PROCESS FOR THE REMOVAL OF ACIDIC CONTAMINANTS FROM A NATURAL GAS STREAM
Acidic contaminants are removed from a natural gas stream comprising hydrocarbons and acidic contaminants in a process comprising the steps of: (a) expanding the natural gas stream, thereby cooling the natural gas stream and allowing at least part of the acidic contaminants to liquefy with the proviso that no solid acidic contaminants are formed, thereby obtaining a cooled natural gas stream that contains liquefied acidic contaminants; (b) separating at least part of the liquefied acidic contaminants from the cooled natural gas stream in a separator comprising centrifugal separation means, to obtain a contaminants-depleted natural gas stream; and (c) treating the contaminants-depleted natural gas stream with a liquid physical solvent to obtain a sweet natural gas stream and a liquid solution of acidic contaminants.
present invention relates to a process for the removal of acidic contaminants from a natural gas stream that contains hydrocarbons and acidic contaminants.
BACKGROUNDIt is known that natural gas streams may contain acidic contaminants. The most prominent contaminants are hydrogen sulphide and carbon dioxide. It is desirable to remove these contaminants from the natural gas streams in an early stage since transport and/or treatment of natural gas that contain these contaminants may not only add to the costs of the transport and/or treatment, but the contaminants may also prove corrosive. Further, hydrogen sulphide is toxic and on combustion produces sulphur dioxide, another pollutant. Moreover, carbon dioxide reduces the heating value of the natural gas.
It is known to remove contaminants from natural gas streams. It is also known to use a centrifugal separator for such removal.
In EP-B 286160 a centrifugal separator is disclosed, which comprises a housing with a gas inlet for contaminated gas at one end of the housing, a separating body, a gas outlet for purified gas at the opposite end of the housing and a contaminants outlet downstream of the separating body, wherein the separating body comprises a plurality of channels over a part of the length of the axis of the housing, which channels have been arranged around a central axis of rotation.
A similar apparatus has been described in WO-A 2007/097621. However, in this specification the hydraulic diameter of the ducts are adapted such that the Reynolds number is sufficiently high to achieve a turbulent flow.
Another document wherein a similar separator has been described is U.S. Pat. No. 5,667,543. Herein the separator comprises one or more separating bodies.
Further, it is observed that the channels are non-parallel to the axis of rotation, whereby the separating process is enhanced.
In WO-A 2006/087332 a process is disclosed in which two or more separating bodies are used in order to purify natural gas streams that contain large amounts of acidic contaminants. It is stated that natural gas streams, thus purified, may be further treated, i.e., in an amine treater.
The standard technique of an amine treater is as described in WO-A 2006/087332, viz., to bind the acidic contaminants on a molecule such as diethanol amine in an aqueous solution.
Another process wherein acidic contaminants are removed from a natural gas stream with a large proportion of acidic contaminants has been described in WO-A 2007/030888. This document describes a process in which natural gas is cooled by expansion to develop the solidification of acidic contaminants. The remaining gas that has been depleted of acidic contaminants is treated with a liquid physical solvent to extract remaining acidic contaminants from the remaining gas. It is evident that the solidification of acidic contaminants requires deeper cooling than the liquefaction of such contaminants. Hence, it would be advantageous to avoid such unnecessary deep cooling.
SUMMARY OF THE INVENTIONAccordingly, the present invention provides a process for the removal of acidic contaminants from a natural gas stream comprising hydrocarbons and acidic contaminants, which process comprises:
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- (a) expanding the natural gas stream, thereby cooling the natural gas stream and allowing at least part of the acidic contaminants to liquefy with the proviso that no solid acidic contaminants are formed, thereby obtaining a cooled natural gas stream that contains liquefied acidic contaminants;
- (b) separating at least part of the liquefied acidic contaminants from the cooled natural gas stream in a separator comprising centrifugal separation means, to obtain a contaminants-depleted natural gas stream; and
- (c) treating the contaminants-depleted natural gas stream with a liquid physical solvent to obtain a sweet natural gas stream and a liquid solution of acidic contaminants.
In
As indicated above, suitable centrifugal separators include those that have been disclosed in EP-B 48508 and WO-A 2006/087332.
Liquefied acidic contaminants are withdrawn from separator 4 via a line 5. The gas is removed via a line 6. The contaminants-depleted gas stream may one or more times be subjected to re-compression and re-expansion, similar to what has been disclosed in WO-A 2006/087332. Such repetitions have not been shown.
The contaminants-depleted gas stream is passed to a column 7 where a physical solvent, such as methanol, is introduced via a line 8. Via a packing 9 the gas stream and the liquid physical solvent stream are contacted, thereby dissolving acidic contaminants into the physical solvent. The obtained liquid solution of acidic contaminants leaves the column 7 via a conduit 10. Sweet natural gas leaves the column 7 via a line 11. The sweet natural gas may be used as such, or recompressed, or treated further.
The liquid solution of acidic contaminants is supplied for regeneration to a flash vessel 12. There, the pressure is released so that acidic contaminants evaporate and a contaminants-containing vapour leaves the vessel 12 via a line 13. The remaining liquid is removed from the vessel 12 and passed via a line 14 to a second regeneration vessel 15. In cases where the contaminants-containing vapour also contains hydrocarbons, it is suitable to recycle the vapour in line 13 to the line 6 so as to ensure that hydrocarbons can be removed from the process via line 11, as is shown in the figure. It is observed that the flash operation as shown in vessel 12 may be conducted in more than one vessel, as will be appreciated by the person skilled in the art.
In the second regeneration vessel 15 the vapour is further reduced to a pressure below atmospheric pressure. Further acidic contaminants will evaporate and be withdrawn via a line 16. If desired, it is also possible to add a stripping gas into the regeneration vessel 15 that is operated at sub-atmospheric pressure to obtain a so-called vacuum stripping operation. Since hardly any hydrocarbons will be entrained with the evaporated acidic contaminants the vapour in line 16 is removed and subjected to further treatment, to compression and/or to combining with the acidic contaminants in line 5. The remaining liquid is passed from the vessel 15 to a vessel 18 via a line 17. In vessel 18 the remaining liquid is heated, e.g. by an external, e.g., electrical, heater or by a bundle coil through which a relatively warm process stream is passed. Due to the enhanced temperature, further acidic contaminants evaporate and leave the vessel 18 via a line 19. Line 19 is combined with line 16 so that the acidic contaminants are withdrawn. Regenerated liquid physical solvent is recycled from the vessel 18 to the column 7 via a line 20 and line 8. Make-up physical solvent, if any is needed, is supplied via a make-up line 21.
The acidic contaminants in lines 16 and 5 may be compressed for use in enhanced oil recovery or sequestration.
In one embodiment, there is disclosed a process comprising:
(a) expanding the natural gas stream, thereby cooling the natural gas stream and allowing at least part of the acidic contaminants to liquefy with the proviso that no solid acidic contaminants are formed, thereby obtaining a cooled natural gas stream that contains liquefied acidic contaminants;
(b) separating at least part of the liquefied acidic contaminants from the cooled natural gas stream in a separator comprising centrifugal separation means, to obtain a contaminants-depleted natural gas stream; and
(c) treating the contaminants-depleted natural gas stream with a liquid physical solvent to obtain a sweet natural gas stream and a liquid solution of acidic contaminants.
In step (a), the natural gas stream is expanded in such a way that no solid acidic contaminants are formed. In the present process the natural gas stream does not have to be cooled to the solidification temperature of acidic contaminants. That will save energy. Further, since no extra refrigeration upstream of the treatment of the contaminants-depleted gas stream is required, the present process will also save equipment costs. Moreover, it has an advantage over the use of centrifugal separator as is suggested in WO-A 2006/087332 since the treatment of the contaminants-depleted natural gas stream is with a liquid physical solvent which is selected to be more selective towards acidic contaminants than a further cooling step is at these depleted contaminants levels. The solvent will absorb less hydrocarbons, such as methane or any hydrocarbons, heavier than methane, than would condense in such further cooling step. The loss of such hydrocarbons is prevented in the present process. By physical solvent is understood a solvent that does not contain an amine moiety.
By a natural gas stream is understood any gas stream that contains significant amounts of methane and that has been produced from a subsurface reservoir. It includes a methane natural gas stream, an associated gas stream or a coal bed methane stream. The amount of the hydrocarbon fraction in such a gas stream is suitably from 10 to 85 vol % of the gas stream, preferably from 25 to 80 vol %. Especially the hydrocarbon fraction of the natural gas stream comprises at least 75 vol % of methane, preferably at least 90 vol %, of the total hydrocarbon fraction. The hydrocarbon fraction in the natural gas stream suitably contains from 0 to 20 vol %, suitably from 0.1 to 10 vol %, of C2-C6 compounds or comprises up till 20 vol %, suitably from 0.1 to 10 vol % of nitrogen.
Natural gas streams may become available at a temperature of from −5 to 150° C. and a pressure of from 20 to 700 bar. In the process of the present invention the natural gas stream comprises suitably hydrogen sulphide and/or carbon dioxide as acidic contaminants. It is observed that also minor amounts of other contaminants may be present, e.g. carbon oxysulphide, mercaptans, alkyl sulphides and aromatic sulphur-containing compounds. The major part of these components will also be removed in the process of the present invention. The acidic contaminants may occur naturally or partly or completely result from injection or re-injection into the subsurface reservoir. In the first step of the process of the present invention the natural gas stream is suitably expanded from a pressure ranging from 70 to 130 bar to a pressure ranging from 5 to 30 bar. Such expansion typically will lead to a temperature decrease that is sufficient to start liquefaction of acidic contaminants. The temperature of the natural gas stream is preferably cooled by expansion from a range of −20 to 50° C. to a range from −40 to −70° C. If the temperature of the natural gas stream is undesirably high, the natural gas stream may suitably be pre-cooled to the desired starting temperature, e.g., by means of heat exchange. The heat exchange medium may be selected from any available cold medium, in particular the sweet natural gas stream or the liquid solution of acidic contaminants.
The expansion is done in such a way that no solid acidic contaminants are formed. This is suitably achieved by conducting the expansion step in a temperature region at least 3° C., preferably at least 5° C. above the temperature at which acidic contaminants begin to solidify. It will be understood that this temperature depends on the type of acidic contaminants and the composition of the mixture and on the pressure. The skilled person will be able to determine the conditions at which the expansion step needs to be conducted.
The expansion can be achieved by any method known to the skilled person. Hence, it is possible to use a so-called Joule-Thomson valve. Preferably, the expansion is carried out using a turbo expander. In this way energy can be recovered that may be used in a subsequent step of the present process. Further, the almost isentropic expansion in a turbo-expander results in optimal cooling per bar pressure drop and, thus, saves energy for compression of the sweet natural gas stream, if such compression is desired.
The amount of hydrogen sulphide in the natural gas stream is suitably from 0.1 to 40 vol % of the natural gas stream, preferably from 20 to 35 vol %, and/or the amount of carbon dioxide is suitably from 5 to 90 vol %, preferably from 10 to 75 vol %, of the natural gas stream. Basis for these amounts is the total volume of hydrocarbons, hydrogen sulphide and carbon dioxide. It is observed that the present process is particularly suitable for gas streams comprising large amounts of acidic contaminants, e.g. 10 vol % or more, suitably from 15 to 90 vol % of the natural gas stream.
Natural gas streams produced from a subsurface formation typically contain water. In order to prevent the formation of gas hydrates in the present process, at least part of the water is suitably removed. Therefore, the natural gas stream that is used in the present process has preferably been dehydrated. This can be done by conventional processes. A suitable process is the one described in WO-A 2004/070297. Other processes for forming methane hydrates are also possible. Other dehydration processes include treatment with molecular sieves or drying processes with glycol. Suitably, water is removed until the amount of water in the natural gas stream comprises at most 50 ppmw, preferably at most 20 ppmw, more preferably at most 1 ppmw of water, based on the total natural gas stream.
The separator comprising centrifugal separation means can be any centrifugal separator known in the art, including gas-liquid cyclones. It is, however, preferred to use a separator which comprises two trays between which open-ended swirl tubes extend, each from an opening in one tray to some distance below a coaxial opening in the other tray, each swirl tube having been provided with swirl means to impart a rotary movement to gas entering the swirl tube. Such a separator has been described in EP-A 48 508. This separator basically comprises a number of swirl tubes, which are arranged between two trays in a separation vessel. In accordance with the teachings of EP-B 195 464 it is suitable to provide the separator according to EP-A 48 508 with a coalescer, e.g., a demister mat. Such mats are relatively tenuous (have a large permeability) and have a relatively large internal surface area. Thereon, small droplets of liquid will coalesce and drop down from the coalescer, whereby the removal efficiency is enhanced. If desired, it is also feasible to expose the sweet natural gas to a demister mat after leaving the swirl tubes. Accordingly, the separator suitably comprises further a coalescer upstream and/or downstream of the swirl-tubes.
A further, preliminary, means to improve the separation of liquid acidic contaminants is achieved when the separator is suitably provided with an assembly consisting of a box-like structure extending parallel to the trays having at least one open side with a grid of vanes disposed one behind the other, which assembly has been arranged upstream of the trays. Also this assembly has been disclosed in EP-B 195 464. The best separation is obtained if the cooled natural gas that contains liquefied acidic contaminants enters a separation vessel via a box-like assembly as described above. An example of such a box-like assembly is known in the art as a Schoepentoeter. This box-like Schoepentoeter assembly has also been described in U.S. Pat. No. 6,537,458 and in GB-A-1,119,699. Some liquid is separated by the assembly. Moreover, the gas is homogeneously distributed over the cross-section of the separation vessel. The remaining gas is preferably subsequently contacted with the coalescer and with the swirl tubes. Hence, the separator preferably comprises a box-like assembly as described above, a coalescer and swirl tubes and optionally a further coalescer, all as described above.
In another preferred embodiment of the present process the separator comprises a housing with a gas inlet for the cooled natural gas stream at one end of the housing, a separating body, a gas outlet for purified gas at the opposite end of the housing and a contaminants outlet downstream of the separating body, wherein the separating body comprises a plurality of channels over a part of the length of the axis of the housing, which ducts have been arranged around a central axis of rotation. Suitable separators have been described in, e.g., EP-B 286160, WO-A 2007/097621, U.S. Pat. No. 5,667,543 and WO-A 2006/087332. In a preferred embodiment the separator has been provided with a tangential gas inlet. That has the advantage that the gas is brought into a swirling motion, thereby obtaining a preliminary separation of droplets of liquefied acidic contaminants and gas. In such a situation the separator is preferably provided with an additional liquid outlet upstream of the separating body. It is also possible to provide a central gas inlet with swirl-imparting means. The known separators can be manufactured in a variety of ways. In one specific embodiment of the separator the channels consist of corrugated material wrapped around a shaft or a pipe. The material can consist of paper, cardboard, foil, metal, plastic or ceramic. Alternatively, the separator has been composed of a plurality of perforated discs wherein the perforations of the discs form the channels. The channels may be given a varying hydraulic diameter and/or be arranged in a non-parallel way with regard to the central axis of rotation. Although certain embodiments of such separators make it easy to arrange for channels that are non-parallel to the central axis of rotation, it is preferred to have parallel channels. The manufacture of parallel channels is easier and the separation under the process conditions is not substantially affected.
In one embodiment, a separator is used comprising:
1) a housing comprising a first, second and third separation section for separating liquid from the mixture, wherein the second separation section is arranged below the first separation section and above the third separation section, the respective separation sections are in communication with each other, and the second separation section comprises a rotating coalescer element;
2) tangentially arranged inlet means to introduce the mixture into the first separation section;
3) means to remove liquid from the first separation section;
4) means to remove liquid from the third separation section; and
5) means to remove a gaseous stream, lean in liquid, from the third separation section.
The separator can have a small or large number of channels. The prior art separators have a number of channels suitably ranging from 100 to 1,000,000, preferably from 500 to 500,000. The diameter of the cross-section of the channels can be varied in accordance with the amount of gas and amounts and nature, e.g., droplet size distribution, of contaminants and the desired contaminants removal efficiency. Suitably, the diameter is from 0.05 to 50 mm, preferably from 0.1 to 20 mm, and more preferably from 0.1 to 5 mm. By diameter is understood twice the radius in case of circular cross-sections or the largest diagonal in case of any other shape.
The size of the separator and in particular of the channels may vary in accordance with the amount of gas to be treated. In EP-B 286 160 it is indicated that separators with a peripheral diameter of 1 m and an axial length of 1.5 m are feasible. The separator in the present invention may suitably have a radial length ranging from 0.1 to 5 m, preferably from 0.2 to 2 m. The axial length ranges conveniently from 0.1 to 10 m, preferably, from 0.2 to 5 m.
For the process according to the invention the separator suitably rotates at a velocity of from 100 to 3000 rpm at the temperature and pressure conditions described above.
From the separator a contaminants-depleted natural gas stream is recovered. If desired, the contaminants-depleted gas stream may be subjected to separation in a second or further subsequent centrifugal separation means. These means may be the same or different. Further, it may be economic to subject the contaminants-depleted stream to a subsequent cooling by expansion before being subjected to the second or subsequent centrifugal separation means.
Acidic contaminants are withdrawn from the separators in any known fashion.
The contaminants-depleted natural gas stream can be used as such in the treatment with a liquid physical solvent. However, since the gas has become available at a rather low temperature, as acidic contaminants must be liquid at such temperature, it is preferred to heat up the contaminants-depleted natural gas steam, preferably by heat exchange with natural gas stream before that is being fed to the expansion step. Alternatively, it may be advantageous to cool the contaminants-depleted natural gas stream, e.g., by indirect heat exchange with a cold process stream or a cold external stream, e.g., from an external refrigeration loop. Further, the contaminants-depleted gas stream has become available at a relatively low pressure. This means that large volumes of gas have to be processed in the treatment with the liquid physical solvent. It would therefore be advantageous if the gas would be compressed to a higher pressure. Preferably, the contaminants-depleted gas stream is compressed to a pressure of 20 to 120 bar. At least part of the energy for the compression is suitably provided by the expansion of the natural gas stream in order to start the liquefaction of acidic contaminants.
The contaminants-depleted natural gas stream is suitably treated with a liquid physical solvent in a separate vessel. Equipment for contacting gas and liquid is known to the skilled person. In this context reference is made to Perry's Chemical Engineers' Handbook, 6th edition, 1984, Chapter 18. In a conventional way the gas stream may be contacted with the liquid physical solvent. Suitably, a column with plates or trays or a packed column, i.e. a column filled with packing material, is used as equipment for contacting the gas with the liquid physical solvent.
The liquid physical solvent may be selected from a variety of compounds. The skilled person may decide the optimal physical solvent depending on the desired performance. Suitable liquid physical solvents include tetramethylene sulphone (sulpholane) and derivatives, dimethyl sulphoxide, amides of aliphatic carboxylic acids, N-alkyl pyrrolidone, in particular N-methyl pyrrolidone, N-alkyl piperidones, in particular N-methyl piperidone, methanol, ethanol, ethylene glycol, polyethylene glycols, mono- or di(C1-C4)alkyl ethers of ethylene glycol or polyethylene glycols, suitably having a molecular weight from 50 to 800, and mixtures thereof. The skilled person may select the physical solvent based on the operating temperature of the cooling and separation steps in the present process and the preferred operating temperature of the physical solvent. These liquid physical solvents have a good solubility for acidic contaminants, such as carbon dioxide and hydrogen sulphide, whereas they will absorb hydrocarbons to only a small extent. In this way, the losses of hydrocarbons due to the treatment step are limited. Methanol, ethylene glycol and dimethylether of polyethylene glycol are particularly preferred.
The liquid physical solvent will become loaded with acidic contaminants to yield a liquid solution of acidic contaminants. Suitably, the liquid solution of acidic contaminants is regenerated to yield regenerated liquid physical solvent. Since the liquid solvents act as a physical solvent only, the regeneration is suitably effected by pressure decrease, such as a flash operation, and/or a temperature increase, such as heating the loaded liquid physical solvent. Another way to regenerate the solution is to subject the solution to a stripping treatment. Stripping is suitably effected by passing an inert gas through the solution. Suitable inert gases include nitrogen and air. Stripping may have the disadvantage that the recovered gases will be diluted with the stripping gas. The regeneration of such physical solvents represents a major advantage over chemical solvents such as alkanolamines since a much higher energy input is required to free acidic contaminants from solutions of acidic contaminants in such chemical solvents than from solutions in physical solvents. Since a treatment with chemical solvents, such as alkanolamines usually takes place at temperatures above 0° C., and the treatment with physical solvents can be carried out at temperatures below 0° C., the operational temperature of the separation matches better with the operational temperature of the treatment with physical solvents. Preferably, the regeneration includes a flashing step. In the flashing step the pressure of the loaded physical solvent is decreased. Suitably, the flashing step is conducted in two or more separate steps at two or more values of pressure decrease to produce partially regenerated physical solvent and gaseous phase comprising acidic contaminants. The gaseous phase is recovered at an intermediate pressure level and, thus, requires relatively little energy if the acidic contaminants are to be compressed. Further, such gaseous phase is suitably recycled to the contaminants-depleted natural gas stream to recover any hydrocarbons that may be present in the gas phase. The partially regenerated physical solvent may be further regenerated by further pressure release and/or some temperature increase.
The regeneration of the loaded liquid solution is suitably done at temperatures from −35° C. to 50° C. In the case that a flash operation is present, the regeneration is suitably done at a temperature from −35 to −15° C. and a pressure from 1 to 10 bar, preferably 1 to 5 bar. When no intermediate flash operation is used, the regeneration temperature is suitably from 5 to 50° C. and a pressure from 5 to 40 bar, preferably from 10 and 25 bar. In a preferred embodiment the regeneration comprises a flash operation and a thermal regeneration step. In the flash operation, in which the pressure is decreased by, e.g., from 5 to 40 bar. When the flash operation is conducted in several steps, the final step may lower the temperature as low as from 5 to 0.01 bar, preferably from 1 to 0.05 bar.
The gaseous phase that is recovered at regeneration typically comprises mainly carbon dioxide and hydrogen sulphide. They can be recovered and be used for any suitable purpose. They may, e.g., be compressed and be used for enhanced oil recovery or sequestration. The regenerated liquid physical solvent is suitably recycled to the treatment of the contaminants-depleted natural gas stream.
It may be advantageous to cool the regenerated liquid physical solvent, e.g., by indirect heat exchange with a cold process stream or a cold external stream, e.g., from an external refrigeration loop, before the regenerated is recycled to the treatment of the contaminants-depleted natural gas stream.
While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.
While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.
Claims
1. A process for the removal of acidic contaminants from a natural gas stream comprising hydrocarbons and acidic contaminants, which process comprises:
- (a) expanding the natural gas stream, thereby cooling the natural gas stream and allowing at least part of the acidic contaminants to liquefy such that no solid acidic contaminants are formed, thereby obtaining a cooled natural gas stream that contains liquefied acidic contaminants;
- (b) separating at least part of the liquefied acidic contaminants from the cooled natural gas stream in a separator comprising centrifugal separation means, to obtain a contaminants-depleted natural gas stream; and
- (c) treating the contaminants-depleted natural gas stream with a liquid physical solvent to obtain a sweet natural gas stream and a liquid solution of acidic contaminants.
2. Process as claimed in claim 1, in which the natural gas stream is expanded from a pressure ranging from 70 to 130 bar to a pressure ranging from 5 to 30 bar.
3. Process as claimed in claim 1, in which the natural gas stream is cooled by expansion from a temperature ranging from −20 to 50 C to a temperature ranging from −40 to −70 C.
4. Process as claimed in claim 1, wherein the natural gas stream is expanded using at least two expansion devices and the operating parameters of the expansion devices are chosen such that the liquefied acidic contaminants have a certain droplet size distribution.
5. Process as claimed in claim 1, in which the separator comprises two trays between which open-ended swirl tubes extend, each from an opening in one tray to some distance below the a coaxial opening in the other tray, each swirl tube having been provided with swirl means to impart a rotary movement to gas entering the swirl tube.
6. Process as claimed in claim 5, in which the separator further comprises a coalescer, upstream and/or downstream of the swirl-tubes.
7. Process as claimed in claim 5, in which the separator comprises an assembly consisting of a box-like structure extending parallel to the trays having at least one open side with a grid of vanes disposed one behind the other, which assembly has been arranged upstream of the trays.
8. Process as claimed in claim 1, in which the natural gas stream is pre-cooled by means of heat exchange.
9. Process as claimed in claim 1, in which the separator comprises a housing with a gas inlet for the cooled natural gas stream at one end of the housing, a separating body, a gas outlet for purified gas at the opposite end of the housing and a contaminants outlet downstream of the separating body, wherein the separating body comprises a plurality of channels over a part of the length of the axis of the housing, which ducts have been arranged around a central axis of rotation.
10. Process as claimed in claim 9, in which the gas inlet is tangential and in which the separator is preferably provided with an additional liquid outlet upstream of the separating body.
11. Process as claimed in claim 1, wherein in step (b) a separator is used comprising:
- 1) a housing comprising a first, second and third separation section for separating liquid from the mixture, wherein the second separation section is arranged below the first separation section and above the third separation section, the respective separation sections are in communication with each other, and the second separation section comprises a rotating coalescer element;
- 2) tangentially arranged inlet means to introduce the mixture into the first separation section;
- 3) means to remove liquid from the first separation section;
- 4) means to remove liquid from the third separation section; and
- 5) means to remove a gaseous stream, lean in liquid, from the third separation section.
12. Process as claimed in claim 1, in which the contaminants-depleted natural gas stream is compressed, to a pressure ranging from 20 to 120 bar, before being treated with the liquid physical solvent.
13. Process as claimed in claim 1, in which the liquid physical solvent is selected from the group consisting of tetramethylene sulphone (sulpholane) and derivatives, dimethyl sulphoxide, amides of aliphatic carboxylic acids, N-alkyl pyrrolidone, in particular N-methyl pyrrolidone, N-alkyl piperidones, N-methyl piperidone, methanol, ethanol, ethylene glycol, polyethylene glycols, mono- or di(C1-C4)alkyl ethers of ethylene glycol or polyethylene glycols, having a molecular weight from 50 to 800, and mixtures thereof.
Type: Application
Filed: Jul 10, 2009
Publication Date: Jan 14, 2010
Inventors: Adriaan Pieter Houtekamer (Bacton), Rick Van Der Vaart (Rijswijk)
Application Number: 12/500,776
International Classification: C10L 3/00 (20060101);
