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Natural gas processing method

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Title: Natural gas processing method.
Abstract: A natural gas processing method includes: a pretreatment process of obtaining a treated natural gas; an NGL recovery process of cooling the treated natural gas obtained in the pretreatment process to recover an NGL product composed of ethane and heavier hydrocarbons and to separate a lean gas; a sales gas production process of compressing a part of the lean gas separated in the NGL recovery process to obtain a high-pressure gas; and a natural gas liquefying process of cooling the high-pressure gas after the high-pressure gas is obtained by compressing the lean gas separated in the NGL recovery process, to thereby obtain the LNG product. In the natural gas processing method, a gas compressor used in the sales gas production process is used as a gas compressor in the natural gas liquefying process. ...


- New York, NY, US
Inventors: Hitoshi Konishi, Hidefumi Omori
USPTO Applicaton #: #20080163645 - Class: 62620 (USPTO) -


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The Patent Description & Claims data below is from USPTO Patent Application 20080163645, Natural gas processing method.

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BACKGROUND OF THE INVENTION

1. Field of the Invention

Priority is claimed on Japanese Patent Application No. 2007-001187, filed Jan. 9, 2007, the content of which is incorporated herein by reference.

The present invention relates to a natural gas processing method of recovering a natural gas liquid and a high-pressure sales gas from a natural gas as major products and recovering a liquefied natural gas as a co-product.

2. Description of Related Art

In general, a natural gas liquid (hereinafter, frequently referred to as “NGL”), a liquefied natural gas (hereinafter, frequently referred to as “LNG”), and a high-pressure sales gas (hereinafter, frequently referred to as “a sales gas”) are separated and recovered from a natural gas in consideration of market demand.

Commercially available products from the natural gas excluding a self-fuel consumed in a plant are the above-mentioned three products including NGL, LNG, and the sales gas. However, there is no known instance in which all the three types of products are produced from the same plant.

Specifically, in a case where a consumption area is in the vicinity of or is neighboring a gas field, it is economical that a gas pipe is installed between the plant and the consumption area. In this case, generally, NGL and sales gas are produced as products and LNG is not produced. On the other hand, in a case where a production yield of the natural gas is more than some quantity and the consumption area is far away, for example, the production area is located in the Middle East and the consumption area is located in Asia, generally, LNG is produced as a major product and sales gas is not produced. The reason for this is as follows. The equipment cost of a liquefying plant for producing LNG is expensive. Therefore, for reducing the manufacturing cost, a large-scale plant for mass production is aimed at. As a result, a system is employed in which the LNG product can be stably supplied for a long time in order to recover the investment.

However regardless of the existence of the actual manufacturing equipment, there has been proposed a method of producing the above-mentioned three types of products from the natural gas.

In JP-T-2004-534116, there is disclosed an LNG production method of separating and recovering a natural gas liquid (referred to as “liquid stream” in JP-T-2004-534116), a liquefied natural gas (referred to as “LNG” in JP-T-2004-534116), and a high-pressure gas (referred to as “residual gas” in JP-T-2004-534116).

FIG. 1 of JP-T-2004-534116 discloses a conventional technique for producing NGL and a residual gas which is a high-pressure gas, and producing no LNG. In FIGS. 2 to 8, there are disclosed examples where the three types of products, which are NGL and the residual gas as well as LNG, are produced. In FIGS. 2 and 3, the related art of JP-T-2004-534116 is described. In FIG. 2, there is disclosed an example in which the three types of products are independently produced from a natural gas. In FIG. 3, there is disclosed an example in which cooled vapor when NGL is produced is used to produce LNG. FIGS. 4 to 8 are related to the invention of JP-T-2004-534116, and there is disclosed a method of producing LNG and NGL as major products.

In such a LNG production method, heat exchange between an NGL recovery process and an LNG production process is mainly used to save energy consumption.

However, in the method of processing the natural gas disclosed in JP-T-2004-534116, the cooled vapor is used to perform heat exchange and a compressor and an expander which are configured to have the same axial are used, so that a mechanical energy is mutually complemented between the compressor and the expander to save the energy consumption. However, the equipment configuration is complex and cost required to construct the natural gas processing plant is expensive, so that manufacturing cost is not sufficiently reduced. Consequently, there has been demanded a natural gas processing method of controlling the production of each of the products and reducing construction cost. Especially, in a case where NGL and the sales gas are reliably produced as major products and LNG is produced as a co-product from a natural gas, such a technique is not practical, since the constructing cost is considerably high. For this reason, in the case where NGL and the sales gas are produced as the major products and LNG is produced as a co-product, there has been demanded a natural gas processing method of producing them at low cost.

SUMMARY OF THE INVENTION

The invention is made in view of the above-described circumstance, with the object of providing a natural gas processing method of producing NGL and a sales gas as major products and producing LNG as a co-product from a natural gas at low cost.

Specifically, the present invention employs the following embodiments.

(1) A natural gas processing method of recovering a natural gas liquid (NGL) and a high-pressure sales gas (sales gas) as major products and recovering a liquefied natural gas (LNG) as a co-product from a natural gas, the method including: a pretreatment process of removing impurities from a feed natural gas to obtain a treated natural gas; an NGL recovery process of cooling the treated natural gas obtained in the pretreatment process to a temperature at which ethane and heavier hydrocarbons are condensed and liquefied to recover an NGL product of ethane and heavier hydrocarbons and separating a lean gas which mainly contains methane; a sales gas production process of compressing a part of the lean gas separated in the NGL recovery process by a gas compressor to obtain a high-pressure gas which is delivered as a sales gas; and a natural gas liquefying process of compressing the remaining part of the lean gas separated in the NGL recovery process by a gas compressor to obtain a high-pressure gas which exceeds critical pressure, and cooling the high-pressure gas up to a temperature at which methane is condensed and liquefied to thereby obtain an LNG product, the gas compressor used in the sales gas production being used in the natural gas liquefying process as the gas compressor.

(2) The natural gas processing method according to item (1) above, wherein the natural gas liquefying process includes: a process A of cooling a part of the LNG feed gas, which is the high-pressure lean gas being supplied in the natural gas liquefying process and exceeding the critical pressure, by heat exchanging with a low-temperature gas generated when the LNG product is produced, and adiabatically expanding the part by a liquid expander; a process B of cooling the remaining part of the LNG feed gas supplied in the process A by heat exchanging with a propane refrigerant, and adiabatically expanding the remaining part by a gas expander to liquefy the remaining part; and merging LNG produced in the process A with LNG produced in the process B to obtain an LNG product.

(3) The natural gas processing method according to item (2) above, wherein the low temperature gas generated when the LNG product is produced, and used to perform the cooling in the process A is returned to the gas compressor in the sales gas production process.

(4) The natural gas processing method according to item (1) above, wherein the LNG feed gas supplied in the natural gas liquefying process is pressurized to a pressure higher than in the sales gas production process to be used in a state where the LNG feed gas exceeds the critical pressure.

(5) The natural gas processing method according to item (1) above, wherein the natural gas liquefying process includes: a process A1 of cooling a part of the high-pressure lean gas being supplied in the natural gas liquefying process and exceeding the critical pressure by heat exchanging with a low temperature gas generated when the LNG product is produced to perform adiabatic expansion by a liquid expander; a process C of cooling some of the remaining part of the high-pressure lean gas supplied in the process A1 by heat exchanging with a propane refrigerant, cooling the some of the remaining part by heat exchanging with a self-cooling medium which is formed by cooling a fluid comprised of an LNG feed gas containing the remainder of the remaining part of the high-pressure lean gas supplied to the process A1, and liquefying the remainder of the remaining part by adiabatic expansion by the gas expander to obtain LNG; and merging LNG produced in the process A1 with LNG produced in the process C to obtain an LNG product.

(6) The natural gas processing method according to item (5) above, wherein the self-cooling medium includes a part of a gas which is cooled by heat exchanging between the remainder of the remaining part of the high-pressure lean gas supplied in the process A1 and a propane refrigerant, and wherein the remainder of the remaining part is cooled by heat exchanging, merged with the part of the gas, followed by adiabatically expanded by the gas expander, and the resulting expanded fluid is heat-exchanged as the self-cooling medium with the remaining part of the gas cooled by the heat exchanging with a propane refrigerant.

(7) The natural gas processing method according to item (6) above, wherein the self-cooling medium is returned to the gas compressor in the sales gas production process after the remainder of the remaining part of the LNG feed gas supplied in the process A1 is cooled by heat exchanging and compressed by a gas compressor.

(8) The natural gas processing method according to item (5) above, wherein the low temperature gas generated when the LNG product used to perform the cooling in the process A1 is returned to the gas compressor in the sales gas production process.

(9) The natural gas processing method according to item (1) above, wherein the natural gas liquefying process includes: a process A1 of cooling a part of an LNG feed gas which is the high-pressure lean gas being supplied in the natural gas liquefying process and exceeding the critical pressure, by heat exchanging with a low-temperature gas generated when the LNG product is produced, liquefying the part of the LNG feed gas, followed by adiabatic expansion by a liquid expander; a process D of cooling the remaining part of the LNG feed gas supplied in the process A1 by heat exchanging with a propane refrigerant, separating the gas into a gas for an LNG feed gas and a cooling medium gas, cooling the LNG feed gas by heat exchanging with a self-cooling medium obtained by adiabatically expanding the cooling medium gas, and liquefying the LNG feed gas by adiabatic expansion by a gas expander to obtain LNG; and merging LNG produced in the process A1 with LNG produced in the process D to obtain an LNG product.

(10) The natural gas processing method according to item (9) above, wherein the cooling medium gas is adiabatically expanded by a gas expander and the resulting adiabatically expanded fluid is heat-exchanged with the LNG feed gas.

(11) The natural gas processing method according to item (9) above, wherein the self-cooling medium forms a circulation cycle in which a part of a gas obtained by compressing the self-cooling medium by gas compressors is cooled by heat exchanging and adiabatically expanded by a gas expander and the resulting adiabatically expanded fluid is heat-exchanged with the LNG feed gas, followed by heating by heat exchanging, and compressing by the gas compressors.

(12) The natural gas processing method according to item (11) above, wherein the part of the gas compressed by the gas compressors is heat-exchanged with the cooling medium gas and merged with the remaining part of the gas cooled by the heat exchanging with the propane refrigerant, and the remaining part is merged with the remaining part of the LNG feed gas supplied in the process A1.

(13) The natural gas processing method according to item (5) above, wherein the LNG feed gas supplied in the natural gas liquefying process is pressurized to a pressure higher than in the sales gas production process to be used in a state where the LNG feed gas exceeds the critical pressure.

(14) The natural gas processing method according to item (1) above, wherein the pressure of the high-pressure gases supplied in the natural gas liquefying process is in the range of 40 bara to 150 bara.

By the natural gas processing method according to the invention, in a case where the natural gas liquid and the sales gas can be produced as the major products and the liquefied natural gas is recovered as the co-product, it becomes possible to use the entire plant equipment, and as a result, all the products can be produced at low cost.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram illustrating a configuration of a natural gas processing plant for performing a natural gas processing method according to a first embodiment of the invention.

FIG. 2 is a schematic diagram illustrating a configuration of a natural gas processing plant for performing a natural gas processing method according to a second embodiment of the invention.

FIG. 3 is a schematic diagram illustrating a configuration of a natural gas processing plant for performing a natural gas processing method according to a third embodiment of the invention.

FIG. 4 is a schematic diagram illustrating a configuration of a natural gas processing plant for performing a natural gas processing method according to a fourth embodiment of the invention.

FIG. 5 is a schematic diagram illustrating a configuration of a natural gas processing plant for performing a natural gas processing method according to a fifth embodiment of the invention.

FIG. 6 is a schematic diagram illustrating a configuration of a natural gas processing plant for performing a natural gas processing method according to a sixth embodiment of the invention.

DETAILED DESCRIPTION OF THE INVENTION

Hereinbelow, the best mode for carrying out the natural gas processing method according to the present invention will be described.

The following embodiment is specifically explained only for easier understanding of the principal of the present invention, and the present invention is not to be limited thereto, unless otherwise described.

(1) FIRST EMBODIMENT

FIG. 1 is a schematic diagram illustrating a configuration of a natural gas processing plant for performing a natural gas processing method according to a first embodiment of the invention.

In FIG. 1, Reference Numeral 1 denotes a feed natural gas. Reference Numeral 2 denotes a natural gas liquid (NGL). Reference Numeral 3 denotes a sales gas. Reference Numeral 4 denotes liquefied natural gas (LNG). Reference Numeral 5 denotes a pretreatment plant. Reference Numeral 6 denotes a sales gas production plant. Reference Numeral 10 denotes an entire natural gas processing plant. Reference Numeral 11 denotes an NGL recovery plant. Reference Numeral 12 denotes sales gas compressors. Reference Numeral 13 denotes a line. Reference Numeral 14 denotes a sales gas pipeline. Reference Numeral 15 denotes a natural gas liquefying plant. Reference Numeral 16 denotes an LNG storing tank. Reference Numerals 17, 18, 19, 20, and 21 denote lines. Reference Numeral 22 denotes a flash drum. Reference Numeral 23 denotes a first heat exchanger. Reference Numeral 24 denotes a liquid expander. Reference Numeral 25 denotes a second heat exchanger. Reference Numeral 26 denotes a first gas expander. Reference Numeral 27 denotes an off-gas line. Reference Numeral 28 denotes a liquid line. Reference Numeral 29 denotes a pump. Reference Numeral 30 denotes a recovery line. Reference Numeral 31 denotes a first gas compressor which has the same axial as that of the first gas expander 26. Reference Numeral 32 denotes a booster compressor.

The natural gas processing plant 10 includes the pretreatment plant 5, the sales gas production plant 6, the NGL recovery plant 11, and the natural gas liquefying plant 15.

The sale gas production plant 6 includes the sales gas compressors 12, the line 13, and the sales gas pipeline 14.

The natural gas liquefying plant 15 includes the sales gas compressors 12, the flash drum 22, the first heat exchanger 23, the liquid expander 24, the second heat exchanger 25, the first gas expander 26, the first gas compressor 31 which has the same axial as that of the first gas expander 26, and the booster compressor 32.

The NGL recovery plant 11 is connected to the sales gas compressor 12A, 12B, 12C, 12D, and 12E through the lines 17 and 18.

The sales gas compressors 12A, 12B, 12C, 12D, and 12E are connected to the sales gas pipeline 14 through the line 13 to continuously supply a high-pressure sales gas 3.

Further, the sales gas compressor 12A, 12B, 12C, 12D, and 12E are connected to the flash drum 22 through the line 19 diverging into the lines 20 and 21. The lines 20 and 21 are diverged, but merged immediately before the flash drum 22.

The first heat exchanger 23 and the liquid expander 24 are sequentially provided in a gas transfer direction in the midway of the line 20 through which a LNG feed gas is supplied.

The second heat exchanger 25 and the first gas expander 26 are sequentially provided in the gas transfer direction in the midway of the line 21.

The off-gas line 27 for taking out an off-gas of LNG is provided to the upper portion of the flash drum 22. Further, the off-gas line 27 is connected to the first heat exchanger 23.

The liquid line 28 for extracting LNG is connected to the lower portion of the flash drum 22 and is connected to the LNG storing tank 16 through the pump 29 provided in the midway of the liquid line 28.

The off-gas line 27 passing through the first heat exchanger 23 is connected to the sales gas compressor 12 via the recovery line 30 for recovering the off-gas and the line 18.

The first gas compressor 31 which has the same axial as the first gas expander 26, and the booster compressor 32 are sequentially provided in the gas transfer direction in the midway of the recovery line 30.

Next, an operation of the natural gas processing plant 10 will be described and the natural gas processing method according to the first embodiment will be described.

Firstly, various impurities, for example, a carbon dioxide, an acidic gas such as hydrogen sulfide, a sulfur compound such as mercaptan, moisture, metal such as mercury contained in a feed natural gas 1 obtained from a wellhead are separated and removed, if necessary, to obtain a treated natural gas in the pretreatment plant 5 (pretreatment process).

Next, in the NGL recovery plant 11, the treated natural gas is cooled to a temperature at which ethane and heavier hydrocarbonss are condensed and liquefied to recover NGL composed of ethane and heavier hydrocarbons and to separate a gas containing methane as a main component (hereinafter, referred to as “a lean gas”).

Herein, the “NGL recovery plant 11” refers to a plant that essentially independently recovers a condensate, i.e., pentanes and heavier hydrocarbons and a liquefied petroleum gas (LPG), composed of propane and butanes, and ethane if necessary. In the present invention, “recovering ethane and heavier hydrocarbons” means the above-described recovery process. Representative products of the NGL products 2 are a liquefied petroleum gas (LPG) composed of propane and butanes and natural gasoline, i.e., pentanes and heavier hydrocarbons.

Further, in the present invention, propane as a cooling medium used in the below-described natural gas liquefying process is separately recovered (NGL recovery process).

In the present invention, an example of the composition of the lean gas mainly containing methane which remains after the recovery of NGL is 4 mol % of nitrogen, 95 mol % of methane, and 1 mole % of ethane. The lean gas mainly containing methane has a pressure of 30 bara and a temperature of 60° C.

Subsequently, the lean gas obtained in the above-described manner is compressed by the sales gas compressors 12 to get high pressure (process before the sales gas production process and the natural gas liquefying process).

A part of the lean gas compressed by the sales gas compressors 12 to get high pressure is produced as a sales gas, which is a major product according to the present invention.

Herein, the “major product” refers to a product which has a weight ratio of 50% or more of products obtained from a natural gas, and representatively, refers to a product which has a weight ratio of at least 60% or more of products from a natural gas obtained from the wellhead as a base-load product.

Most of the high-pressure lean gas are transferred to the sales gas pipeline 14 to be finally supplied a user as a sales gas product through the sales gas pipeline 14 (sales gas production process).

Of the lean gas pressurized to higher pressure than its critical pressure by the sales gas compressors 12, the remaining gas from which the sales gas has been produced is used as the LNG feed gas.

More specifically, a part of the high-pressure gas supplied as the LNG feed gas is supplied through the line 19 in the natural gas liquefying process and liquefied, as described below, to be manufactured into an LNG product (natural gas liquefying process).

An example of the high-pressure gas which is pressurized to higher pressure than its critical pressure after the gas is supplied by the sales gas compressors 12 is a high-pressure gas having a pressure of 105 bara and a temperature of 60° C., which is described below.

In the present invention, the pressure of the high-pressure gas supplied in the natural gas liquefying process is appropriately selected in the range of 40 to 150 bara. In order to increase the recovery amount of LNG, the pressure of the high-pressure gas supplied in the natural gas liquefying process is preferably higher, and more preferably 80 bara or more.

Next, the natural gas liquefying process will be described.

A part of the LNG feed gas transferred to the line 19 is transferred to the line 20 to be processed in a process A including processes A-1 and A-2. The remainder of the LNG feed gas is transferred to the diverged line 21 to be processed in a process B including processes B-1 and B-2. In this manner, the LNG feed gas is liquefied to obtain LNG products.

The LNG feed gas transferred through the line 20 is cooled in the first heat exchanger 23 by heat exchanging with a low temperature gas generated when LNG in the flash drum 22 is produced. That is, the LNG feed gas is cooled down to −158° C. by the heat exchanging with the gas having a temperature −161° C. transferred through the off-gas line 27 of LNG (the process A-1).

Next, the pressure of a part of the cooled LNG feed is reduced by adiabatic expansion using the liquid expander 24 to be recovered as an LNG product (the process A-2).

As described above, the high-pressure gas transferred to the line 20 is a part of the LNG feed gas, but the amount of the high-pressure gas transferred to the line 20 is defined as the amount of gas within the range which can be supplied after the high-pressure gas is cooled by the heat exchanging with the off-gas transferred from the flash drum 22 and cooled down to −158° C. to the liquid expander 24. Therefore, the LNG feed gas supplied to the liquid expander 24 can be adjusted to 10% or more of the entire LNG feed gas or 30% or less thereof, and such a process is essential in the present invention.

On the other hand, the remainder of the LNG feed gas transferred to the line 21 is cooled down to −33° C. in the second heat exchanger 25 by a cooling medium of which the major component is the propane recovered in the NGL recovery process (the process B-1).

Then, a part of the LNG feed gas cooled by the second heat exchanger 25 is liquefied by adiabatic expansion using the first gas expander 26 to thereby obtain LNG product (the process B-2).

Subsequently, the LNG product produced in the process A and the LNG product produced in the process B are merged immediately before the flash drum 22 and transferred to the flash drum 22.

Thereafter, the LNG products transferred to the flash drum 22 are produced as an LNG product by adjusting pressure.

The flash drum 22 is operated under a pressure of 1.1 bara and the off-gas line 27 is provided at the upper portion thereof so that a low temperature off-gas of −161° C. is separated to be transferred to the first heat exchanger 23. At the lower portion of the flash drum 22, the produced LNG is transferred to the LNG storing tank 16 through the liquid line 28 by the pump 29 to be recovered.

The off-gas is transferred from the flash drum 22 to the first heat exchanger 23 and used to cool the LNG feed gas is elevated up to about 30° C. The off-gas is compressed by the first gas compressor 31 which has the same axial as that of the first gas expander 26, to raise the pressure thereof 2.5 bara, and the off-gas is further compressed by the booster compressor 32, and the pressure thereof at the inlet of the sales gas compressors 12 increases up to 30 bara. Then, the supplied gas is transferred to the sales gas compressors 12 through the line 18.

In the natural gas processing method according to the first embodiment, a part of the high-pressure gas compressed by the sales gas compressors 12 is produced as the sales gas, and the remainder of the high-pressure gas is supplied as the LNG feed gas. At this time, the liquefied natural gas is produced by a simple method of a combination of the process A of cooling a part of the LNG feed gas by the heat exchange with the low temperature off-gas separated by the flash drum 22, and then lowering the pressure of the part thereof by the adiabatic expansion of the liquid expander, and the process B of cooling the remainder of the LNG feed gas by use of the propane refrigerant, and then liquefying the remainder thereof by the gas expansion. This method is advantageous in that it is not necessary to provide an independent booster machine used in the natural gas liquefying process and production cost can be significantly reduced by the combination of the above-described simplified processes, as compared to a conventional processing method. Furthermore, in the natural gas processing method according to the first embodiment, the low temperature gas which is separated by the flash drum 22 to be used in cooling of the high-pressure gas is compressed and transferred again to the sales gas compressors 12 to be supplied to a process of producing the sales gas and the liquefied natural gas. Accordingly, gas waste does not occur.

(2) SECOND EMBODIMENT

FIG. 2 is a schematic diagram illustrating a configuration of a natural gas processing plant for performing a natural gas processing method according to a second embodiment of the invention.

In FIG. 2, the same reference numerals are used for the same components as those of the natural gas processing plant 10 shown in FIG. 1 and explanations thereof are omitted.

A natural gas processing plant 40 is different from the above-described natural gas processing plant 10 in that a second gas compressor 41 compressing only an LNG feed gas is provided between a line 19 and a line 19′ and before a diverging point of lines 20 and 21. Other configurations are the same as those according to the above-described first embodiment.

Hereinafter, an operation of the natural gas processing plant 40 will be described and a method of processing a natural gas according to the second embodiment will be described.

First, a feed natural gas 1 obtained from a wellhead is processed in a pretreatment process and an NGL recovery process, like those according to the first embodiment.

Next, impurities are removed and NGL is recovered to separate and recover a lean gas mainly containing methane under a pressure of 30 bara and at a temperature of 60° C. in the same manner as that according to the above-described first embodiment, and then the lean gas is transferred to the sales gas compressors 12 (12A, 12B, 12C, 12D, and 12E) through the lines 17 and 18.

The composition of the treated gas is the same as the above-described composition.

In the second embodiment, when the lean gas is highly pressurized by the sales gas compressors 12, the lean gas can be processed under a pressure lower than that according to the first embodiment, for example, a pressure of 56 bara, and a temperature of 60° C.

In a sales gas production process, a part of the high-pressure gas having a pressure of 56 bara obtained by the sales gas compressors 12 is produced as a product of a sales gas 3 transferred via a sales gas pipeline 14.

On the other hand, in the natural gas liquefying process, a part of the high-pressure gas having the pressure of 56 bara highly pressurized by the sales gas compressors 12, that is, the remainder of the high-pressure gas used in the above-described sales gas production process is used as an LNG feed gas. The LNG feed gas is further compressed by the second gas compressor 41 to be pressurized to higher pressure than its critical pressure. Specifically, only the LNG feed gas having the pressure of 56 bara introduced in the natural gas liquefying process can be pressurized by the second gas compressor 41 at a pressure of 105 bara.

Subsequently, a part of the LNG feed gas further compressed by the second gas compressor 41 is transferred to the line 20 in the same manner as that according to the first embodiment to be processed in the same process A as that according to the first embodiment. Further, the remainder of the LNG feed gas is all transferred to line 21 to be processed in the same process B as that according to the first embodiment. Thus, the LNG feed gas can be processed in the same manner as that according to the first embodiment.

In the natural gas processing method according to the second embodiment, when the pressure necessary for the sales gas is not so high, for example, 56 bara, the lean gas is compressed to an appropriate pressure necessary for the sales gas by the sales gas compressors 12 and only the LNG feed gas supplied in the natural gas liquefying process can be increased to a higher pressure (105 bara) by the second gas compressor 41. In this case, since the pressure in the natural gas liquefying process can be equalized to the pressure according to the first embodiment, the sales gas compressors 12 can be effectively used without reducing the productivity of the LNG product. As a result, it becomes possible to save the entire energy consumption while ensuring the production of LNG.

(3) THIRD EMBODIMENT

FIG. 3 is a schematic diagram illustrating a configuration of a natural gas processing plant 50 for performing a natural gas processing method according to a third embodiment of the invention.

In FIG. 3, the same reference numerals are used for the same components as those of the natural gas processing plant 10 shown in FIG. 1 and the explanations thereof are omitted.

A natural gas processing plant 50 according to the third embodiment is different from the above-described natural gas processing plant 10 in that the line 21 diverging from the line 20 in the midway of a line 19 in a natural gas liquefying plant 55 has different connected portions. Specifically, the line 21 is further diverged to provide a line for liquefying the LNG feed gas to obtain a product, and a line for transferring the LNG feed gas as a cooling medium. Other configurations are basically the same as those according to the above-described first embodiment.

In FIG. 3, Reference Numeral 50 denotes the natural gas processing plant. Reference Numeral 55 denotes a natural gas liquefying plant. Reference Numerals 70, 71, 72, and 73 denote lines. Reference Numeral 74 denotes a third heat exchanger. Reference Numeral 75 denotes a second gas expander. Reference Numeral 76 denotes a fourth heat exchanger. Reference Numeral 77 denotes a line. Reference Numeral 81 denotes a second gas compressor which has the same axial with the second gas expander. Reference Numeral 82 denotes a line.

The natural gas processing plant 50 mainly includes a pretreatment plant 5, a sales gas production plant 6, an NGL recovery plant 11, and the natural gas liquefying plant 55. The natural gas liquefying plant 55 mainly includes a sales gas compressor 12, a flash drum 22, a first heat exchanger 23, a liquid expander 24, a second heat exchanger 25, a first gas expander 26, the third heat exchanger 74, the second gas expander 75, the fourth heat exchanger 76, a first gas compressor 31 which has the same axial with the first gas expander 26, a booster compressor 32, and a second gas compressor 81 which has the same axial with the second gas expander.

A lean gas which remains after NGL is recovered by the NGL recovery plant 11, which is connected to sales gas compressors 12 via the lines 17 and 18. Further, the sales gas compressors 12 are connected to the sales gas pipeline 14 which supplies the sales gas and also connected to the line 19 for producing LNG.

The line 19 is diverged into the lines 20 and 21 to be connected to the flash drum 22 for producing LNG.

The first heat exchanger 23 and the gas expander 24 are sequentially provided in the gas transfer direction in the midway of the line 20.

The configuration described above is the same as that according to the first embodiment, except that the line 21 is diverged into the lines 70 and 71. Further, the line 70 is diverged into the lines 72 and 73. The second heat exchanger 25 which performs heat exchange operation with a propane refrigerant is provided in the midway of the line 70 and before the diverged point of the lines 72 and 73.

The line 71 is connected to the second gas expander 75 via the third heat exchanger 74.

The lines 71 and 73 are merged between the third heat exchanger 74 and the second gas expander 75.

The fourth heat exchanger 76 and the first gas expander 26 are sequentially provided in the gas transfer direction in the midway of the line 72.

The lines 20 and 72 are merged immediately before the flash drum 22.

The second gas expander 75 is connected to the second gas compressor 81 which has the same axial as that of the second gas expander 75 via the line 77 in which the fourth heat exchanger 76 and the third heat exchanger 74 are provided sequentially in the gas transfer direction.

The flash drum 22 is connected to the first heat exchanger 23 via the line 27. Further, the flash drum 22 is connected to an LNG storing tank 16 via the line 28 and a pump 29 which is provided in the midway of the line 28.

The first heat exchanger 23 is connected to the first gas compressor 31 which has the same axial as that of the first gas expander 26 via the line 30.

The first gas compressor 31 and the booster compressor 32 are sequentially provided in the gas transfer direction in the midway of the line 30.

The line 30 is merged in the vicinity of the inlet of the sales gas compressors 12 with the line 82 extending from the second gas compressor 81 which has the same axial with the second gas expander 75.

Next, an operation of the natural gas processing plant 50 will be described and a natural gas processing method according to the third embodiment will be described.

In the NGL recovery plant 11, ethane and heavier hydrocarbons are cooled down to a temperature of condensation and liquefaction to recover an NGL product 2 composed of ethane and heavier hydrocarbons and to separate a lean gas which mainly contains methane (NGL recovery process).

The lean gas separated in the NGL recovery process is transferred to the sales gas compressors 12 (12A, 12B, 12C, 12D, and 12E) via the lines 17 and 18 as a sales gas and an LNG feed gas under a pressure of 30 bara and at a temperature of 60° C.

The composition of the lean gas is 4 mol % of nitrogen, 95 mol % of methane, and 1 mol % of ethane.

In the sales gas production process, the sales gas can be produced in the same manner as that according to the above-described first embodiment.

The high-pressure gas which is pressurized to higher pressure than its critical pressure after the gas is supplied by the sales gas compressors 12 is a high-pressure gas having pressure of 105 bara and a temperature of 60° C.

Next, a natural gas liquefying process will be described.

A part of the LNG feed gas transferred to the line 19 is transferred to the line 20 to be processed in the same process A1 as that according to the first embodiment. The remainder of the LNG feed gas is transferred to the diverged line 21 to be processed in a process C. In this manner, each processed LNG product can be obtained.

The LNG feed gas transferred through the line 20 is cooled down to −158° C. by the first heat exchanger 23 (process A1-1) and the pressure is reduced by adiabatic expansion using the liquid expander 24 (process A1-2) to be recovered as an LNG product in the liquefaction process A including the processes A1-1 and A1-2.

On the other hand, the LNG feed gas transferred through the line 21 is processed in a liquefaction process C including processes C-1, C-2, C-3, C-4, and C-5.

More specifically, the LNG feed gas transferred through the line 21 is diverged to be transferred to the lines 70 and 71 (the process C-1).

The LNG feed gas transferred through the line 70 is cooled down to −33° C. by the propane refrigerant by the second heat exchanger 25 (the process C-2).

Then, the LNG feed gas cooled by the second heat exchanger 25 is diverged to be transferred to the lines 72 and 73 (the process C-3).

The LNG feed gas transferred through the line 72 is cooled down to −97° C. by the fourth heat exchanger 76 by using a fluid which is transferred via the line 77 from the third heat exchanger 74 and used as a cooling medium.

Then, the fluid cooled by the fourth heat exchanger 76 is subjected to the adiabatic expansion by the first gas expander 26 to thereby obtain the LNG product (the process C-5).

Subsequently, the LNG product produced in the process A1 and the LNG product produced in the process C are merged immediately before the flash drum 22 and transferred to the flash drum 22.

Thereafter, by adjusting the pressure of the LNG product transferred to the flash drum 22, the LNG product is transferred to the LNG storing tank 16 via the line 28 by the pump 29 to be recovered as the LNG product.

The flash drum 22 is operated under a pressure of 1.1 bara.

An off-gas of −161° C. transferred from the flash drum 22 via the line 27 is heat-exchanged with the LNG feed gas by the first heat exchanger 23, and the temperature of the off-gas becomes 33° C. The off-gas of 33° C. is compressed by the first gas compressor 31 which has the same axial as that of the first gas expander 26, to raise the pressure thereof to 1.8 bara, and the off-gas is further compressed by the booster compressor 32, so that the pressure thereof at the inlet of the sales gas compressors 12 increases up to pressure of the supply gas (30 bara). Then, the supplied gas is transferred to the sales gas compressors 12 through the line 18.

In the process C of obtaining the above-described LNG, a part of the LNG feed gas is not produced as the LNG product, but circulates as a cooling medium in the process. Hereinafter, this gas is referred to as its self-cooling medium. A flow of the self-cooling medium will be described in processes CC-1 to CC-6.

The self-cooling medium gas of 60° C. which is diverged from the line 21 and transferred through the line 71 is cooled down to −33° C. by heat exchange with a cooling medium gas of −37° C. by the third heat exchanger 74 (the process CC-1)

The cooling medium gas of the third heat exchanger 74, which becomes the other gas in the process CC-1, is heated from −37° C. to 45° C. by heat exchange with the self-cooling medium gas of 60° C.

Subsequently, the self-cooling medium gas cooled down to −33° C. and the self-cooling medium gas of −33° C. transferred to the line 73 diverged from the line of LNG product in the process C-3 are merged to be transferred to the second gas expander 75 (the process CC-2).

The self-cooling medium gas of −33° C. obtained in the process CC-2 is expanded by the second gas expander 75, so as to lower the temperature thereof to −102° C. (the process CC-3).

Subsequently, the self-cooling medium fluid which has been lowered to −102° C. is transferred to the fourth heat exchanger 76 and subjected to heat exchange with the LNG feed gas of −33° C. in the process C-2, so as to lower the temperature to −97° C. In this manner, the self medium fluid becomes the cooling medium gas in the process CC-1 (the process CC-4).

The LNG feed gas of the fourth heat exchanger 76, which becomes the other gas in the process CC-4, is cooled from −33° C. to −97° C. by heat exchange with the self-cooling medium gas of −102° C.

The self-cooling medium gas of −37° C. obtained in the process CC-4 is a gas of the other side in the process CC-1 and is heated up to 45° C. by heat exchange of a gas of 60° C. by the third heat exchanger 74 (the process CC-5).

The self-cooling medium gas of 45° C. obtained in the process CC-5 is compressed by the second compressor 81 which has the same axial as that of the second gas expander 75, the pressure thereof is increased up to the pressure of the supplied gas (30 bara) at the inlet of the sales gas compressors 12, and the self-cooling medium is transferred to the sales gas compressors 12 via the lines 82 and 18 (the process CC-6).

In the natural gas processing method according to the third embodiment, a part of the LNG feed gas is used as the cooling medium gas. Accordingly, the production of LNG decreases, as compared to that according to the first embodiment. Nevertheless, it becomes possible to improve efficiency in liquefaction of the LNG feed gas.

Especially, since the LNG feed gas can be used as the cooling medium gas, a production process can be designed more flexibly. Moreover, since the LNG feed gas circulates as the feed gas, cost of the LNG feed gas is not wasted.

(4) FOURTH EMBODIMENT

FIG. 4 is a schematic diagram illustrating a configuration of a natural gas processing plant for performing a natural gas processing method according to a fourth embodiment of the invention.

In FIG. 4, the same reference numerals are used the same components as those of the natural gas processing plant 50 shown in FIG. 3 and explanations thereof are omitted.

A natural gas processing plant 90 is different from the above-described natural gas processing plant 50 in that a fourth gas compressor 91 compressing only an LNG feed gas is provided between a line 19 and a line 19′ and before a diverging point of lines 20 and 21. Other configurations are the same as those according to the above-described third embodiment.

An operation of the natural gas processing plant 90 will be described, focusing in the difference from the operation according to the third embodiment.

In the fourth embodiment, when a lean gas supplied from an NGL recovery plant 11 is compressed at high-pressure by a sales gas compressor 12, the lean gas can be operated at low pressure of, for example, 56 bara, which is lower than that in the third embodiment. Accordingly, a sales gas 3 is produced as a product.

On the other hand, in a natural gas liquefying process, only the LNG feed gas is further boosted to higher pressure than its critical pressure by the fourth gas compressor 91.

For example, the pressure of 56 bara is compressed up to the pressure of 105 bara, so that the subsequent natural gas liquefying processes can be operated under the same condition as that according to the above-described third embodiment.

In the natural gas processing method according to the fourth embodiment, even when the pressure necessary for the sales gas is not so high (56 bara), only the LNG feed gas supplied in the natural gas liquefying process can be boosted by the fourth gas compressor 91 (105 bara). Accordingly, the LNG feed gas can be processed in the same process as that according to third embodiment, and the sales gas compressors 12 can be effectively used without reducing the productivity of the LNG product. As a result, it becomes possible to save the entire energy consumption and ensure the production of LNG.

(5) FIFTH EMBODIMENT

FIG. 5 is a schematic diagram illustrating a configuration of a natural gas processing plant 100 for performing a natural gas processing method according to a fifth embodiment of the invention.

In FIG. 5, the same reference numerals are used for the same components as those of the natural gas processing plant 50 shown in FIG. 3 and explanations thereof are omitted.

In FIG. 5, Reference Numeral 100 denotes the natural gas processing plant. Reference Numeral 105 denotes a natural gas liquefying plant. Reference Numerals 120 and 121 denote lines. Reference Numeral 122 denotes a third heat exchanger. Reference Numeral 123 denotes a second gas expander. Reference Numeral 124 denotes a fourth heat exchanger. Reference Numeral 125 denotes a line. Reference Numeral 129 denotes a third gas compressor which has the same axial as that of the second gas expander 123. Reference Numeral 130 denotes a line. Reference Numeral 131 denotes a fourth gas compressor. Reference Numeral 132 denotes a line.

The natural gas processing plant 100 mainly includes a pretreatment plant 5, a sales gas production plant 6, an NGL recovery plant 11, and the natural gas liquefying 105.

The natural gas liquefying plant 105 mainly includes a sales gas compressor 12, a flash drum 22, a first heat exchanger 23, a liquid expander 24, a second heat exchanger 25, a first gas expander 26, the third heat exchanger 122, the second gas expander 123, the fourth heat exchanger 124, a third gas compressor 129 which has the same axial with the second gas expander 123, and a fourth gas compressor 131.

The natural gas liquefying plant 105 according to the fifth embodiment is different from the above-described natural gas liquefying plant 55 according to the above-described third embodiment in that in the natural gas liquefying plant 105, the LNG feed gas is used as an self-cooling medium gas so as to be circulated, whereas the LNG feed gas is transferred back to the sales gas compressors in the third embodiment. Specifically, at the downstream of the second heat exchanger 25 which performs heat exchange with a propane refrigerant of the line 21 to which the LNG feed gas is diverged and supplied, the lines 120 and 121 are diverged. The former is a line for LNG production and the latter is a line for the self-cooling medium gas. A part of the self-cooling medium gas transferred through the latter is returned before the second heat exchanger 25 which performs the heat exchange with the propane refrigerant and merged with the gas of the line 21 so as to be circulated. Other configurations are the same as those according to the above-described third embodiment.

Hereinafter, the fifth embodiment will be described, focusing on the difference from the above-described third embodiment.

The line 21 is diverged into the lines 120 and 121 at the downstream of the second heat exchanger 25 which performs the heat exchange with the propane refrigerant. Between the third heat exchanger 122 and the second gas expander 123, the latter line 121 is merged with the line 130 through which the self-cooling medium gas is circulated.

The second gas expander 123 is connected to the third gas compressor 129 which has the same axial as that of the second gas expander 123 via the line 125 in which the fourth heat exchanger 124 and the third heat exchanger 122 are sequentially provided in a gas transfer direction.

Further, the third gas compressor 129 is connected to the second gas expander 123 via the line 130 in which the fourth gas compressor 131 and the third heat exchanger 122 are sequentially provided in a gas transfer direction.

In this manner, the lines 130 and 125 form a circulation loop of the self-cooling medium gas.

The line 132 diverged from the line 130 forming the circulation loop of the self-cooling medium gas is merged with the line 21 immediately before the second heat exchanger 25.

Next, an operation of the natural gas processing plant 100 will be described and a natural gas processing method according to the fifth embodiment will be described. The same description as that according to the above-described embodiments is omitted and a natural gas liquefying process will be described.

The natural gas liquefying process according to the fifth embodiment will be described.

A part of the LNG feed gas transferred through the line 19 is transferred to the line 20 to be processed in the same liquefying process A2 as the liquefying process A according to the first embodiment. The remainder thereof is transferred to the diverged line 21 and processed in a liquefying process D. In this manner, each LNG product is obtained.

The LNG feed gas transferred through the line 20 is cooled down to −158° C. by the first heat exchanger 23 (process A2-1). Then, the pressure of the LNG feed is reduced by adiabatic expansion using the liquid expander 24 (process A2-2). An LNG product is recovered in the liquefying process A2 including the processes A2-1 and A2-2

On the other hand, the LNG feed gas transferred through the line 21 is subjected to the liquefying process D including the following processes D-1, D-2, and D-3.

Specifically, the LNG feed gas of 60° C. supplied through the line 21 is cooled down to −33° C. by heat exchanging with the propane refrigerant by use of the second heat exchanger 25, and then transferred to the lines 120 and 121 (the process D-1).

The LNG feed gas transferred through the line 120 is cooled down to −97° C. by the fourth heat exchanger 124 which uses a high-pressure fluid transferred via the line 125 from the third heat exchanger 122 (the process D-2).

Then, the LNG feed gas cooled down to −97° C. obtained in the above-described process is adiabatically expanded by the first gas expander 26 to thereby obtain an LNG product (the process D-3).

Subsequently, the LNG product produced in the process A2 and the LNG product produced in the process D are merged immediately before the flash drum 22 to be transferred to the flash drum 22.

Thereafter, the LNG product transferred to the flash drum 22 is transferred to an LNG storing tank 16 as an LNG product via the line 28 by a pump 29 by adjusting the pressure thereof to be recovered as an LNG product 4.

The flash drum is operated under a pressure of 1.1 bara.

An off-gas of −161° C. from the flash drum 22 is compressed by the first gas compressor 31 in the same manner as that according to the above-described embodiments and the pressure thereof becomes 1.8 bara. Further, the off-gas is compressed by a booster compressor 32, and the pressure thereof is increased to a pressure at the inlet of the sales gas compressors 12 (30 bara) and transferred to the sales gas compressors 12 via the line 18.

With respect to the flow of the self-cooling medium for obtaining the LNG, explanations will be given following the process D including DD-1 to DD-9.

A part of the LNG feed gas which is cooled to −33° C. by heat exchanging with the propane refrigerant by the second heat exchanger 25 provided in the line 21 is diverged to be supplied to the line 121 as the self-cooling medium gas. The diverged lines are merged with the line 133 between the third heat exchanger 122 and the second gas expander 123 (the process DD-1).

The self-cooling medium gas supplied through the line 130 is cooled down to −102° C. by adiabatic expansion using the second gas expansion 123 (the process DD-2).

The self-cooling medium gas of −102° C. obtained in the process DD-2 is supplied to the fourth heat exchanger 124 via the line 125 (the process DD-3).

The temperature of the self-cooling medium fluid supplied to the fourth heat exchanger 124 in the process DD-3 becomes −37° C. by heat exchange with the LNG feed gas of −33° C. (the process DD-4).

Then, the self-cooling medium gas of −37° C. is supplied to the third heat exchanger 122 via the line 125 (the process DD-5).

The temperature of the self-cooling medium gas of −37° C. supplied to the third heat exchanger 122 becomes 45° C. by heat exchange with the self-cooling medium gas of 60° C. (the process DD-6).

Subsequently, the self-cooling medium gas of 45° C. is compressed to a pressure of 30 bara by the third gas compressor 129 which has the same axial as that of the second gas expander 123 and transferred to the fourth gas compressor 131 via the line 130 (the process DD-7).

Thereafter, the self-cooling medium which becomes a high-pressure gas transferred to the fourth gas compressor 131 is boosted up to 105 bara by the fourth gas compressor 131. Then, a part of the self-cooling medium gas is transferred to the third heat exchanger 122 via the line 130 and the temperature thereof becomes −33° C. by heat exchanging (the process DD-8).

The remainder of the self-cooling medium gas in the process DD-8 is transferred to the line 21 via the line 132 and merged with a part of the LNG feed gas to be supplied to heat exchange with the propane refrigerant (the process DD-9). The amount of self-cooling medium gas transferred via the line 132 is the same as that returned to the line 133 via the line 121.

In the natural gas processing method according to the fifth embodiment, advantages more effective than those obtained according to the above-described third embodiment can be obtained. That is, the same advantages as those according to the above-described first embodiment can be obtained. Moreover, although the power required for circulating the cooling medium gas increases, the ability to liquefy the LNG feed gas can be improved. As a result, it becomes possible to improve a recovery ratio of the LNG product. Therefore, making a balance between the cost of the LNG product and the cost of power consumption enables an optimum production system.

Especially, since the LNG feed gas can be used as the cooling medium gas, a production process can be designed more flexibly. Moreover, since the LNG feed gas circulates as the feed gas, cost of the LNG feed gas is not wasted.

(6) SIXTH EMBODIMENT

FIG. 6 is a schematic diagram illustrating a configuration of a natural gas processing plant for performing a natural gas processing method according to a sixth embodiment of the invention.

In FIG. 6, the same reference numerals are used for the same components as those of the natural gas processing plant 100 shown in FIG. 5 and explanations thereof are omitted.

A natural gas processing plant 140 is different from the above-described natural gas processing plant 100 in that a fifth gas compressor 141 which compresses only an LNG feed gas so that the pressure thereof becomes higher pressure than its critical pressure is provided in the midway of the line 19 to which the LNG feed gas is supplied and before the diverged point between the lines 20 and 21. Other configurations are the same as those according to the above-described fifth embodiment.

An operation of the natural gas processing plant 140 will be described, focusing on the difference from the operation according to the fifth embodiment.

In the sixth embodiment, when a lean gas supplied from an NGL recovery plant is compressed at high-pressure by a sales gas compressor 12, the lean gas can be operated at low pressure of, for example, 56 bara, which is lower than that in the fifth embodiment. Accordingly, a sales gas 3 is produced as a product.

On the other hand, in a natural gas liquefying process, only the LNG feed gas is further boosted to higher pressure than its critical pressure by the fifth gas compressor 141. For example, the pressure of 56 bara is compressed up to the pressure of 105 bara, so that the subsequent natural gas liquefying processes can be operated under the same condition as that according to the above-described fifth embodiment.

In the natural gas processing method according to the sixth embodiment, even when the pressure necessary for the sales gas is not so high (56 bara), only the LNG feed gas supplied to the natural gas liquefying process can be boosted by the fifth gas compressor 141 (105 bara). Accordingly, the LNG feed gas can be processed in the same process as that according to fifth embodiment, and the sales gas compress 12 can be effectively used without reducing the productivity of the LNG product. As a result, it becomes possible to save the entire energy consumption and ensure the production of LNG.

EXAMPLES

Hereinafter, Examples according the invention will be described in detail, but the invention is not limited to the following Examples.

Example 1

A natural gas processing operation was performed using the natural gas processing plant 10 shown in FIG. 1.

Of the lean gas (of which the composition is 4 mol % of nitrogen, 95 mole % of methane, and 1 mole % of ethane) supplied through the line 18, 2000 (MMSCFD) was supplied to the sales gas compressor 12, 200 (10%) (MMSCFD) was used as the LNG feed gas, and 1800 (90%) (MMSCFD) was used as the sales gas.

As conditions necessary to perform the processing, motive power of the sales gas compressor 12, motive power of the booster gas compressor 32, and motive power of the propane refrigerant compressor (which is used for cooling in the second heat exchanger 25) are shown in Table 1.

Total sales was calculated on the assumption that the sales gas is 2 (US$) and LNG is 4 (US$) per 1 (MMBTU) (the same applies for the following examples).

As a result, the amount of recovered liquefied natural gas was 0.56 (MTA) and total sales of the sales gas and LNG was 1328 (MMUS$/year).

Motive power (specific power) of a compressor necessary to produce a unit weight of LNG was 0.430 (kW·hr/kg−LNG).

Example 2

A natural gas processing operation was performed using the natural gas processing plant 50 shown in FIG. 3.

The same lean gas as that used in Example 1 was used, and the sales gas and the LNG feed gas was distributed in the same manner.

As conditions necessary to perform the processing, motive power of the sales gas compressor 12, motive power of the booster gas compressor 32, and motive power of the propane refrigerant compressor (which is used for cooling in the second heat exchanger 25) are shown in Table 1.

As a result, the amount of recovered liquefied natural gas was 0.39 (MTA) and total sales of the sales gas and LNG was 1294 (MMUS$/year).

Motive power (specific power) of a compressor necessary to produce a unit weight of LNG was 0.363 (kW·hr/kg−LNG).

Example 3

A natural gas processing operation was performed using the natural gas processing plant 105 shown in FIG. 5.

The same lean gas as that used in Example 1 was used, and the sales gas and the LNG feed gas was distributed in the same manner.

As conditions necessary to perform the processing, motive power of the sales gas compressor 12, motive power of the booster gas compressor 32, motive power of the propane refrigerant compressor (which is used for cooling in the second heat exchanger 25), and motive power of the fourth gas compressor 131 for the self-cooling medium are shown in Table 1.

As a result, the amount of recovered liquefied natural gas was 0.91 (MTA) and total sales of the sales gas and LNG was 1397 (MMUS$/year).

Motive power (specific power) of a compressor necessary to produce a unit weight of LNG was 0.363 (kW·hr/kg−LNG).

TABLE 1 Reference Reference Example 1 Example 2 Example 3 Example 1 Example 2 Amount of gas supplied 1800 1800 1800 2000 1800 for sales gas (MMSCFD) Motive power of sales 122.5 122.5 122.5 122.5 110.25 gas compressor (MW) (Motive power necessary (7)  (8.7) (4)  (—) (—) to re-compress gas from natural gas liquefying plant) a) Motive power of booster 18 5.2 12.2 — — compressor (MW) b) Motive power of 4 3.1 7.2 — — compressor using propane refrigerant (MW) c) Motive power of — — 16.1 — — compressor using cooling medium (MW) d) Total additional motive 29 17 39.5 — — power (MW) e) = a) + b) + c) + d) Amount of gas supplied 200 200 200 0 0 for liquefied natural gas (MMSCFD) Amount of recovered 0.56 0.39 0.91 0 0 liquefied natural gas (million ton/year) (ton/time) f) (67)   (46)   (109)   (—) (—) Sales of Sales gas + LNG 1328 1294 1397 1352 1217 (MMUS$/year) Specific power 0.430 0.363 0.363 — — (kW-h/Kg-LNG) e)/f)

Example 4

A natural gas processing operation was performed using the natural gas processing plant 10 shown in FIG. 1.

The same lean gas as that used in Example 1 was used, 1600 (80%) (MMSCFD) was used as the sales gas, and 400 (20%) (MMSCFD) was used as the LNG feed gas.

As conditions necessary to perform the processing, motive power of the sales gas compressor 12, motive power of the booster gas compressor 32, and motive power of the propane refrigerant compressor (which is used for cooling in the second heat exchanger 25) are shown in Table 2.

As a result, the amount of recovered liquefied natural gas was 1.12 (MTA) and total sales of the sales gas and LNG was 1304 (MMUS$/year).

Motive power (specific power) of a compressor necessary to produce a unit weight of LNG was 0.430 (kW·hr/kg−LNG).

Example 5

A natural gas processing operation was performed using the natural gas processing plant 50 shown in FIG. 3.

The same lean gas as that used in Example 1 was used, and the sales gas and the LNG feed gas was distributed in the same manner as that in Example 4.

As conditions necessary to perform the processing, motive power of the sales gas compressor 12, motive power of the booster gas compressor 32, and motive power of the propane refrigerant compressor (which is used for cooling in the second heat exchanger 25) are shown in Table 2.

As a result, the amount of recovered liquefied natural gas was 0.78 (MTA) and total sales of the sales gas and LNG was 1237 (MMUS$/year).

Motive power (specific power) of a compressor necessary to produce a unit weight of LNG was 0.363 (kW·hr/kg−LNG).

Example 6

A natural gas processing operation was performed using the natural gas processing plant 105 shown in FIG. 5.

The same lean gas as that used in Example 1 was used, and the sales gas and the LNG feed gas was distributed in the same manner as that in Example 4.

As conditions necessary to perform the processing, motive power of the sales gas compressor 12, motive power of the booster gas compressor 32, motive power of the propane refrigerant compressor (which is used for cooling in the second heat exchanger 25) and motive power of the fourth gas compressor 131 for the self-cooling medium are shown in Table 2.

As a result, the amount of recovered liquefied natural gas was 1.82 (MTA) and total sales of the sales gas and LNG was 1442 (MMUS$/year).

Motive power (specific power) of a compressor necessary to produce a unit weight of LNG was 0.363 (kW·hr/kg−LNG).

TABLE 2 Reference Example 4 Example 5 Example 6 Example 3 Amount of gas supplied for 1600  1600  1600  1600 sales gas (MMSCFD) Motive power of sales gas   122.5   122.5   122.5 98.0 compressor (MW) (Motive power necessary to  (14)   (17.4)  (8) (—) re-compress gas from natural gas liquefying plant) a) Motive power of booster  36   10.4   24.4 — compressor (MW) b) Motive power of compressor  8    6.2   14.4 — using propane refrigerant (MW) c) Motive power of compressor — —   32.2 — using cooling medium (MW) d) Total additional motive power  58  34  79 — (MW) e) = a) + b) + c) + d) Amount of gas supplied for 400 400 400 0 liquefied natural gas (MMSCFD) recovered Amount of    1.12    0.78    1.82 0 liquefied natural gas (million tons/year) (ton/time) f) (134) (92) (218) (—) Sales of Sales gas + LNG 1304  1237  1442  1082 (MMUS$/year) Specific power     0.430     0.363     0.363 — (kW-h/Kg-LNG) e)/f)

Example 7

A natural gas processing operation was performed using the natural gas processing plant 10 shown in FIG. 1.

The same lean gas as that used in Example 1 was used, 1200 (60%) (MMSCFD) was used as the sales gas, and 800 (40%) (MMSCFD) was used as the LNG feed gas.

As conditions necessary to perform the processing, motive power of the sales gas compressor 12, motive power of the booster gas compressor 32, and motive power of the propane refrigerant compressor (which is used for cooling in the second heat exchanger 25) are shown in Table 3.

As a result, the amount of recovered liquefied natural gas was 2.24 (MTA) and total sales of the sales gas and LNG was 1255 (MMUS$/year).

Motive power (specific power) of a compressor necessary to produce a unit weight of LNG was 0.430 (kW·hr/kg−LNG).

Example 8

A natural gas processing operation was performed using the natural gas processing plant 50 shown in FIG. 3.

The same lean gas as that used in Example 1 was used, and the sales gas and the LNG feed gas was distributed in the same manner as that in Example 7.

As conditions necessary to perform the processing, motive power of the sales gas compressor 12, motive power of the booster gas compressor 32, and motive power of the propane refrigerant compressor (which is used for cooling in the second heat exchanger 25) are shown in Table 3.

As a result, the amount of recovered liquefied natural gas was 1.56 (MTA) and total sales of the sales gas and LNG was 1120 (MMUS$/year).

Motive power (specific power) of a compressor necessary to produce a unit weight of LNG was 0.363 (kW·hr/kg−LNG).

Example 9

A natural gas processing operation was performed using the natural gas processing plant 105 shown in FIG. 5.

The same lean gas as that used in Example 1 was used, and the sales gas and the LNG feed gas was distributed in the same manner as that in Example 7.

As conditions necessary to perform the processing, motive power of the sales gas compressor 12, motive power of the booster gas compressor 32, motive power of the propane refrigerant compressor (which is used for cooling in the second heat exchanger 25) and motive power of the fourth gas compressor 131 for the self-cooling medium are shown in Table 3.

As a result, the amount of recovered liquefied natural gas was 3.64 (MTA) and total sales of the sales gas and LNG was 1533 (MMUS$/year).

Motive power (specific power) of a compressor necessary to produce a unit weight of LNG was 0.363 (kW·hr/kg−LNG).

TABLE 3 Reference Example 7 Example 8 Example 9 Example 4 Amount of gas supplied for 1200 1200 1200 1200 sales gas (MMSCFD) Motive power of sales gas   122.5   122.5   122.5 73.5 compressor (MW) (Motive power necessary to  (28)   (34.8)  (16) (—) re-compress gas from natural gas liquefying plant) a) Motive power of booster  72   20.8   48.8 — compressor (MW) b) Motive power of compressor  16   12.4   28.8 — using propane refrigerant (MW) c) Motive power of compressor — —   64.4 — using cooling medium (MW) d) Total additional motive power 116  68 158 — (MW) e) = a) + b) + c) + d) Amount of gas supplied for 800 800 800 0 liquefied natural gas (MMSCFD) recovered Amount of    2.24    1.56    3.64 0 liquefied natural gas (million tons/year) (ton/time) f) (268) (184) (436) (—) Sales of Sales gas + LNG 1255  1120  1533  811 (MMUS$/year) Specific power     0.430     0.363     0.363 — (kW-h/Kg-LNG) e)/f)

Reference Example 1

In order to recover the sales gas, the 2000 (MMSCFD) of the gas used in Example 1 was supplied to produce 100% of the sales gas.

Motive power necessary for the sales gas compressor was 122.5 (MW).

As a result, total sales of the sales gas was 1352 (MMUS$/year).

Reference Example 2

In order to recover the sales gas, the 1800 (MMSCFD) of the gas used in Example 1 was supplied to produce 100% of the sales gas.

Motive power necessary for the sales gas compressor was 110.25 (MW).

As a result, total sales of the sales gas was 1217 (MMUS$/year).

Reference Example 3

In order to recover the sales gas, the 1600 (MMSCFD) of the gas used in Example 1 was supplied to recover 100% of the sales gas.

Motive power necessary for the sales gas compressor was 98 (MW).

As a result, total sales of the sales gas was 1082 (MMUS$/year).

Reference Example 4

In order to recover the sales gas, the 1200 (MMSCFD) of the gas used in Example 1 was supplied to recover 100% of the sales gas.

Motive power necessary for the sales gas compressor was 73.5 (MW).

As a result, total sales of the sales gas was 811 (MMUS$/year).

In consideration of the results of the above-described Examples 1 to 9 and Reference Examples 1 to 4 and the results of Tables 1 to 3, it is apparent that according to the invention, LNG can be produced as a co-product in the natural gas processing plant capable of producing the sales gas and NGL as major products with feasible investment for producing LNG.

From the results of Tables 1 to 3, in Examples 1 to 9, it was confirmed that liquefied natural gas could be effectively recovered. Especially, in a case where the production of the sales gas is not fully performed, surplus motive power of the sales gas compressor can be used as motive power for boosting the gas supplied to the natural gas liquefying plant. In this manner, it becomes possible to improve efficiency of the plant.

The natural gas processing method according to the invention can be used not only in a new natural gas processing plant, but also particularly in the existing plant which produces the sales gas and NGL by simple modification and expansion of the existing plant in order to additionally produce LNG.

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stats Patent Info
Application #
US 20080163645 A1
Publish Date
07/10/2008
Document #
11968819
File Date
01/03/2008
USPTO Class
62620
Other USPTO Classes
International Class
25J3/00
Drawings
7



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