Classifications

• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
  • B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
  • B01D53/1493—Selection of liquid materials for use as absorbents
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
  • B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
  • B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
  • B01D53/1456—Removing acid components
  • B01D53/1475—Removing carbon dioxide
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
  • B01D53/26—Drying gases or vapours
  • B01D53/263—Drying gases or vapours by absorption
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
  • C10G2300/10—Feedstock materials
  • C10G2300/1025—Natural gas
• • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
  • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
  • Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
  • Y02C20/00—Capture or disposal of greenhouse gases
  • Y02C20/40—Capture or disposal of greenhouse gases of CO2

Definitions

• 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 C0 2 .
• C0 2 When the natural gas is to be condensed to LNG, C0 2 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 C0 2 . 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 H 2 0 in LNG may result in formation of ice in the heat exchangers, and too much C0 2 will result in crystallization of C0 2 either in the heat exchangers or in the liquid natural gas when the temperature becomes sufficiently low.
• MEA aqueous solution of MEA, diethanol amine (DEA) or similar chemicals.
• DEA diethanol amine
• 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.
• TEG triethylene glycol
• This process requires, however, subsequent stripping of water in several steps.
• a further disadvantage of this process is that C0 2 is not removed.
• the object of the invention was to arrive at a simple and economical process for lowering both the water and C0 2 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.
• 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.
• C0 2 the second component alkanolamines were found to be useful.
• 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 C0 2 and regenerate the absorption solution by stripping with a large amount of stripping gas (methane) containing substantially no water and C0 2 .
• the treatment with absorption solution is preferably performed at 40-80 bar and 30-50°C.
• Desorption of C0 2 from used absorption solution is preferably performed at 130-200°C.
• 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.
• this stream 1 might be mixed with recirculation stream 27 and then fed as stream 2 to ClOl.
• water and C0 2 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 C0 2 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 C0 2 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.
• the process according to the invention applies split absorption and one desorption column.
• Natural gas containing water and C0 2 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.
• column ClOl water and C0 2 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 C0 2 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.
• two desorption columns are used.
• the bottom fraction 10 from the separator V101 is fed to desorption column C102 where most of the remaining C0 2 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 C0 2 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.
• This example refers to the basic process described in Fig. 1. 100,000 Nm 3 /h of natural gas at 60 bar and 35°C and containing 7.5 mol% C0 2 is fed to column ClOl and brought in contact with an absorption solution of 340 m 3 /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 C0 2 /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 C0 2 content in the solution was thereby reduced from 0.4 mol C0 /mol MEA to 0,13 mol C0 2 /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 Nm 3 /h gas which did not contain any water or C0 2 .
• the content of water and C0 2 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 C0 2 and less than 1 ppm water as it leaves the absorption column ClOl.
• 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 C0 2 content in the solution was thereby reduced from 0.4 mol C0 2 /mol MEA to 0.21 mol C0 /mol MEA.
• 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 Nm 3 /h pre-heated gas being water and C0 2 free gas.
• the content of water and C0 2 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.
• the gas leaving column ClOl contained less than 50 ppm C0 2 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.
• 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 C0 2 content in the absorption solution was thereby reduced from 0.4 mol C0 2 /mol MEA to 0.21 mol C0 2 /mol MEA.
• 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 C0 2 .
• 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.
• water and C0 2 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.
• 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 C0 2 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 C0 2 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.

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• Chemical & Material Sciences (AREA)
• Engineering & Computer Science (AREA)
• Analytical Chemistry (AREA)
• General Chemical & Material Sciences (AREA)
• Oil, Petroleum & Natural Gas (AREA)
• Chemical Kinetics & Catalysis (AREA)
• Gas Separation By Absorption (AREA)

Applications Claiming Priority (3)

Publications (1)

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ID=19895587

Family Applications (1)

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Family Cites Families (2)

• 1992
  • 1992-11-13 NO NO924381A patent/NO176828C/no unknown
• 1993
  • 1993-11-11 CA CA002149314A patent/CA2149314A1/en not_active Abandoned
  • 1993-11-11 NL NL9320051A patent/NL9320051A/nl not_active Application Discontinuation
  • 1993-11-11 AU AU55781/94A patent/AU5578194A/en not_active Abandoned
  • 1993-11-11 GB GB9511768A patent/GB2288750B/en not_active Expired - Fee Related
  • 1993-11-11 EP EP94901073A patent/EP0668792A1/en active Pending
  • 1993-11-11 WO PCT/NO1993/000166 patent/WO1994011090A1/en not_active Application Discontinuation
• 1995
  • 1995-05-10 DK DK054095A patent/DK54095A/da not_active Application Discontinuation

Non-Patent Citations (1)

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