101 from the separator is fed to the upper section of the demethanizer 56, and the flow 102 of the liquid from the separator is injected through a booster pump 152 LNG from about 17225 to 24115 kPa (from 2500 to 3500 pounds per square inch man.), Forming a stream 103. The compressed liquid is heated by an external heat source in a heat exchanger 153 using coolant 99, forming a stream 104 at from about 204.4 up to 260 ° С (from 400 d 500 ° F). Different sources of heat can be applied, including sources of waste heat from the flue gas, process waste heat and environmental heat, and / or a fuel fired heater, and the choice depends on availability and economy. Flow 104 then expands in expander 154 to flow 105 at pressures from about 2,757 to 3,446.7 kPa (400 to 500 psi), producing approximately 1,1190000 W (15,000 HP), which can be used to supply demand in the energy of the process of regasification, including the pump 152, and the excess energy is exported for sale.

The stream 105 leaving the expander at approximately 93.3 to 148.9 ° C (200 to 300 ° P) is fed to a demethanizer 56 operating at 2757 to 3446.7 kPa (400 to 500 pounds per square meter). inch man.). It should be particularly noted that the stream 105 supplies at least part, if not all, with the heat of the reboiler required for the demethanizer. Heat consumption for the formation of irrigation for demethanizer 56 is provided by means of the incoming stream 4 LNG to heat exchanger 54. It should be especially noted that such irrigation / distillation configurations of light fractions are autonomous and usually do not require any additional heat consumption. If required, a 57 side cut reboiler or 58 bottom bottom reboiler can be used to supplement the need for heat. The overhead 8 of the demethanizer is re-condensed in the heat exchanger 54, separated in the separator 59 into

- 6 010743 fluid pumped by pump 60 to form flow 12 and lean LNG 14 (through 10 and 13), additionally heated in heat exchangers 65 and 62. It should be noted that a higher inlet pressure to the expander can be used to increase production energy and efficiency. However, there is an economic trade-off between higher energy revenues and higher equipment costs. In most cases, a higher expander pressure is desired only where electrical energy can be sold above nominal value.

In the further considered aspects of the invention, it should also be noted that the LNG plant can also operate in the ethane extraction or ethane removal (propane extraction) mode, as depicted in the exemplary installation of FIG. 6. Here, ethane recovery can vary from about 2 to about 80%, as required, to meet the needs of the ethane market. The term “about,” as used herein in connection with a number, refers to a range of +/− 10% of that number. The installation of such a process is similar to the installation of FIG. 2 with some options. Thus, with regard to the configurations of FIG. 6 and 7, it should be noted that the same considerations apply to the respective components and operating conditions, as described above for installations in accordance with FIG. 2

In installations in accordance with FIG. 6, the LNG rich heating system is configured from one or more heating and separation stages before the demethanizer 56. The LNG stream 5 from the heat exchanger 54 is heated using the heat consumption for condensation of the de-ethanizer reflux in the heat exchanger 65 and then heated in the heat exchanger 55 using an external source heat 91, forming stream 6. A two-phase stream 6 is then separated in separator 87, producing a stream 73 a pair of flash evaporation, which is sent to the upper section of demethanizer 56 (via valve 86), and p The flow 71 of liquid that is supplied to the middle section of the demethanizer as flow 72 after the liquid flow is heated by an external heat source 99 in the heat exchanger 88. In general, the operation and mode of the demethanizer and de-ethanizer are similar to the operation and mode on the unit in FIG. 2, except that the C2 liquid stream 26 is pumped from the deethanizer overhead through pump 89 to approximately 8963 kPa (1300 psi) or to the pressure in the pipeline for sale. The amount of ethane produced can be altered by deflecting at least part of the stream 75 of excess liquid ethane through valve 90 in order to mix it with stream 14 of lean LNG (and / or stream 2 rich in LNG and / or a mixture of streams 2 and 14 ), forming a stream 77, before heating in a traditional evaporator 62 LNG. Alternatively, this ethane blending method can be used to produce natural gas when higher calorific value is desired for sale in a gas pipeline by increasing the ethane flow 75. Thus, by changing the flow of C2 using the diverting valve 90, the calorific value of natural gas can be controlled, and the amount of ethane produced can be changed to meet the equipment requirements, regardless of the calorific value of the imported LNG.

Similarly, the considered FGP recovery facilities may also operate to produce liquid product propane and ethane, which can be injected and transported to remote locations through the metering pipeline, as shown in the installation of FIG. 7, similar to that of FIG. 6 with some options. Thus, with regard to the installation of FIG. 7, it should be noted that the same considerations apply to the respective components and modes of operation, as described above for installations in accordance with FIG. 6

Here, one pipeline is used to transport either C2 or C3 + in alternate mode to different piping systems or production sites, and additionally includes fluid storage, pumping, and metering pipelines. Most typically, containers are provided for storing a liquid product for one day or more days to ensure stable operation of the reservoir 100 for storing the product C3 + and the reservoir 101 for storing the product C2. High pressure pumps 89 and 102 for a liquid product, respectively, are used to inject C2 or C3 + product into a 104 IGU pipeline, typically operating at 8963 kPa (1300 pounds per square inch man) or higher pressure. When using a single pipeline for the supply of C2 and C3 + product in dispensing mode, the need for two specialized pipelines for C2 and C3 + is eliminated, significantly reducing the costs associated with the pipeline.

Therefore, it should be noted that numerous advantages can be achieved using installations in accordance with the subject matter of the invention. For example, the plants in question provide a highly efficient cycle for generating energy from LNG, which can be connected to a calorific value control unit using fractionation and re-condensation. Considering other perspectives, it should be noted that the facilities considered here make it possible for LNG regasification plants to be less dependent on an external energy source, thus making such plants even more economical and flexible, while at the same time allowing the processing of LNG with varying compositions and heat content in order to comply with the technical conditions for pipelines.

Preferred installations are suitable as an additional unit for new installations.

- 7 010743 new or as a modernized installation to control the calorific value of the incoming LNG, producing poor LNG, LPG and ethane. By controlling a portion of the LNG supply and the levels of propane and ethane removal, the desired calorific value or the flow rate of the liquid product can be maintained. Any type of heat source for regasification is considered suitable, but particularly preferred heat sources include waste heat from a power plant.

Thus, it must be recognized that in some preferred installations, the demethanizer and de-ethanizer operate in such a way that the demethanizer removes the C2 + components from the LNG using heat of the reboiler and / or side fraction reboiler, and in which at least part of the heat consumption for demethanizer irrigation condensation provided by cold content rich in LNG. In addition, cooling of the deethanizer overhead condenser can be achieved by cooling from a poor LNG after the lean LNG is injected to the pressure in the pipeline. Therefore, in one aspect of the subject matter, at least part of the demethanizer overhead is cooled, partially condensed and separated, and the separated liquid is returned to the demethanizer, as irrigation, with lean gas from the separator (partially or fully depleted ethane), further cooled and condensed by entering LNG, forming a liquid phase. The liquid phase is then further injected to the pressure in the pipeline, ensuring the need for cooling the de-ethanizer, and then heated in conventional evaporators. The residual product of the demethanizer can be fed to the deethanizer, which produces the product ethane vapor and / or liquid ethane and liquefied petroleum gas product, in which, at least in some installations, the product ethane is used as fuel in evaporators or used as fuel gas in a power plant, or sold as feedstock for chemistry. In further preferred aspects of the plants in question, at least part of the heat consumption for condensation of the de-ethanizer irrigation can be ensured by cooling the portion of liquefied natural gas after steam from the de-methanizer’s irrigation separator is condensed and injected to the pressure in the pipeline.

Alternatively or additionally, the facilities in question may include a deethanizer, in which the incoming LNG (rich gas) or the outgoing LNG (lean gas) provides the heat consumption for reflux condensation for the deethanizer before the LNG is heated to the pipeline specification. In at least some of these installations, the demethanizer can produce residual product that is fed to the deethanizer, in which the deethanizer produces liquefied petroleum gas (C3 +) and ethane, which can then be sold as feedstock for petrochemicals or burned as fuel for the turbine in a combined cycle power plant. Where this is appropriate (for example, to reduce safety concerns), the first part is heated by means of a heat transfer fluid (for example, a mixture of glycol and water), which transfers heat from heat sources, such as, for example, a fuel fired heater, ambient air, circulation of water, air entering the combustion zone of the gas turbine, the release of a steam turbine, a heat recovery unit and / or a flue gas stream. Considering other prospects, the plants in question will receive LNG supplied, which is divided into the first part and the second part, in which the first part enters the calorific value control section and in which the second part is fed to the evaporator (most preferably after combining with a poor LNG).

In the additional plants under consideration, the extraction of ethane by withdrawing ethane or varying levels of ethane production is satisfied by deflecting at least part of the liquid ethane product from the deethanizer overhead to mix it with the poor LNG before heating in traditional evaporators. Such an installation allows flexible switching between ethane extraction and ethane removal, or vice versa, which may be necessary to meet the technical requirements for the calorific value of the gas sold or to adapt to changing requirements in the ethane market, while maintaining essentially the same the same process mode in the demethanizer and de-ethanizer for all jobs. Considered installations for the extraction of PGK can also work to produce products propane and ethane, which can be transported to remote pipeline systems or industrial sites through a single metering pipeline operating in variable modes. The use of a metering pipeline eliminated the need for two specialized pipelines for products C2 and C3 +, significantly reducing the cost of the pipeline.

Examples

Approximate calculation of components in selected flows.

In an exemplary installation, substantially identical to the installation, as shown in FIG. 1, the molar fraction of the various components of the selected streams was calculated, and the results are listed in the table below. LPG is a stream 20 - C3 + fraction from the bottom of the demethanizer, and the pipeline gas is depicted as stream 16.

- 8 010743

Component Poda swedish LNG uh tang with ng Trubopro waters fresh gas N2 0.00 0 0 0.0073 65 , 0000 , 0000 C1 0.88 0 0 0.9878 sixteen , 0176 , 0000 C2 0.05 0 0 0,0042 22 , 9723 , 0053 NW 0.03 0 0 0.0006 28 , 0092 , 5407 104 0, 00 0 0 0,0000 71 , 0000 1206 N04 0, 01 0 0 0,0000 07 , 0000 1818 1С5 0.00 0 0 0,0000 40 , 0000 , 0673 N05 0.00 0 0 0,0000 20 , 0000 , 0337 C6 + 0.00 0 0 0,0000 thirty , 0000 , 0505 Calorific 1.15 one 2 999 ability, 3 , 750 , 985 BTU / normal cubic feet (NNU) Million 500 2 3 450 normal five 0 cubic feet to day Barrels in 218, one 2 181,000 day Ltd 6, 000 1,000

Thus, specific embodiments and applications of LNG regasification facilities and methods have been disclosed. It should be obvious, however, to those skilled in the art that there are many more modifications besides those already described are possible without departing from the concepts of the invention here. The subject matter of the invention, therefore, should not be limited, with the exception of the essence of the attached claims. In addition, in interpreting both the description and the claims, all terms should be interpreted in the broadest possible manner consistent with the context. In particular, the terms “comprises” and “comprising” should be interpreted as referring to elements, components or stages in a non-exclusive way, meaning that the elements, components or stages referred to may be present or used, or combined with other elements components or stages to which the link is not explicitly given. In addition, where the definition or use of a term in a link, which is hereby incorporated by reference, is inconsistent or contrary to the definition of this term provided herein, the definition of this term provided here and the definition of this term does not apply in the reference.

Claims (17)

CLAIM 1. Installation for regasification of liquefied natural gas (LNG), containing a separator flow of LNG into the first and second parts with a pressure above the pressure of regasification; a device for lowering the pressure of the second part to the regasification pressure; a separator separating the first part of LNG into heavy components and the depleted LNG stream, a unit for combining the depleted LNG stream and the second part of the LNG stream to form a combined LNG stream for regasification and an evaporator for regasification of the combined LNG stream. - 9 010743 2. Installation according to claim 1, characterized in that the inlet contains a pump capable of raising the pressure of the LNG stream above the regasification pressure. 3. Installation according to claim 2, characterized in that the separator is a demethanizer. 4. Installation according to claim 3, characterized in that the demethanizer further comprises a heat exchanger, the input of the cooling circuit of which is connected to the demethanizer by the overhead product stream, and the output is connected to the demethanizer by the irrigation stream. 5. Installation according to claim 1, characterized in that it further comprises a collection of the irrigating fraction of the demethanizer to condense at least a fraction of the overhead product to obtain depleted LNG. 6. Installation according to claim 5, characterized in that it further comprises a second pump installed along the depleted LNG stream to pump its pressure to the supply pressure. 7. Installation according to claim 1, characterized in that it further comprises a deethanizer associated with the demethanizer according to its residual product and producing the overhead product C2 and the residual product C3 +. 8. The installation according to claim 7, characterized in that it further comprises a condenser of the overhead of the deethanizer, configured to cool the product of the overhead of C2 using the cold content of the first part of the LNG. 9. The installation according to claim 4, characterized in that it further comprises a separator associated with the outlet of the heating circuit of the heat exchanger, and a pump and generator, which is driven by expanding the heated and compressed portion of the first part, are sequentially installed at the outlet of the separator along the liquid phase flow LNG flow. 10. Installation for regasification of liquefied natural gas (LNG), containing a separator of the LNG stream into first and second parts, installed along the first part of the LNG stream, a heat exchanger and demethanizer, while the inlet of the cooling circuit of the heat exchanger is connected to the demethanizer overhead stream, and the output is connected to the demethanizer through the irrigation flow through the irrigation fraction collector, the heat exchanger being able to condense at least a portion of the overhead product to obtain an irrigation stream and depleted LNG, and also a unit for combining the depleted LNG stream and the second part of the LNG stream to form a combined LNG stream for regasification, and an evaporator for regasification of the combined LNG stream. 11. The installation according to claim 10, characterized in that at the outlet of the collector of the irrigating fraction along the depleted LNG stream, it contains a pump capable of pumping the pressure in the depleted LNG stream to the supply pressure. 12. A method of regasification of liquefied natural gas (LNG), in which LNG is injected to a supply pressure; separating the LNG at a feed pressure into the first and second parts; supplying the first part to the separator at a separation pressure that is lower than the supply pressure, and heavier components are separated from the first part at a separation pressure, forming a depleted LNG stream; pressurizing a depleted LNG stream to a supply pressure; combine the depleted LNG stream and the second part of the LNG to form a combined LNG stream, and the combined LNG stream is vaporized. 13. The method according to p. 12, characterized in that the supply pressure and supply pressure is between 4825 and 8963 kPa, and the separation pressure is between 2068 and 4482 kPa. 14. The method according to p. 12, characterized in that the separation of the heavier components from the first part is carried out in a demethanizer, which produces the product of the overhead demethanizer. 15. The method according to 14, characterized in that at least one part of the overhead product of the demethanizer is condensed, forming a depleted LNG and, possibly, another part of the overhead product of the demethanizer is cooled, forming an irrigation stream for the demethanizer. 16. The method according to p. 12, characterized in that the separation of the heavier components from the first part is carried out in a demethanizer and in a deethanizer, and the residual product of the demethanizer is fed to the deethanizer. 17. The method according to p. 12, characterized in that the removal of ethane or varying levels of ethane extraction is carried out by mixing part of the liquid ethane product from the overhead of the deethanizer with treated LNG from the demethanizer.