Patent Application
20100162753
The present invention relates to a method and/or apparatus of treating a hydrocarbon stream such as a natural gas stream.
Several processes and apparatuses for treating a hydrocarbon stream are known. An example is given in US 2005/0268649 A1 relating to a process for processing natural gas or other methane-rich gas streams to produce a liquefied natural gas (LNG) stream that has a high methane purity and a liquid stream containing predominantly hydrocarbons heavier than methane.
A problem of the known method is that it is rather complicated thereby resulting in high capital expenses (CAPEX), but at the same time it does not obtain a satisfactory recovery of in particular ethane. Also the amount of fuel gas produced is not optimal, because the focus of US 2005/0268649 A1 is mainly on the liquefaction of natural gas rather than on the production of ‘residual streams’ and recovery of ethane therefrom.
A further problem of US 2005/0268649 A1 is that the start up of the method or the plant for performing the method takes a significant amount of time.
It is an object of the present invention to minimize one or more of the above problems, while at the same time maintaining or even improving the recovery of ethane and heavier hydrocarbons, in particular ethane, from the hydrocarbon stream.
It is a further object of the present invention to provide an alternative method for treating a natural gas stream.
The present invention provides a method of treating a hydrocarbon stream such as a natural gas stream, in a plant, the method at least comprising the steps of:
(a) supplying a partly condensed feed stream to a first gas/liquid separator;
(b) separating the feed stream in the first gas/liquid separator into a gaseous stream and a liquid stream;
(c) expanding the liquid stream obtained in step (b) and feeding it into a second gas/liquid separator at a first feeding point;
(d) expanding the gaseous stream obtained in step (b), thereby obtaining an at least partially condensed stream, and subsequently feeding it into the second gas/liquid separator at a second feeding point, the second feeding point being at a higher level than the first feeding point;
(e) feeding a liquefied natural gas stream into the second gas/liquid separator at a third feeding point, the third feeding point being at a higher level than the second feeding point;
(f) removing from the top of the second gas/liquid separator a C2+ lean gaseous stream; and
(g) removing from the bottom of the second gas/liquid separator a liquid stream;
wherein the liquefied natural gas stream as fed in step (e) is obtained from a source of liquefied natural gas from a separate plant.
In a further aspect the present invention relates to an apparatus for treating a hydrocarbon stream such as a natural gas stream, in a plant, the apparatus at least comprising:
a first gas/liquid separator having an inlet for a partly condensed feed stream, a first outlet for a gaseous stream and a second outlet for a liquid stream;
a second gas/liquid separator having at least a first outlet for a gaseous stream and a second outlet for a liquid stream and first, second and third feeding points, the third feeding point being at a higher level in the gas/liquid separator than the second feeding point, said second feeding point being at a higher level in the gas/liquid separator than the first feeding point;
a first expander for expanding the gaseous stream obtained from the first outlet of the first gas/liquid separator, the first expander having an outlet which is connected to the second feeding point of the second gas/liquid separator; and
a second expander for expanding the liquid stream obtained from the second outlet of the first gas/liquid separator, the second expander having an outlet which is connected to the first feeding point of the second gas/liquid separator;
wherein the third feeding point is connected to a source of liquefied natural gas from a separate plant.
Hereinafter the invention will be further illustrated by way of example and with reference to the following non-limiting drawing. In the drawing,
For the purpose of this description, a single reference number will be assigned to a line as well as a stream carried in that line. Same reference numbers refer to similar components.
Embodiments of the present invention relate to the treatment of a natural gas stream, and may involve recovery of at least some of the ethane, propane, butanes and higher hydrocarbons such as pentane from the natural gas. The recovery of hydrocarbons may be done for several purposes. One purpose may be the production of hydrocarbon streams consisting primarily of hydrocarbon products heavier than methane such as natural gas liquids (NGLs; usually composed of ethane, propane and butanes), liquefied petroleum gas (LPG; usually composed of propane and butane) or condensates (usually composed of butanes and heavier hydrocarbon components). Another purpose may be the adjustment of e.g. the heating value of the hydrocarbon stream to correspond to desired specifications of sales gas.
It has been found that, using the surprisingly simple methods set forth in the present disclosure, the CAPEX can be significantly lowered. As an example no (partial) reflux of the gaseous overhead stream from the second gas/liquid separator is needed.
Further, also due to its simplicity, the methods and apparatuses described herein are expected to be very robust and can be started up quickly when compared with known line-ups.
Furthermore it has been found a high ethane recovery may be obtained using the methods described herein. thereby resulting in a leaner methane-rich natural gas stream. The methods have also been contemplated to be suitable for feed streams having a pressure well below 70 bar, at the same time maintaining a relatively high ethane recovery.
Another advantage is that it is suitable for a broad range of feed stream compositions.
A further advantage is that more sales gas is produced, in particular if the overhead gas is not subsequently liquefied or refluxed to the second gas/liquid separator (contrary to e.g. US 2005/0268649 A1).
The hydrocarbon feed stream may be any suitable hydrocarbon-containing stream to be treated, but is usually a natural gas stream which may be obtained from natural gas or petroleum reservoirs. As an alternative the natural gas stream may also be obtained from another source, also including a synthetic source such as a Fischer-Tropsch process.
Usually the feed stream is comprised substantially of methane. Preferably the feed stream comprises at least 60 mole % methane, more preferably at least 80 mole % methane.
Depending on the source, the feed stream may contain varying amounts of hydrocarbons heavier than methane such as ethane, propane, butanes and pentanes as well as some aromatic hydrocarbons. The feed stream may also contain non-hydrocarbons such as H2O, N2, CO2, H2S and other compounds, and the like.
Embodiments of the invention involve supplying a feed stream to a first gas/liquid separator; separating the feed stream into a gaseous stream and a liquid stream; and feeding these gaseous and liquid streams into a second gas/liquid separator.
If desired, the feed stream containing the natural gas may be pre-treated before feeding it to the first gas/liquid separator. This pre-treatment may comprise removal of undesired components such as CO2 and H2S, or other steps such as pre-cooling, pre-pressurizing or the like. As these steps are well known to the person skilled in the art, they are not further discussed here. Preferably the hydrocarbon feed stream contains < (less than) 1 mole % CO2.
The first and second gas/liquid separator may be any suitable means for obtaining at least a gaseous stream and a liquid stream, such as a scrubber, distillation column, etc. If desired, three or more gas/liquid separators may be present. Preferably the second gas/liquid separator is a de-methanizer, i.e. the overhead stream of the second gas/liquid separator being methane-enriched and the bottom stream of the second gas/liquid separator being ethane-enriched when compared with the hydrocarbon feed stream.
The gaseous and liquid streams may be expanded before feeding them into the second gas/liquid separator. The person skilled in the art will understand that the steps of expanding may be performed in various ways using any expansion device (e.g. using a throttling valve, a flash valve or a common expander).
Further, the person skilled in the art will readily understand that treated hydrocarbon streams may be further processed, if desired. Also, further intermediate processing steps between the first and second gas/liquid separator may be performed.
The invention provides methods and apparatuses wherein a C2+ lean gaseous stream is produced in a plant, whereby a liquefied natural gas (LNG) stream is employed that is obtained from a source of liquefied natural gas from a separate plant. In what may hereinafter be referred to as step (e), the LNG stream may be fed into the second gas/liquid separator.
Preferably the LNG stream has a temperature below −100° C. and is at least partially condensed and comprises more than 60 mole % methane, preferably more than 80 mole % methane. The phrase “source of liquefied natural gas from a separate plant” means that the LNG is produced in a separate plant from the plant in which the C2+ lean gaseous stream is produced. No LNG stream is used that is generated in the hydrocarbon treating plant of the invention, such as any LNG stream produced during the treating itself or downstream of the treating (e.g. downstream of the second gas/liquid separator). Thus, contrary to e.g. US 2005/0268649 A1, an already existing LNG stream is used that has been produced elsewhere, for example an LNG stream produced in a separate liquefaction plant. The separate source may be a storage tank or a stream from a nearby liquefaction plant. Also, the LNG stream may have been obtained from an offloading LNG carrier vessel. Preferably the LNG stream is obtained from a separate plant at an LNG import terminal, such as an LNG storage tank at an LNG import terminal.
In a step (f), a gaseous stream is removed from the top of the second gas/liquid separator. The gaseous stream obtained in step (f) is a C2+ lean gaseous stream. By “C2+ lean” is meant a gaseous stream which has a low proportion of hydrocarbons having two or more carbon atoms, including a stream rich in methane, with only a minor proportion of hydrocarbons having two or more carbon atoms. In this way, the gaseous stream obtained in step (f) is provided with a composition and/or heating value required for used as a sales gas. For instance, the C2+ lean gaseous stream removed from the top of the second gas/liquid separator in step (f) may comprise < (less than) 10 mole % hydrocarbons having 2 of more carbon atoms, preferably <5 mole %, more preferably <2 mole % and even more preferably <1 mole %.
According to an embodiment described herein the gaseous stream obtained in step (f) is sent to a gas network and not liquefied to obtain a methane-rich LNG stream.
Further it may be that the gaseous stream obtained in step (f) is heat exchanged against the feed stream.
Moreover, the LNG stream as fed in step (e) may have been previously heat exchanged against the feed stream.
In a step (g), a liquid stream is removed from the bottom of the second gas/liquid separator. This liquid stream may be further processed. Preferably, during such further processing, this liquid stream is subjected to fractionation thereby obtaining two or more products, including ethane.
It is preferred that > (more than) 75 mole % of hydrocarbons having 2 or more carbon atoms present in the partially condensed feed stream are recovered in the liquid stream obtained from the second gas/liquid separator, preferably >80, more preferably >85, even more preferably >90, most preferably >95 mole %. Viewed another way, it is preferred that ≦ (less than or equal to) 25 mole % of the hydrocarbons having 2 or more carbon atoms present in the partially condensed feed stream are transferred to the gaseous stream obtained in step (f), preferably ≦20, more preferably ≦15, even more preferably ≦10, most preferably ≦5 mole %.
For instance, it is preferred that > (more than) 75 mole % of the ethane present in the paritially condensed feed stream is recovered in the liquid stream obtained in step (g), preferably >80, more preferably >85, even more preferably >90, most preferably >95 mole %. Viewed another way, it is preferred that s (less than or equal to) 25 mole % of the ethane present in the partially condensed feed stream is transferred to the gaseous stream obtained from the second gas/liquid separator in step (f), preferably ≦20, more preferably ≦15, even more preferably ≦10, most preferably ≦5 mole %. According to an embodiment described herein the pressure drop during expanding—in a step (d)—of the gaseous stream obtained from the first gas/liquid separator is less than 15 bar, more preferably less than 10 bar, even more preferably less than 5 bar. Herewith the energy consumption in the treating process can be reduced.
Also it is preferred that the pressure in the second gas/liquid separator is from 15 to 40 bar, preferably from 20 to 30 bar. Examples include from 23 to 27 bar and about 25 bar.
The process scheme of
During use, a partly condensed feed stream 10 containing natural gas is supplied to the inlet 21 of the first gas/liquid separator 2 at a certain inlet pressure and inlet temperature. Typically, the inlet pressure to the first gas/liquid separator 2 will be between 10 and 100 bar, preferably above 30 bar and preferably below 90 bar, more preferably below 70 bar. The temperature will usually be between 0 and −80° C. To obtain the partly condensed feed stream 10, it may have been pre-cooled in several ways. In the embodiment of
If desired the feed stream 10 may have been further pre-treated before it is fed to the first gas/liquid separator 2. As an example, H2O, CO2, H2S and hydrocarbon components having the molecular weight of pentane or higher may also at least partially have been removed from the feed stream 10 before entering the first separator 2.
In the first gas/liquid separator 2, the feed stream 10 (fed at inlet 21) is separated into a gaseous stream 20 (removed at first outlet 22) and a liquid stream 30 (removed at second outlet 23). The gaseous stream 20, which may hereinafter be referred to as the gaseous overhead stream 20, is enriched in methane relative to the feed stream 10.
The liquid stream 30, which may hereinafter be referred to as the liquid bottom stream 30, is generally liquid and usually contains some components that are freezable when they would be brought to a temperature at which methane is liquefied. The bottom stream 30 may also contain hydrocarbons that can be separately processed to form liquefied petroleum gas (LPG) products. The stream 30 is expanded in the second expander 7 to the operating pressure of the distillation column 3 (usually about 25 bar) and fed into the same at a first feeding point 31 as stream 40. If desired a further heat exchanger (not shown) may be present on line 40 to heat the stream 40. The second expander 7 may be any expansion device such as a liquid expander as well as a flash valve.
The gaseous overhead stream 20 removed at the first outlet 22 of the first separator 2 is at least partially condensed in the first expander 6 and subsequently fed as an at least partially condensed stream 50 into the distillation column 3 at a second feeding point 32. The second feeding point 32 is at a higher level than the first feeding point 31. If desired a further heat exchanging step may take place between the first expander 6 and the second feeding point 32. The pressure drop over the expander 6 may be lower than 15 bar, even lower than 10 bar, as no extra cooling is required for the stream 50 in view of the use of the cold stream 70 (to be discussed hereafter).
If desired (and as indicated with dashed lines in
The LNG stream 70 is, after cooling the feed stream 10 in heat exchanger 5, fed as stream 70b into the distillation column 3 at a third feeding point 33, the third feeding point 33 being at a higher level than the second feeding point 32. Preferably the third feeding point 33 is at or near the top of the distillation column 3.
Preferably, the pressure in the distillation column 3 is from 15 to 40 bar, preferably from 20 to 30 bar.
Preferably, the temperature of the LNG stream 70 is below −150° C. just before heat exchanging (as stream 70a) against stream 10 in heat exchanger 5, and below −100° C. but usually above −150° C. just before feeding (as stream 70b) in the second gas/liquid separator 3 at the third feeding point 33. Herewith no reflux of the overhead stream 60 to the distillation column 3 is required in order to recover a major part of the ethane present in the feed stream 10 in the bottom product stream 80. As a result the capital expenses are significantly reduced.
The gaseous overhead stream 60 obtained at the top of the second gas/liquid separator 3 (at first outlet 34) is sent to the gas network 11 (for use as a sales gas) after heat exchanging against the feed stream 10 in heat exchanger 12 and optionally compressing in compressor 8 (which may be functionally coupled to first expander 6). Preferably, the gaseous stream 60 is not subsequently liquefied.
A liquid stream 80, hereinafter also referred to as a liquid bottom stream 80, is removed from the second outlet 35 of the distillation column 3. Liquid bottom stream 80 may be cooled in ambient cooler 81 and is usually subjected to one or more fractionation steps, e.g. in a fractionation unit 9, to collect various natural gas liquid products. For example, as shown in
If desired, and as shown in
The person skilled in the art will understand that the amount of ethane recovered in the bottom stream will also be dependent on the composition of the LNG stream 70 originating from the source 4. In case the LNG stream 70 contains large amounts of ethane, this ethane will be substantially recovered in the bottom stream 80.
Table I gives an overview of the pressures and temperatures of a stream at various parts in an example process of
It was found that according to the present invention the amount of overhead gas stream 60 (that can be used as sales gas) was relatively high when compared with the same line-up as
The person skilled in the art will readily understand that many modifications may be made without departing from the scope of the invention. As an example, the compressor may comprise two or more compression stages. Further, each heat exchanger may comprise a train of heat exchangers.
| Number | Date | Country | Kind |
|---|---|---|---|
| 06119358.7 | Aug 2006 | EP | regional |
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/EP2007/058648 | 8/21/2007 | WO | 00 | 2/19/2009 |
