WO1994011090A1

WO1994011090A1 - Pre-treatment of natural gas to be condensed to liquefied natural gas (lng)

Info

Publication number: WO1994011090A1
Application number: PCT/NO1993/000166
Authority: WO
Inventors: Dag Arne Eimer
Original assignee: Norsk Hydro A.S
Priority date: 1992-11-13
Filing date: 1993-11-11
Publication date: 1994-05-26
Also published as: GB2288750A; NO176828C; NO924381D0; DK54095A; NO176828B; AU5578194A; GB9511768D0; NO924381L; NL9320051A; EP0668792A1; CA2149314A1; GB2288750B

Abstract

The present invention relates to pre-treatment of natural gas for removal of CO2 and water by means of absorption down to LNG specification regarding CO2 and H2O content. The natural gas is brought in contact with a two-component absorption solution comprising one component acting as a solvent, which can be a mixture of solvents, having high affinity for water and being compatible with the other components having the ability to react reversibly with CO2. Used absorption solution is regenerated by stripping with large amounts of inert gas, preferably natural gas, containing substantially no CO2 or H2O. Both the absorption and desorption can be performed in two stages. The two-component absorption solution comprises ethylene glycols, glycol ethers or normal methyl pyrrolidone and alkanolamines.

Description

Pre-treatment of natural gas to be condensed to liquefied natural gas (LNG)

The present invention relates to pre-treatment of natural gas to be condensed to liquefied natural gas (LNG) . The said treatment relates to removal of water and C0 from the natural gas in order to meet the specification for LNG, regarding water content and C0₂.

Removal of contaminants from natural gas is an old problem. Already in the 1920's it was known to use amines for binding C0 • In the thirties processes were developed for simultaneous removal of C0₂ and water, and also H₂S if present. This gas treatment was aimed at meeting pipeline specifications. These processes are described in US patents 2,177,068, 2,435,089, 2,518,752 and 2,547,278, and they all relate to application of diethylene glycol-monoethanol a ine (DEG-MEA) and a few per cent of water. This mixture was applicable for treatment of gas to be trans¬ ported in pipelines. The content of C0₂ in the gas could thereby be brought down to 2-2.5 mol%, while the water content would vary according to the temperature the pipeline would be exposed to. A dew point of 0-10°C was mostly used as standard.

When the natural gas is to be condensed to LNG, C0₂ is usually first removed by absorption in an aqueous solution of MEA, diethanol amine (DEA) or similar chemicals. Subsequent to this treatment water is absorbed on molecular sieves which also can be applied for final removal of C0₂. But it is costly and requires large process units to reach the required specifications for LNG by such a process, and inherent problems will arise. More than 1 ppm H₂0 in LNG may result in formation of ice in the heat exchangers, and too much C0₂ will result in crystallization of C0₂ either in the heat exchangers or in the liquid natural gas when the temperature becomes sufficiently low.

It is further known from the so-called Drizo process, US patent No. 3,349,544, to remove water by absorption in for instance triethylene glycol (TEG) to an extent that a dew point of -80°C can be attained. This process requires, however, subsequent stripping of water in several steps. A further disadvantage of this process is that C0₂ is not removed.

The object of the invention was to arrive at a simple and economical process for lowering both the water and C0₂ content of natural gas down to the respective LNG specifications. It was further desired to lower the water content to such an extent that a dew point of -80°C could be attained.

In order to arrive at an integrated process by which both C0₂ and water were removed from the natural gas, it soon became evident that the selection of absorption solution would be of great importance. In view of that known from previous attempts to purify natural gas, the inventor found that a new approach to the problem was necessary. Tests were then performed using an absorption solution having a double function and comprising two main components, one acting as a solvent which can be a mixture of solvents for removing water and the other component being compatible with the solvent and having the ability to react reversibly with C0₂.

The solvent constitutes the major part of the absorption solution, and its essential property is great affinity for water in order to obtain the required drying of the natural gas. Useful solvents will be ethylene glycols, glycol ethers and normal methyl pyrrolydone (NMP) . TEG is preferred because it can be applied at temperatures as high as 172-200°C without being degraded. For removal of C0₂ (the second component) alkanolamines were found to be useful. Also for the second component the operating temperature proved to be a selection criteria, and MEA and DEA were found to be most suitable. The ratio between the two components, solvent: alkanola ine, should be in the range of 2-1: 50-1. However, further tests showed that this ratio was not very critical.

The basic process according to the invention comprises bringing the crude natural gas in contact with the two-component absorp¬ tion solution for simultaneous removal of water and C0₂ and regenerate the absorption solution by stripping with a large amount of stripping gas (methane) containing substantially no water and C0₂.

The treatment with absorption solution is preferably performed at 40-80 bar and 30-50°C. Desorption of C0₂ from used absorption solution is preferably performed at 130-200°C.

The scope of the invention is as defined by the attached claims.

The invention is further described and explained in the following description of the figures and in the examples.

Fig. 1 shows a flow sheet of the basic process according to the invention.

Fig. 2 shows a flow sheet for a process according to the invention comprising split absorption and one desorption column. Fig. 3 shows a process according to the invention com¬ prising split absorption and two desorption columns.

The basic process shown in Fig. 1 comprises one complete absorption section. If the raw natural gas contains condensed water, this should be removed in a scrubber prior to the process described in Fig. 1.

Natural gas 1 containing water and C0 is fed to an absorption column ClOl. Optionally, this stream 1 might be mixed with recirculation stream 27 and then fed as stream 2 to ClOl. In column ClOl water and C0₂ are removed by absorption in an absorption solution 4 fed to the top of said column. Purified natural gas 3 having desired LNG specifications leaves column ClOl at its top. Used absorption solution 6 is removed from the bottom of ClOl and is heat exchanged with regenerated absorption solution 15 before the latter solution is pumped by P101 and cooled in H101 before its return to column ClOl. The used absorption solution 7 is further heated in H107 before its pressure is released over valve 30 and it is fed to the phase separator V101 where C0₂ is removed at the top as a stream 9. The bottom fraction 10 from separator V101 is heated in heat exchanger H103 and then as stream 14 fed to a desorption column C103 where the remaining C0₂ and substantially all the water are removed by means of hot stripping gas 18. The heat exchanger H103 is optional. The bottom fraction from column C103 is heat exchanged in H102 and H101 and returned to column ClOl as previously described. The used stripping gas 16 leaving column C103 at its top can be used as fuel gas 24 or 26. However, it may also be cooled with subsequent separation of water in V102 and pressurized by fan K101. This gas 22 can then be supplied to the fuel gas net 24 or being compressed in K102 and recirculated as stream 25 to the crude natural gas stream 1. A bleed 26 can be used as high pressure fuel gas. In Fig. 2 the process according to the invention applies split absorption and one desorption column. Natural gas containing water and C0₂ is fed to an absorption column ClOl. This natural gas feed might be mixed with recirculating gas 27 and then fed to the column ClOl as stream 2. In column ClOl water and C0₂ are removed by absorption in the absorption solution which is supplied as a split feed as streams 5 and 4. Purified gas leaves at the top of column ClOl. Used absorption solution 6 is removed from the bottom of column ClOl and heat exchanged with regener¬ ated absorption solutions 15 and 12 in the heat exchangers H102 , and H108 respectively, before the regenerated absorption solutions are returned to column ClOl as streams 4 and 5. The used absorption solution is further heated in H107 before its pressure is released over valve 30. It is then transferred to phase separator V101 for removal of C0 which leaves at the top as stream 9. The bottom fraction 10 from separator V101 is separated in a stream 12 which is returned to column ClOl through pump P102 and heat exchanger H106, and a stream 13 which can be heated in a heat exchanger H103 and then transferred as a stream 14 to the top of a desorption column C103 in which the remaining C0₂ and substantially all the water are removed by means of hot stripping gas 18. The bottom fraction from column C103 is returned through pipe 15 back to column ClOl. The used stripping gas 16 can be applied as fuel gas 24, 264 or 28, or cooled and separated from water as described for Fig. 1.

Fig. 3 describes a process according to the invention comprising split absorption and two desorption columns. The absorption section is basically run as shown in Fig. 2. In this embodiment of the process according to the invention two desorption columns are used. The bottom fraction 10 from the separator V101 is fed to desorption column C102 where most of the remaining C0₂ in the absorption solution is stripped by the gas supplied to the column through pipe 17 from the top of column C103. The bottom fraction 11 from column C102 is split in one stream 12 which is returned to the absorption column ClOl and a stream 13 which Optionally can be heated in heat exchanger H103 and then fed to the top of desorption column C103 where the remaining C0₂ and substantially all the water are removed by the hot stripping gas 18. The used stripping gas 16 from the top of desorption column C102 is then passed through V102 for removal of water and subsequently pressurized in fans KlOl and 102 and returned to the feed gas or alternatively used as fuel gas as explained in connection with Figs. 1 and 2.

Example 1

This example refers to the basic process described in Fig. 1. 100,000 Nm³/h of natural gas at 60 bar and 35°C and containing 7.5 mol% C0₂ is fed to column ClOl and brought in contact with an absorption solution of 340 m³/h. The absorption solution contains 2.5 M MEA and has a water content of 5 ppm (weight) and a CO_ content corresponding to 0.00001 ol C0₂/mol MEA. Used absorption solution is heated to 180°C and its pressure is released over a valve 30, whereupon it is brought to a separator V101 where the pressure is 1.2 bar. The C0₂ content in the solution was thereby reduced from 0.4 mol C0 /mol MEA to 0,13 mol C0₂/mol MEA. The temperature was reduced to 122°C during the pressure release. The solution was then preheated to 200°C in a heat exchanger H103 and thereupon fed to the desorption column C103 where it was stripped by 13,000 Nm³/h gas which did not contain any water or C0₂. The content of water and C0₂ in the absorption solution was thereby reduced down to the level stated for the absorption solution feed to the column G101.

The natural gas purified as described above contains less than 100 ppm C0₂ and less than 1 ppm water as it leaves the absorption column ClOl. Example 2

This example refers to the embodiment described in Fig. 2. Natural gas in an amount of 100,000 Nm³/h at 70 bar and 35°C and containing 6.4 mol% C0₂ was fed to the absorption column ClOl in which it was brought in contact with an absorption solution primarily consisting of TEG in an amount of 340 m³/h split in two streams 4 and 5 as shown in Fig. 2. The MEA concentration was 2.5 M in the absorption solution. In the absorption stream 4 the water content was 5 ppm (weight) and the C0₂ content cor¬ responding to 0.05 mol C0₂/mol MEA, while the absorption stream 5 had a water content of 3000 ppm (weight) and the C0₂ content corresponding to 0.21 mol/mol MEA. Used absorption solution was heated to 160°C and pressure released and then fed to separator VI01 in which the pressure was 1.2 bar. The C0₂ content in the solution was thereby reduced from 0.4 mol C0₂/mol MEA to 0.21 mol C0 /mol MEA. During the pressure release the temperature was reduced to 107°C. The solution was then split in two streams 12 and 13, where the stream 12 was cooled and pumped back to ClOl as stream 5, while stream 13 was transferred without being preheated to desorption column C103 in which it was stripped with 10,000 Nm³/h pre-heated gas being water and C0₂ free gas. The content of water and C0₂ in the absorption solution was thereby reduced to the same level as for stream 4. The liquid was cooled and pumped back to the absorption column.

When the natural gas was purified according to this embodiment of the invention, the gas leaving column ClOl contained less than 50 ppm C0₂ and 1 ppm water. A further advantage of this embodiment of the invention is that smaller amounts of stripping gas is necessary for obtaining pure LNG or it can be used the same amount of stripping gas, but less heating in H 107 and/or H 103. Example 3

This example refers to the embodiment described in Fig. 3. 100,000 Nm³/h of natural gas at a pressure of 65 bar and 35°C and having a C0₂ content of 6.9 mol% was fed to column ClOl in which it was brought in contact with an absorption solution pre¬ dominantly consisting of TEG. This solution of 340 m³/h comprises both streams 4 and 5 and it contains MEA in an amount of 2.5 M. In stream 4 the water content was 3 ppm (weight) and the C0₂ content corresponding to 0.01 mol C0₂/mol MEA, while stream 5 had a water content of 2750 ppm (weight) and a C0₂ content corres¬ ponding to 0.1 mol/mol MEA.

Used absorption solution was heated to 160°C and pressure re¬ leased over valve 30 and then fed to separator V101 in which the pressure was 1.2 bar. The C0₂ content in the absorption solution was thereby reduced from 0.4 mol C0₂/mol MEA to 0.21 mol C0₂/mol MEA. During the pressure release the temperature was reduced to 107°C. The solution was then fed to a desorption column C102 in which C0 and water were stripped by gas which had already been used as stripping gas in desorption column C103. The bottom fraction from C102 is split in two streams 12 and 13 where the stream 12 is cooled and pumped back to the absorption column ClOl as stream 5, while stream 13 without being preheated was fed to the desorption column C103 in which it was further stripped by preheated gas which did not contain any water or C0₂. The water and C0 content of the absorption solution was thereby reduced to a level as stated for stream 4. The liquid was then cooled and pumped back to the absorption column.

When the crude natural gas was treated as described in this example the gas leaving column ClOl had a maximum of 50 ppm CC_ and 1 ppm water. Thus the advantage by using two desorption columns results in less C0 and H₂0 in stream 12, especially C0₂. Accordingly a smaller ClOl unit can be applied for obtaining the required LNG specifications without increasing the amount of stripping gas.

As shown by the above examples, water and C0₂ can be removed simultaneously from natural gas by using the process according to the invention.

The desired LNG specification can also easily be met by the invention. Thus purified natural gas can also be exposed to temperatures as low as -80°C without getting serious problems with regard to ice or crystallization due to the C0₂ or water content.

The process according to the invention requires only standard equipment and smaller units than the conventional processes in which removal of the contaminants has to be performed in several steps. In fact the equipment specifications required allows it to be placed on board ships and platforms. The invention also utilizes available gas free of water and C0₂ for being used as flash gas and fuel gas on board. It is also part of this invention that the fuel gas can be recirculated to the process if it is not required as fuel gas. The flexibility of the process makes it suitable for application ashore where the requirement for space to the process equipment is less important.

The process according to the invention makes it also possible to utilize flash gas from the LNG condensation unit to purify the natural gas prior to the condensation step. This synergy effect improves the overall economy.

Claims

Pre-treatment of natural gas for removal of C0₂ and water by means of absorption down to LNG specification regarding C0 and H₂0 content, c h a r a c t e r i z e d i n t h a t the natural gas is brought in contact with a two-component absorption solution comprising one component acting as a solvent, which can be a mixture of solvents, having high affinity for water and being compatible with the other components having the ability to react reversibly with C0₂, and that used absorption solution is regenerated by stripping with large amounts of inert gas containing substantially no C0₂ or H₂0.

Pre-treatment of natural gas according to claim 1, c h a r a c t e r i z e d i n t h a t the bottom fraction from the absorption column is heated, the pressure reduced, and C0₂ removed in a separation unit prior to desorption treatment with hot stripping gas from which H 0 is removed in a condenser, whereby used stripping gas can be recycled.

Pre-treatment of natural gas according to claim 1, c h a r a c t e r i z e d i n t h a t the absorption solution is heated to 100-200°C before being pressure released in one step in which most of the C0₂ is expelled, and that the liquid solution thereafter is split in two streams, the major part being returned to the absorption column and the remaining part is stripped with gas in a subsequent desorption column before the absorption solution is returned to the upper part of the absorption column.

4. Pre-treatment of natural gas according to claim 1, c h a r a c t e r i z e d i n t h a t the two-component absorption solution comprises ethylene glycols, glycol ethers or normal methyl pyrrolidone and alkanolamines.

5. Pre-treatment of natural gas according to claim 1, c h a r a c t e r i z e d i n t h a t the inert stripping gas is reheated flash gas from the la stage of a LNG condensation unit.

6. Pre-treatment of natural gas according to claim 1, c h a r a c t e r i z e d i n t h a t the main constituents of the absorption solution are triethylene glycol and monoethanol amine and/or diethanol amine.

7. Pre-treatment according to claim 1, c h a r a c t e r i z e d i n t h a t the used absorption solution is heated to at least 150°C prior to desorption.

8. Pre-treatment according to claim 1, c h a r a c t e r i z e d i n t h a t the desorption of the used absorption solution is performed in three steps and that most of the C0₂ is removed in a first step by flashing before the solution is partially stripped of water using gas and that part of the bottom fraction from the first desorption column is returned to the lower part of the absorption column with the rest being fed to a second desorption column, and that the bottom fraction from the second desorption column being essenti¬ ally free of water, is returned to the upper part of the absorption column. AMENDED CLAIMS

[received by the International Bureau on 10 March 1994 (10.03.94); original claim 1 amended; other claims unchanged (1 page)]

Pre-treatment of natural gas for removal of C0₂ and water by means of absorption down to LNG specification regarding C0₂ and H₂0 content, c h a r a c t e r i z e d i n t h a t the natural gas is brought in contact with a two-component absorption solution substantially free of water and comprising one component acting as a solvent, which can be a mixture of solvents, having high affinity for water and being compatible with the other components having the ability to react reversibly with C0₂ , and that used absorption solution is regenerated as known per se by stripping with large amounts of inert gas containing substantially no C0₂ or H₂0.

Pre-treatment of natural gas according to claim 1, c h a r a c t e r i z e d i n t h a t the bottom fraction from the absorption column is heated, the pressure reduced, and C0₂ removed in a separation unit prior to desorption treatment with hot stripping gas from which H₂0 is removed in a condenser, whereby used stripping gas can be recycled.