US20070056317A1 - Removing contaminants from natural gas - Google Patents
Removing contaminants from natural gas Download PDFInfo
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- US20070056317A1 US20070056317A1 US11/556,869 US55686906A US2007056317A1 US 20070056317 A1 US20070056317 A1 US 20070056317A1 US 55686906 A US55686906 A US 55686906A US 2007056317 A1 US2007056317 A1 US 2007056317A1
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- Prior art keywords
- vessel
- gas
- natural gas
- temperature
- feed stream
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- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 title claims abstract description 91
- 239000003345 natural gas Substances 0.000 title claims abstract description 47
- 239000000356 contaminant Substances 0.000 title claims abstract description 17
- 239000007789 gas Substances 0.000 claims abstract description 55
- 239000007788 liquid Substances 0.000 claims abstract description 55
- 238000000034 method Methods 0.000 claims abstract description 33
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 25
- 239000007787 solid Substances 0.000 claims abstract description 22
- 238000001816 cooling Methods 0.000 claims abstract description 18
- 150000004677 hydrates Chemical class 0.000 claims abstract description 16
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 description 34
- 230000015572 biosynthetic process Effects 0.000 description 11
- 229930195733 hydrocarbon Natural products 0.000 description 11
- 150000002430 hydrocarbons Chemical class 0.000 description 11
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 description 10
- 239000004215 Carbon black (E152) Substances 0.000 description 7
- 239000001569 carbon dioxide Substances 0.000 description 7
- 229910002092 carbon dioxide Inorganic materials 0.000 description 7
- 239000007921 spray Substances 0.000 description 7
- PNEYBMLMFCGWSK-UHFFFAOYSA-N Alumina Chemical compound [O-2].[O-2].[O-2].[Al+3].[Al+3] PNEYBMLMFCGWSK-UHFFFAOYSA-N 0.000 description 4
- 238000011144 upstream manufacturing Methods 0.000 description 4
- UHOVQNZJYSORNB-UHFFFAOYSA-N Benzene Chemical compound C1=CC=CC=C1 UHOVQNZJYSORNB-UHFFFAOYSA-N 0.000 description 3
- YXFVVABEGXRONW-UHFFFAOYSA-N Toluene Chemical compound CC1=CC=CC=C1 YXFVVABEGXRONW-UHFFFAOYSA-N 0.000 description 3
- 230000018044 dehydration Effects 0.000 description 3
- 238000006297 dehydration reaction Methods 0.000 description 3
- NMJORVOYSJLJGU-UHFFFAOYSA-N methane clathrate Chemical compound C.C.C.C.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O NMJORVOYSJLJGU-UHFFFAOYSA-N 0.000 description 3
- 238000000926 separation method Methods 0.000 description 3
- 238000001179 sorption measurement Methods 0.000 description 3
- YNQLUTRBYVCPMQ-UHFFFAOYSA-N Ethylbenzene Chemical compound CCC1=CC=CC=C1 YNQLUTRBYVCPMQ-UHFFFAOYSA-N 0.000 description 2
- LYCAIKOWRPUZTN-UHFFFAOYSA-N Ethylene glycol Chemical compound OCCO LYCAIKOWRPUZTN-UHFFFAOYSA-N 0.000 description 2
- ATUOYWHBWRKTHZ-UHFFFAOYSA-N Propane Chemical compound CCC ATUOYWHBWRKTHZ-UHFFFAOYSA-N 0.000 description 2
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 description 2
- RAHZWNYVWXNFOC-UHFFFAOYSA-N Sulphur dioxide Chemical compound O=S=O RAHZWNYVWXNFOC-UHFFFAOYSA-N 0.000 description 2
- 238000010521 absorption reaction Methods 0.000 description 2
- 230000000903 blocking effect Effects 0.000 description 2
- 238000010586 diagram Methods 0.000 description 2
- 230000000694 effects Effects 0.000 description 2
- 239000000499 gel Substances 0.000 description 2
- 230000005484 gravity Effects 0.000 description 2
- 238000010438 heat treatment Methods 0.000 description 2
- 239000003949 liquefied natural gas Substances 0.000 description 2
- 238000004519 manufacturing process Methods 0.000 description 2
- 238000002844 melting Methods 0.000 description 2
- 230000008018 melting Effects 0.000 description 2
- 239000000203 mixture Substances 0.000 description 2
- 239000002808 molecular sieve Substances 0.000 description 2
- 238000005057 refrigeration Methods 0.000 description 2
- URGAHOPLAPQHLN-UHFFFAOYSA-N sodium aluminosilicate Chemical compound [Na+].[Al+3].[O-][Si]([O-])=O.[O-][Si]([O-])=O URGAHOPLAPQHLN-UHFFFAOYSA-N 0.000 description 2
- AKEJUJNQAAGONA-UHFFFAOYSA-N sulfur trioxide Chemical compound O=S(=O)=O AKEJUJNQAAGONA-UHFFFAOYSA-N 0.000 description 2
- 230000007704 transition Effects 0.000 description 2
- CTQNGGLPUBDAKN-UHFFFAOYSA-N O-Xylene Chemical compound CC1=CC=CC=C1C CTQNGGLPUBDAKN-UHFFFAOYSA-N 0.000 description 1
- 150000001412 amines Chemical class 0.000 description 1
- 239000003795 chemical substances by application Substances 0.000 description 1
- 238000002485 combustion reaction Methods 0.000 description 1
- 235000009508 confectionery Nutrition 0.000 description 1
- 239000013078 crystal Substances 0.000 description 1
- WGCNASOHLSPBMP-UHFFFAOYSA-N hydroxyacetaldehyde Natural products OCC=O WGCNASOHLSPBMP-UHFFFAOYSA-N 0.000 description 1
- 230000010354 integration Effects 0.000 description 1
- 239000003915 liquefied petroleum gas Substances 0.000 description 1
- 239000000463 material Substances 0.000 description 1
- 229910052751 metal Inorganic materials 0.000 description 1
- 239000002184 metal Substances 0.000 description 1
- 150000002739 metals Chemical class 0.000 description 1
- 238000002156 mixing Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- -1 natural gas hydrates Chemical class 0.000 description 1
- 239000008239 natural water Substances 0.000 description 1
- 238000005457 optimization Methods 0.000 description 1
- 230000002028 premature Effects 0.000 description 1
- 239000001294 propane Substances 0.000 description 1
- 239000003507 refrigerant Substances 0.000 description 1
- 239000000377 silicon dioxide Substances 0.000 description 1
- 238000003860 storage Methods 0.000 description 1
- 239000004291 sulphur dioxide Substances 0.000 description 1
- 235000010269 sulphur dioxide Nutrition 0.000 description 1
- 231100000331 toxic Toxicity 0.000 description 1
- 230000002588 toxic effect Effects 0.000 description 1
- 239000008096 xylene Substances 0.000 description 1
Images
Classifications
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- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
- F25J3/06—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by partial condensation
- F25J3/0605—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by partial condensation characterised by the feed stream
- F25J3/061—Natural gas or substitute natural gas
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
- C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
- C10L3/10—Working-up natural gas or synthetic natural gas
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
- C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
- C10L3/10—Working-up natural gas or synthetic natural gas
- C10L3/101—Removal of contaminants
- C10L3/102—Removal of contaminants of acid contaminants
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
- F25J3/06—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by partial condensation
- F25J3/063—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by partial condensation characterised by the separated product stream
- F25J3/0635—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by partial condensation characterised by the separated product stream separation of CnHm with 1 carbon atom or more
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
- F25J3/06—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by partial condensation
- F25J3/063—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by partial condensation characterised by the separated product stream
- F25J3/067—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by partial condensation characterised by the separated product stream separation of carbon dioxide
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2205/00—Processes or apparatus using other separation and/or other processing means
- F25J2205/20—Processes or apparatus using other separation and/or other processing means using solidification of components
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2205/00—Processes or apparatus using other separation and/or other processing means
- F25J2205/30—Processes or apparatus using other separation and/or other processing means using a washing, e.g. "scrubbing" or bubble column for purification purposes
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- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2215/00—Processes characterised by the type or other details of the product stream
- F25J2215/04—Recovery of liquid products
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2220/00—Processes or apparatus involving steps for the removal of impurities
- F25J2220/60—Separating impurities from natural gas, e.g. mercury, cyclic hydrocarbons
- F25J2220/64—Separating heavy hydrocarbons, e.g. NGL, LPG, C4+ hydrocarbons or heavy condensates in general
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- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2220/00—Processes or apparatus involving steps for the removal of impurities
- F25J2220/60—Separating impurities from natural gas, e.g. mercury, cyclic hydrocarbons
- F25J2220/66—Separating acid gases, e.g. CO2, SO2, H2S or RSH
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- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2220/00—Processes or apparatus involving steps for the removal of impurities
- F25J2220/60—Separating impurities from natural gas, e.g. mercury, cyclic hydrocarbons
- F25J2220/68—Separating water or hydrates
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- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2245/00—Processes or apparatus involving steps for recycling of process streams
- F25J2245/02—Recycle of a stream in general, e.g. a by-pass stream
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- 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 a process for removing a contaminant from a natural gas feed stream.
- Natural gas from either production reservoirs or storage reservoirs typically contains water, as well as other species, which form solids during the liquefaction to produce liquefied natural gas (LNG). It is common practice for the natural gas to be subjected to a dehydration process prior to the liquefaction. Water is removed to prevent hydrate formation occurring in pipelines and heat exchangers upstream of the liquefaction vessel.
- LNG liquefied natural gas
- solid hydrates may form in pipe work, heat exchangers and/or the liquefaction vessel.
- the hydrates are stable solids comprising water and natural gas having the outward appearance of ice, with the natural gas stored within the crystal lattice of the hydrate.
- Methods of dehydrating natural gas feed streams include absorption of water in glycol or adsorption of the water using a solid such as hydrated aluminium oxide, silica gels, silica-alumina gels and molecular sieves.
- Natural gas also typically contains sour species, such as hydrogen sulphide (H 2 S) and carbon dioxide (CO 2 ). Such a natural gas is classified as “sour gas”. When the H 2 S and CO 2 have been removed from the natural gas feed stream, the gas is then classified as “sweet”. The term “sour gas” is applied to natural gases including H 2 S because of the bad odour that is emitted even at low concentrations from an unsweetened gas. H 2 S is a contaminant of natural gas that must be removed to satisfy legal requirements, as H 2 S and its combustion products of sulphur dioxide and sulphur trioxide are also toxic. Furthermore, H 2 S is corrosive to most metals normally associated with gas pipelines so that processing and handling of a sour gas may lead to premature failure of such systems.
- sour species such as hydrogen sulphide (H 2 S) and carbon dioxide (CO 2 ).
- Gas sweetening processes typically include adsorption using solid adsorption processes or absorption using amine processes, molecular sieves, etc. Existing dehydration and gas sweetening processes are extremely complex and expensive.
- a process for removing contaminants from a natural gas feed stream containing water comprising the steps of: cooling the natural gas feed stream in a first vessel to a first operating temperature at which hydrates are formed; and removing from the first vessel a stream of dehydrated gas.
- FIG. 1 is a schematic process flow diagram of one embodiment of the invention.
- FIG. 2 is a schematic process flow diagram of a further embodiment of the invention.
- the present invention represents an improvement on the process and device discussed in International patent application publication No. 03/062 725.
- Contaminants from a natural gas feed stream is removed by forming a solid of the contaminant and suitably subsequently melting the solid contaminant.
- one embodiment of the present invention relates to a process for dehydrating a natural gas feed stream.
- one embodiment of the present invention relates to a process for sweetening the natural gas feed stream.
- the process for removing contaminants from a natural gas feed stream including water comprises the steps of cooling the natural gas feed stream in a first vessel to a first operating temperature at which hydrates are formed; and removing from the first vessel a stream of dehydrated gas.
- An essential feature of the process of the present invention is that on purpose hydrates are formed in order to remove water. Normally formation of hydrates is prevented.
- the process according to the present invention suitably further comprises the steps of cooling the dehydrated gas in a second vessel to a second operating temperature at which solids of the sour species are formed or at which the sour species dissolve in a liquid; and removing from the second vessel a stream of dehydrated sweetened gas.
- operating temperature is used to refer to a temperature below the solid/liquid transition temperature for the contaminant at a given pressure of operation of the first or second vessel.
- a “warm” liquid stream can be any compatible stream of liquid having a temperature above the solid/liquid transition temperature of the contaminant for a given pressure of operation of the first or second vessel.
- the warm liquid stream has thus a temperature that is sufficiently high to cause melting of the solids of the contaminant.
- the warm liquid may or may not take the contaminant fully into solution.
- FIG. 1 shows an apparatus 10 for carrying out the process of the present invention.
- the apparatus 10 comprises a first vessel 12 .
- the contaminant removed in the first vessel 12 is water and thus the gas exiting the first vessel 12 is dry. Also heavy hydrocarbons are removed as a consequence of this process, and thus the gas stream exiting the first vessel 12 is dew pointed for hydrocarbons to an extent determined by the conditions in the first vessel 12 .
- the water dew point of the gas exiting the first vessel 12 is lower than its equilibrium dew point due to the formation of hydrates.
- wet feed gas from a wellhead is fed through conduit 15 to a first flash tank 16 in which condensate is separated from the feed gas.
- the pressure and temperature conditions within the first flash tank 16 would typically be in the order of 75 to 130 bar and between 25 and 40 degrees C. (about 5 to 10 degrees C. above the hydrate formation temperature).
- the condensate liquid stream exiting the first flash vessel 16 through conduit 17 is “a warm liquid” as defined above.
- the condensate consists of liquid hydrocarbons that are produced together with natural gas.
- the gas stream separated from the sour wet feed gas in the first flash tank 16 enters the first vessel 12 via wet sour gas feed stream inlet 20 .
- An intermediate heat exchanger 22 may be used to cool the wet sour gas between the first flash tank 16 and the first vessel 12 .
- the intermediate heat exchanger 22 drops the temperature of the wet sour gas to a temperature just above the hydrate formation temperature for the particular pressure of this feed stream.
- the hydrate formation temperature for the particular pressure of the feed stream is the maximum value of the first operating temperature, which is the operating temperature in the first vessel 12 .
- the wet gas feed stream fed to the first vessel 12 is expanded using a Joule-Thompson valve 24 or other suitable expansion means such as a turbo expander to further cool the stream as it enters the first vessel 12 .
- the Joule-Thompson valve 24 may alternatively define the inlet 20 to the first vessel 12 .
- the gas pressure-temperature conditions within the vessel 12 allow hydrates to form.
- the necessary degree of cooling is achieved by the degree of expansion of the wet sour gas feed stream through the Joule-Thompson valve 24 .
- the first operating temperature and the pressure in the first vessel 12 are maintained at a level whereby hydrates are formed.
- the natural gas feed stream entering downstream of the Joule-Thompson valve 24 into the first vessel 12 is at the first operating temperature.
- the first operating temperature to which the feed gas in the first vessel 12 is cooled is below the temperature at which hydrates are formed but above the temperature at which solids of sour species, such as H 2 S and CO 2 , are formed. This is done to produce hydrates and to prevent the formation of solids of sour species in the first vessel 12 .
- dry sour gas exiting the first vessel 12 would have a nominal pressure of 10 to 30 bar lower than the pressure upstream of the expansion device 24 and a temperature of 10 to 25 degrees C. lower than the temperature just upstream of the expansion device 24 .
- dry gas is used to refer to water-free gas.
- a hydrate-containing liquid stream is removed from the first vessel 12 via water condensate outlet 28 , and passed through conduit 29 to a separator 30 .
- the water is separated from the condensate in the water condensate separator 30 .
- Such a separator is for example a baffled gravity separation unit. As water is heavier than the condensate, any suitable gravity separation techniques may be used.
- the separated condensate is removed through conduit 31 and the separated water is removed through conduit 33 .
- the natural gas feed stream entering into the first vessel 12 was cooled to the first operating temperature.
- the natural gas feed stream can be cooled using one or more sprays of a sub-cooled liquid introduced via sub-cooled liquid inlet 26 .
- the natural gas feed stream is cooled by both the Joule-Thompson valve 24 and the sub-cooled liquid supplied through inlet 26 .
- the natural gas feed stream can enter into the first vessel 12 at a temperature that is at or above the hydrate-formation temperature.
- the sub-cooled liquid inlet 26 should be located in the first vessel 12 above the inlet 20 of the wet sour gas feed stream.
- the sub-cooled liquid inlet 26 is a plurality of spray nozzles.
- the particular sub-cooled liquid is condensate recycled from the process and sprayed into the first vessel 12 . Sprays are used in order to maximise the contact area of the sub-cooled liquid and the gas and thus the cooling effect of contact of the sub-cooled liquid with the wet-sour gas.
- the dry sour gas at a pressure of 10 to 30 bar lower than the pressure upstream of the expansion device 24 and at the operating temperature of the first vessel 12 is directed via second heat exchanger 36 in conduit 35 to a second flash tank 40 . It is cooled in the second heat exchanger 36 to form a two-phase mixture of gas and condensate at a temperature higher than ⁇ 56 degrees C. Not shown is that additional cooling may be provided by indirect heat exchange with a refrigerant that is circulated through an external refrigeration cycle, for example a propane refrigeration cycle. In the second flash tank 40 , condensate is separated from the dry sour gas stream.
- the liquid stream exits the second flash tank 40 via liquid outlet 42 and is sufficiently cooled to satisfy the criteria of a sub-cooled liquid that may be fed to the sub-cooled liquid inlet 26 of the first vessel 12 .
- the sub-cooled liquid is supplied through conduit 43 , provided with a pump 44 to the sub-cooled liquid inlet 26 .
- Conduit 45 may comprise a Joule-Thompson valve 48 .
- the present invention relates to dehydrating natural gas by forming hydrates.
- the condensate present in the lower portion of the first vessel 12 is preferably heated. This is suitably done by introducing a warm liquid into the first vessel 12 below the level at which the feed stream is introduced.
- a portion of the stream of warm condensate separated in the first flash tank 16 is fed through conduit 17 and inlet 18 to the first vessel 12 .
- the warm condensate is sufficiently warm to liquefy hydrate formed in the first region of the first vessel 12 .
- the gas trapped in the hydrate lattice is liberated and the water goes into solution with the condensate.
- at least a portion of the condensate separated in the water/condensate separator 30 can be recycled for use as the warm liquid used for heating the solids of the freezable species in the first vessel 12 through conduit 37 (after heating, not shown).
- Any gas present within the water condensate separator may be recycled to the first vessel 12 .
- a portion of the gas separated in the water/condensate separator 30 may be recycled to the wet sour gas feed stream entering the first vessel 12 via inlet 20 .
- the liquid that is sprayed into the first vessel through inlets 26 is a natural gas liquid, which natural gas liquid is a mixture of C 2 , liquefied petroleum gas components, C 3 and C 4 and C 5 +hydrocarbon components.
- the warm liquid that is introduced into the first vessel through inlet 18 is also a natural gas liquid.
- FIG. 2 showing a further embodiment of the present invention.
- dehydrated gas is treated to remove sour components from it.
- the dehydration process is discussed with reference to FIG. 1 , and will not be repeated here. Parts having the same function as parts shown in FIG. 1 get the same reference numeral.
- the dry sour gas exits the second flash tank 40 via gas outlet 47 and is fed to a second vessel 14 via dry sour gas inlet 46 .
- the dry sour gas being fed to the second vessel 14 may be expanded through a Joule-Thompson valve 48 or other suitable expansion means, such as a turbo expander, in order to further cool the gas.
- the Joule-Thompson valve may define the dry sour gas inlet 46 .
- the temperature of the dry gas entering into the second vessel 14 is at a second operating temperature.
- the second operating temperature is the maximum temperature at which solids of the sour species are formed or the temperature at which the sour species dissolve in a liquid.
- the gas exiting the second vessel 14 via outlet 62 is dehydrated and sweetened.
- the dry sweetened gas would typically be at a pressure of between 20 and 50 bar and a temperature of not lower than ⁇ 85.degree. C.
- This product stream of sweetened dry gas is typically transported to the end user at ambient temperature.
- the product stream of dry sweetened gas can be further cooled by allowing the gas to expand in expansion device 63 , and the further cooled dry sweetened gas is used in one or more of the heat exchangers 38 , 36 or 22 to effect cooling of one or more of the other process streams within the apparatus 10 .
- the temperature to which the dry gas is cooled in heat exchanger 36 is greater than that at which the solids of the sour species form for the given line pressure.
- the dry sour gas was cooled to the second operating temperature by allowing the gas to expand in Joule-Thompson valve 48 .
- the dry sour gas can be cooled using one or more sprays of a sub-cooled liquid supplied through inlet 49 .
- the natural gas feed stream is cooled by both the Joule-Thompson valve 48 and the sub-cooled liquid supplied through inlet 49 .
- the dry gas can enter into the second vessel 14 at a temperature that is at or above the temperature at which solids of the sour species are formed or the temperature at which the sour species dissolve in a liquid.
- the sub-cooled liquid inlet 49 should be located in the second vessel 14 above the dry sour gas inlet 46 .
- the sub-cooled liquid inlet 49 is a plurality of spray nozzles.
- the temperature and pressure conditions in the second vessel 14 are adjusted so as to form solids of the freezable species.
- the temperature-pressure conditions need only be adjusted to form solids of hydrogen sulphide (H.sub.2S) and carbon dioxide (CO.sub.2).
- the process conditions within the second vessel are sufficient to cause the formation of solids of the freezable species of other hydrocarbons such as benzene, toluene, ethylbenzene and xylene.
- the sub-cooled liquid is part of the liquid passing through conduit 43 .
- the liquid is passed through conduit 50 to the heat exchanger 38 where it is cooled by indirect heat exchange with dry sweetened gas.
- the dry sweetened gas is then passed through conduit 65 to heat exchanger 36 for cooling the dry sour gas from the first vessel 12 .
- the dry sweetened gas is then fed to the intermediate heat exchanger 22 and from there to an end user (not shown).
- the concentration of C 2 -C 4 hydrocarbon components in the liquid should be in the range of from 0.5 to 1.5 mol per mol of CO 2 in the feed gas.
- the liquid in the second vessel 14 is the liquid sprayed in the vessel through the inlet 49 .
- the concentration of C 2 -C 4 hydrocarbon components in the sub-cooled liquid should be in the specified range. It will be understood that if the concentration of C 2 -C 4 hydrocarbon components in the liquid stream in conduit 50 is too low, additional C 2 -C 4 hydrocarbon components can be added to this stream.
- the condensate present in the lower portion of the second vessel 14 is preferably heated. This is suitably done by introducing a warm liquid through warm condensate inlet 56 into the second vessel 14 below the level at which the feed stream is introduced.
- a suitable liquid is liquid passing through conduit 50 .
- liquid passing through conduit 31 can be used.
- part of the hydrocarbon liquid stream leaving the second vessel 14 through outlet 52 can be recycled to inlet 26 of the first vessel 12 .
- a separation vessel (not shown) is used to separate a stream of liquid enriched in sour species from the hydrocarbon stream that is recycled.
Abstract
A process for removing contaminants from a natural gas feed stream including water and sour species is provided, which process comprises the steps of cooling the natural gas feed stream in a first vessel (12) to a first operating temperature at which hydrates are formed and removing from the first vessel (12) a stream of dehydrated gas (34); and cooling the dehydrated gas in a second vessel (14) to a second operating temperature at which solids of the sour species are formed or at which the sour species dissolve in a liquid and removing from the second vessel (14) a stream of dehydrated sweetened gas (62).
Description
- This application claims priority to co-pending U.S. patent application having Ser. No. 10/772,621, filed Feb. 5, 2004, which claims priority to Australian patent application having serial number 2003900534, filed Feb. 7, 2003. Co-pending U.S. application having Ser. No. 10/772,621 is herein incorporated by reference in its entirety.
- The present invention relates to a process for removing a contaminant from a natural gas feed stream.
- Natural gas from either production reservoirs or storage reservoirs typically contains water, as well as other species, which form solids during the liquefaction to produce liquefied natural gas (LNG). It is common practice for the natural gas to be subjected to a dehydration process prior to the liquefaction. Water is removed to prevent hydrate formation occurring in pipelines and heat exchangers upstream of the liquefaction vessel.
- If water is not removed, solid hydrates may form in pipe work, heat exchangers and/or the liquefaction vessel. The hydrates are stable solids comprising water and natural gas having the outward appearance of ice, with the natural gas stored within the crystal lattice of the hydrate.
- The formation of natural gas hydrates was historically seen as an undesirable result that should be avoided. However, processes have been developed to encourage natural gas hydrate formation such as International patent applications No. 01/00 755 and No. 01/12 758. In the first of these International patent applications, a method and apparatus is described whereby natural gas and water are combined in the presence of an agent adapted to reduce the natural gas water interfacial tension to encourage natural gas hydrate formation. In the second of these International patent applications, a production plant is described, including a convoluted flow path to cause mixing of water and natural gas as a first step prior to reducing the temperature to produce natural gas hydrate.
- Methods of dehydrating natural gas feed streams include absorption of water in glycol or adsorption of the water using a solid such as hydrated aluminium oxide, silica gels, silica-alumina gels and molecular sieves.
- Natural gas also typically contains sour species, such as hydrogen sulphide (H2S) and carbon dioxide (CO2). Such a natural gas is classified as “sour gas”. When the H2S and CO2 have been removed from the natural gas feed stream, the gas is then classified as “sweet”. The term “sour gas” is applied to natural gases including H2S because of the bad odour that is emitted even at low concentrations from an unsweetened gas. H2S is a contaminant of natural gas that must be removed to satisfy legal requirements, as H2S and its combustion products of sulphur dioxide and sulphur trioxide are also toxic. Furthermore, H2S is corrosive to most metals normally associated with gas pipelines so that processing and handling of a sour gas may lead to premature failure of such systems.
- Gas sweetening processes typically include adsorption using solid adsorption processes or absorption using amine processes, molecular sieves, etc. Existing dehydration and gas sweetening processes are extremely complex and expensive.
- A process for removing contaminants from a natural gas feed stream containing water is provided comprising the steps of: cooling the natural gas feed stream in a first vessel to a first operating temperature at which hydrates are formed; and removing from the first vessel a stream of dehydrated gas.
-
FIG. 1 is a schematic process flow diagram of one embodiment of the invention. -
FIG. 2 is a schematic process flow diagram of a further embodiment of the invention. - The present invention represents an improvement on the process and device discussed in International patent application publication No. 03/062 725.
- Contaminants from a natural gas feed stream is removed by forming a solid of the contaminant and suitably subsequently melting the solid contaminant.
- When the contaminant is water, one embodiment of the present invention relates to a process for dehydrating a natural gas feed stream.
- When the contaminant is a sour species, for example hydrogen sulphide or carbon dioxide, one embodiment of the present invention relates to a process for sweetening the natural gas feed stream.
- In another embodiment of the present invention relates to a process for sequentially dehydrating and sweetening the natural gas feed stream.
- To this end the process for removing contaminants from a natural gas feed stream including water according to the present invention comprises the steps of cooling the natural gas feed stream in a first vessel to a first operating temperature at which hydrates are formed; and removing from the first vessel a stream of dehydrated gas.
- An essential feature of the process of the present invention is that on purpose hydrates are formed in order to remove water. Normally formation of hydrates is prevented.
- When the natural gas feed stream further includes sour species, the process according to the present invention suitably further comprises the steps of cooling the dehydrated gas in a second vessel to a second operating temperature at which solids of the sour species are formed or at which the sour species dissolve in a liquid; and removing from the second vessel a stream of dehydrated sweetened gas.
- The term “operating temperature” is used to refer to a temperature below the solid/liquid transition temperature for the contaminant at a given pressure of operation of the first or second vessel.
- In this specification a “warm” liquid stream can be any compatible stream of liquid having a temperature above the solid/liquid transition temperature of the contaminant for a given pressure of operation of the first or second vessel. The warm liquid stream has thus a temperature that is sufficiently high to cause melting of the solids of the contaminant. The warm liquid may or may not take the contaminant fully into solution.
- The invention will now be described in more detail with reference to the accompanying drawings.
- Reference is now made to
FIG. 1 .FIG. 1 shows anapparatus 10 for carrying out the process of the present invention. Theapparatus 10 comprises afirst vessel 12. The contaminant removed in thefirst vessel 12 is water and thus the gas exiting thefirst vessel 12 is dry. Also heavy hydrocarbons are removed as a consequence of this process, and thus the gas stream exiting thefirst vessel 12 is dew pointed for hydrocarbons to an extent determined by the conditions in thefirst vessel 12. The water dew point of the gas exiting thefirst vessel 12, however, is lower than its equilibrium dew point due to the formation of hydrates. - In the embodiment as illustrated in
FIG. 1 , wet feed gas from a wellhead is fed throughconduit 15 to afirst flash tank 16 in which condensate is separated from the feed gas. The pressure and temperature conditions within thefirst flash tank 16 would typically be in the order of 75 to 130 bar and between 25 and 40 degrees C. (about 5 to 10 degrees C. above the hydrate formation temperature). The condensate liquid stream exiting thefirst flash vessel 16 throughconduit 17 is “a warm liquid” as defined above. The condensate consists of liquid hydrocarbons that are produced together with natural gas. The gas stream separated from the sour wet feed gas in thefirst flash tank 16 enters thefirst vessel 12 via wet sour gasfeed stream inlet 20. Anintermediate heat exchanger 22 may be used to cool the wet sour gas between thefirst flash tank 16 and thefirst vessel 12. Theintermediate heat exchanger 22 drops the temperature of the wet sour gas to a temperature just above the hydrate formation temperature for the particular pressure of this feed stream. The hydrate formation temperature for the particular pressure of the feed stream is the maximum value of the first operating temperature, which is the operating temperature in thefirst vessel 12. - The wet gas feed stream fed to the
first vessel 12 is expanded using a Joule-Thompsonvalve 24 or other suitable expansion means such as a turbo expander to further cool the stream as it enters thefirst vessel 12. The Joule-Thompsonvalve 24 may alternatively define theinlet 20 to thefirst vessel 12. Upon expansion of the wet sour gas feed stream into thefirst vessel 12, the gas pressure-temperature conditions within thevessel 12 allow hydrates to form. The necessary degree of cooling is achieved by the degree of expansion of the wet sour gas feed stream through the Joule-Thompsonvalve 24. - The first operating temperature and the pressure in the
first vessel 12 are maintained at a level whereby hydrates are formed. The natural gas feed stream entering downstream of the Joule-Thompson valve 24 into thefirst vessel 12 is at the first operating temperature. - If the natural gas feed stream also contains sour species, the first operating temperature to which the feed gas in the
first vessel 12 is cooled is below the temperature at which hydrates are formed but above the temperature at which solids of sour species, such as H2S and CO2, are formed. This is done to produce hydrates and to prevent the formation of solids of sour species in thefirst vessel 12. - Dry sour gas exits the
first vessel 12 via drysour gas outlet 34. Typically the dry sour gas exiting thefirst vessel 12 would have a nominal pressure of 10 to 30 bar lower than the pressure upstream of theexpansion device 24 and a temperature of 10 to 25 degrees C. lower than the temperature just upstream of theexpansion device 24. The term “dry gas” is used to refer to water-free gas. - A hydrate-containing liquid stream is removed from the
first vessel 12 viawater condensate outlet 28, and passed throughconduit 29 to aseparator 30. The water is separated from the condensate in thewater condensate separator 30. Such a separator is for example a baffled gravity separation unit. As water is heavier than the condensate, any suitable gravity separation techniques may be used. The separated condensate is removed throughconduit 31 and the separated water is removed throughconduit 33. - The natural gas feed stream entering into the
first vessel 12 was cooled to the first operating temperature. Alternatively, the natural gas feed stream can be cooled using one or more sprays of a sub-cooled liquid introduced via sub-cooledliquid inlet 26. In a further alternative embodiment, the natural gas feed stream is cooled by both the Joule-Thompson valve 24 and the sub-cooled liquid supplied throughinlet 26. In case of spray cooling, the natural gas feed stream can enter into thefirst vessel 12 at a temperature that is at or above the hydrate-formation temperature. - The sub-cooled
liquid inlet 26 should be located in thefirst vessel 12 above theinlet 20 of the wet sour gas feed stream. In the illustrated embodiment, the sub-cooledliquid inlet 26 is a plurality of spray nozzles. The particular sub-cooled liquid is condensate recycled from the process and sprayed into thefirst vessel 12. Sprays are used in order to maximise the contact area of the sub-cooled liquid and the gas and thus the cooling effect of contact of the sub-cooled liquid with the wet-sour gas. - The dry sour gas at a pressure of 10 to 30 bar lower than the pressure upstream of the
expansion device 24 and at the operating temperature of thefirst vessel 12 is directed viasecond heat exchanger 36 inconduit 35 to asecond flash tank 40. It is cooled in thesecond heat exchanger 36 to form a two-phase mixture of gas and condensate at a temperature higher than −56 degrees C. Not shown is that additional cooling may be provided by indirect heat exchange with a refrigerant that is circulated through an external refrigeration cycle, for example a propane refrigeration cycle. In thesecond flash tank 40, condensate is separated from the dry sour gas stream. The liquid stream exits thesecond flash tank 40 vialiquid outlet 42 and is sufficiently cooled to satisfy the criteria of a sub-cooled liquid that may be fed to the sub-cooledliquid inlet 26 of thefirst vessel 12. The sub-cooled liquid is supplied throughconduit 43, provided with apump 44 to the sub-cooledliquid inlet 26. - The dry sour gas exits the
second flash tank 40 viagas outlet 47 and is fed throughconduit 45 to theintermediate heat exchanger 22 and from there to an end user (not shown).Conduit 45 may comprise a Joule-Thompson valve 48. - As observed earlier, the present invention relates to dehydrating natural gas by forming hydrates. To prevent hydrates from blocking
outlet 28 andconduit 29, the condensate present in the lower portion of thefirst vessel 12 is preferably heated. This is suitably done by introducing a warm liquid into thefirst vessel 12 below the level at which the feed stream is introduced. - A portion of the stream of warm condensate separated in the
first flash tank 16 is fed throughconduit 17 andinlet 18 to thefirst vessel 12. The warm condensate is sufficiently warm to liquefy hydrate formed in the first region of thefirst vessel 12. As the hydrates melt, the gas trapped in the hydrate lattice is liberated and the water goes into solution with the condensate. In addition at least a portion of the condensate separated in the water/condensate separator 30 can be recycled for use as the warm liquid used for heating the solids of the freezable species in thefirst vessel 12 through conduit 37 (after heating, not shown). - Any gas present within the water condensate separator may be recycled to the
first vessel 12. Alternatively or additionally, a portion of the gas separated in the water/condensate separator 30 may be recycled to the wet sour gas feed stream entering thefirst vessel 12 viainlet 20. - Suitably the liquid that is sprayed into the first vessel through
inlets 26 is a natural gas liquid, which natural gas liquid is a mixture of C2, liquefied petroleum gas components, C3 and C4 and C5+hydrocarbon components. - Suitably, the warm liquid that is introduced into the first vessel through
inlet 18 is also a natural gas liquid. - Reference is now made to
FIG. 2 showing a further embodiment of the present invention. In this further embodiment dehydrated gas is treated to remove sour components from it. The dehydration process is discussed with reference toFIG. 1 , and will not be repeated here. Parts having the same function as parts shown inFIG. 1 get the same reference numeral. - The dry sour gas exits the
second flash tank 40 viagas outlet 47 and is fed to asecond vessel 14 via drysour gas inlet 46. As with thefirst vessel 12, the dry sour gas being fed to thesecond vessel 14 may be expanded through a Joule-Thompson valve 48 or other suitable expansion means, such as a turbo expander, in order to further cool the gas. As before with thefirst vessel 12, the Joule-Thompson valve may define the drysour gas inlet 46. The temperature of the dry gas entering into thesecond vessel 14 is at a second operating temperature. The second operating temperature is the maximum temperature at which solids of the sour species are formed or the temperature at which the sour species dissolve in a liquid. - The gas exiting the
second vessel 14 viaoutlet 62 is dehydrated and sweetened. The dry sweetened gas would typically be at a pressure of between 20 and 50 bar and a temperature of not lower than −85.degree. C. This product stream of sweetened dry gas is typically transported to the end user at ambient temperature. - The product stream of dry sweetened gas can be further cooled by allowing the gas to expand in
expansion device 63, and the further cooled dry sweetened gas is used in one or more of theheat exchangers apparatus 10. Please note that the temperature to which the dry gas is cooled inheat exchanger 36 is greater than that at which the solids of the sour species form for the given line pressure. - Through outlet 52 a liquid is removed that contains the sour species.
- The dry sour gas was cooled to the second operating temperature by allowing the gas to expand in Joule-
Thompson valve 48. Alternatively, the dry sour gas can be cooled using one or more sprays of a sub-cooled liquid supplied throughinlet 49. In a further alternative embodiment, the natural gas feed stream is cooled by both the Joule-Thompson valve 48 and the sub-cooled liquid supplied throughinlet 49. In case of spray cooling, the dry gas can enter into thesecond vessel 14 at a temperature that is at or above the temperature at which solids of the sour species are formed or the temperature at which the sour species dissolve in a liquid. - The sub-cooled
liquid inlet 49 should be located in thesecond vessel 14 above the drysour gas inlet 46. In the illustrated embodiment the sub-cooledliquid inlet 49 is a plurality of spray nozzles. The temperature and pressure conditions in thesecond vessel 14 are adjusted so as to form solids of the freezable species. For sweetening of a gas, the temperature-pressure conditions need only be adjusted to form solids of hydrogen sulphide (H.sub.2S) and carbon dioxide (CO.sub.2). However, the process conditions within the second vessel are sufficient to cause the formation of solids of the freezable species of other hydrocarbons such as benzene, toluene, ethylbenzene and xylene. - Suitably, the sub-cooled liquid is part of the liquid passing through
conduit 43. In order to reduce the temperature the liquid is passed throughconduit 50 to theheat exchanger 38 where it is cooled by indirect heat exchange with dry sweetened gas. The dry sweetened gas is then passed throughconduit 65 toheat exchanger 36 for cooling the dry sour gas from thefirst vessel 12. The dry sweetened gas is then fed to theintermediate heat exchanger 22 and from there to an end user (not shown). - Applicant had found that in particular the concentration of C2-C4 hydrocarbon components in the liquid should be in the range of from 0.5 to 1.5 mol per mol of CO2 in the feed gas. The liquid in the
second vessel 14 is the liquid sprayed in the vessel through theinlet 49. Thus the concentration of C2-C4 hydrocarbon components in the sub-cooled liquid should be in the specified range. It will be understood that if the concentration of C2-C4 hydrocarbon components in the liquid stream inconduit 50 is too low, additional C2-C4 hydrocarbon components can be added to this stream. - To prevent sour species from blocking
outlet 52, the condensate present in the lower portion of thesecond vessel 14 is preferably heated. This is suitably done by introducing a warm liquid throughwarm condensate inlet 56 into thesecond vessel 14 below the level at which the feed stream is introduced. A suitable liquid is liquid passing throughconduit 50. Alternatively liquid passing throughconduit 31 can be used. - Further optimization of the above discussed flow schemes to improve heat integration is possible. For example part of the hydrocarbon liquid stream leaving the
second vessel 14 throughoutlet 52 can be recycled toinlet 26 of thefirst vessel 12. In order to do so a separation vessel (not shown) is used to separate a stream of liquid enriched in sour species from the hydrocarbon stream that is recycled. - Those of skill in the art will appreciate that many modifications and variations are possible in terms of the disclosed embodiments, configurations, materials and methods without departing from their spirit and scope. Accordingly, the scope of the claims appended hereafter and their functional equivalents should not be limited by particular embodiments described and illustrated herein, as these are merely exemplary in nature.
Claims (5)
1. A process for removing contaminants from a natural gas feed stream containing water and a sour species comprising:
dehydrating the natural gas feed stream in a first vessel;
removing from the first vessel a stream of dehydrated gas;
cooling the dehydrated gas in a second vessel to a second operating temperature at which solids of the sour species are formed or at which the sour species dissolve in a liquid; and
removing from the second vessel a stream of dehydrated sweetened gas.
2. The process of claim 1 , wherein dehydrating the natural gas feed stream comprises cooling the natural gas feed stream to a first operating temperature at which hydrates are formed.
3. The process of claim 2 , wherein cooling the natural gas feed stream comprises introducing the natural gas feed stream into the first vessel at a temperature that is below the first operating temperature.
4. The process of claim 1 , wherein cooling the dehydrated gas comprises introducing the dehydrated gas into the second vessel at a temperature that is below the second operating temperature.
5. The process of claim 2 , wherein cooling the natural gas feed stream comprises introducing the natural gas feed stream into the first vessel at a temperature that is below the first operating temperature, and cooling the dehydrated gas comprises introducing the dehydrated gas into the second vessel at a temperature that is below the second operating temperature.
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NO20054132D0 (en) | 2005-09-06 |
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OA13101A (en) | 2006-11-10 |
CN1990836A (en) | 2007-07-04 |
EA200601957A1 (en) | 2007-02-27 |
EA009563B1 (en) | 2008-02-28 |
AU2004209623A1 (en) | 2004-08-19 |
TW200418563A (en) | 2004-10-01 |
CA2515139A1 (en) | 2004-08-19 |
EP1790927A3 (en) | 2008-01-16 |
CN1950657B (en) | 2010-06-16 |
TW200724835A (en) | 2007-07-01 |
AU2004209623C1 (en) | 2009-10-08 |
CN1950657A (en) | 2007-04-18 |
MY138913A (en) | 2009-08-28 |
AU2004209623B2 (en) | 2007-07-12 |
EA009248B1 (en) | 2007-12-28 |
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