U.S. patent application number 12/304496 was filed with the patent office on 2009-07-30 for method and apparatus for treating a hydrocarbon stream.
Invention is credited to Eduard Coenraad Bras, Hussein Mohammed Ismail Mostafa, Paramasivam Senthil Kumar.
Application Number | 20090188279 12/304496 |
Document ID | / |
Family ID | 37564056 |
Filed Date | 2009-07-30 |
United States Patent
Application |
20090188279 |
Kind Code |
A1 |
Bras; Eduard Coenraad ; et
al. |
July 30, 2009 |
METHOD AND APPARATUS FOR TREATING A HYDROCARBON STREAM
Abstract
The present invention relates to a method of treating a
hydrocarbon stream such as a natural gas stream, the method at
least comprising the steps of: (a) supplying a partially condensed
feed stream (10) to a first gas/liquid separator (2), the feed
stream (10) having a pressure >50 bar; (b) separating the feed
stream (10) in the first gas/liquid separator (2) into a first
vaporous stream (20) and a first liquid stream (70); (c) expanding
the first vaporous stream (20), thereby obtaining an at least
partially condensed first vaporous stream (30); (d) supplying the
at least partially condensed first vaporous stream (30) to a second
gas/liquid separator (4); (e) separating the stream (30) as
supplied in step (d) in the second gas/liquid separator (4) into a
second vaporous stream (60) and a second liquid stream (40); (f)
increasing the pressure of the second liquid stream (40) to a
pressure of at least 50 bar, thereby obtaining a pressurized second
liquid stream (50); and (g) returning the pressurized second liquid
stream (50) to the first gas/liquid separator (2).
Inventors: |
Bras; Eduard Coenraad; (The
Hague, NL) ; Ismail Mostafa; Hussein Mohammed;
(Cairo, EG) ; Kumar; Paramasivam Senthil; (The
Hague, NL) |
Correspondence
Address: |
SHELL OIL COMPANY
P O BOX 2463
HOUSTON
TX
772522463
US
|
Family ID: |
37564056 |
Appl. No.: |
12/304496 |
Filed: |
June 14, 2007 |
PCT Filed: |
June 14, 2007 |
PCT NO: |
PCT/EP07/55866 |
371 Date: |
December 12, 2008 |
Current U.S.
Class: |
62/630 ;
62/620 |
Current CPC
Class: |
F25J 2235/60 20130101;
F25J 2260/20 20130101; F25J 3/0233 20130101; F25J 2210/06 20130101;
C10G 7/02 20130101; F25J 3/0242 20130101; F25J 2200/70 20130101;
F25J 3/0247 20130101; C10G 2300/1025 20130101; F25J 2205/02
20130101; C10G 5/06 20130101; C10L 3/10 20130101; F25J 2200/74
20130101; C10G 2300/4012 20130101; F25J 2200/02 20130101; F25J
2245/02 20130101; F25J 3/0209 20130101; F25J 2270/04 20130101 |
Class at
Publication: |
62/630 ;
62/620 |
International
Class: |
F25J 3/02 20060101
F25J003/02; C10G 5/06 20060101 C10G005/06 |
Foreign Application Data
Date |
Code |
Application Number |
Jun 16, 2006 |
EP |
06115604.8 |
Claims
1. A method of treating a hydrocarbon stream, the method at least
comprising the steps of: (a) supplying a partially condensed feed
stream to a first gas/liquid separator, the feed stream having a
pressure >50 bar; (b) separating the feed stream in the first
gas/liquid separator into a first vaporous stream and a first
liquid stream; (c) expanding the first vaporous stream obtained in
step (b), thereby obtaining an at least partially condensed first
vaporous stream; (d) supplying the at least partially condensed
first vaporous stream obtained in step (c) to a second gas/liquid
separator; (e) separating the stream as supplied in step (d) in the
second gas/liquid separator into a second vaporous stream and a
second liquid stream; (f) increasing the pressure of the second
liquid stream obtained in step (e) to a pressure of at least 50
bar, thereby obtaining a pressurized second liquid stream; and (g)
returning the pressurized second liquid stream obtained in step (f)
to the first gas/liquid separator.
2. The method according to claim 1, wherein in step (a) the feed
stream is supplied as at least two different streams to the first
gas/liquid separator, the feed stream comprising a higher feed
stream and a lower feed stream.
3. The method according to claim 2, wherein the higher feed stream
is cooled before it is supplied to the first gas/liquid
separator.
4. The method according to claim 3, wherein the higher feed stream
is cooled against the second vaporous stream obtained in step
(e).
5. The method according to claim 1, wherein the first liquid stream
obtained in step (b) is supplied to a third gas/liquid separator
thereby obtaining a third vaporous stream and a third liquid
stream.
6. The method according to claim 5, wherein the third vaporous
stream is combined with the second vaporous stream.
7. The method according to claim 5, wherein the third liquid stream
is heat exchanged against the first liquid stream, before it is
supplied to the third gas/liquid separator.
8. The method according to claim 5, wherein the third liquid stream
is heat exchanged against the lower feed stream.
9. The method according to claim 5, wherein the third column is a
debutanizer, thereby obtaining a third vaporous stream being
enriched in butane and lower hydrocarbons relative to the third
liquid stream.
10. The method according to claim 1, wherein the second vaporous
stream, is liquefied, thereby obtaining a liquefied hydrocarbon
stream.
11. An apparatus for treating a hydrocarbon stream, the apparatus
at least comprising: a first gas/liquid separator for separating a
partially condensed feed stream O into a first vaporous stream and
a first liquid stream; an expander for expanding the first vaporous
stream; a second gas/liquid separator for separating the expanded
first vaporous stream into a second vaporous stream and a second
liquid stream; and a pressurizing unit for increasing the pressure
of the second liquid stream to a pressure of at least 50 bar before
being returned to the first gas/liquid separator.
12. The apparatus according to claim 11, wherein the first
gas/liquid separator comprises at least two inlets for the feed
stream, including a first inlet for a higher feed stream and a
second inlet for a lower feed stream.
13. The apparatus according to claim 12, wherein the apparatus
further comprises a heat exchanger for cooling the higher feed
stream against the second vaporous stream.
14. The apparatus according to claim 11, wherein the apparatus
further comprises a third gas/liquid separator for separating the
first liquid stream into a third vaporous stream and a third liquid
stream.
15. The apparatus according to claim 14, wherein the third vaporous
stream can be combined with the second vaporous stream.
16. The method according to claim 2, wherein the first liquid
stream obtained in step (b) is supplied to a third gas/liquid
separator thereby obtaining a third vaporous stream and a third
liquid stream.
17. The method according to claim 3, wherein the first liquid
stream obtained in step (b) is supplied to a third gas/liquid
separator thereby obtaining a third vaporous stream and a third
liquid stream.
18. The method according to claim 4, wherein the first liquid
stream obtained in step (b) is supplied to a third gas/liquid
separator thereby obtaining a third vaporous stream and a third
liquid stream.
19. The method according to claim 6, wherein the third liquid
stream is heat exchanged against the first liquid stream, before it
is supplied to the third gas/liquid separator.
20. The method according to claim 6, wherein the third liquid
stream is heat exchanged against the lower feed stream.
Description
[0001] The present invention relates to a method of treating a
hydrocarbon stream such as a natural gas stream, in particular in a
process for the production of liquefied natural gas.
[0002] Several methods of treating a natural gas stream are known,
e.g. to remove undesired components from the natural gas and/or to
meet the required specifications of a client.
[0003] Also, several methods of liquefying a natural gas stream
thereby obtaining liquefied natural gas (LNG) are known. It is
desirable to liquefy a natural gas stream for a number of reasons.
As an example, natural gas can be stored and transported over long
distances more readily as a liquid than in gaseous form, because it
occupies a smaller volume and does not need to be stored at high
pressures.
[0004] Usually, the natural gas stream to be liquefied (mainly
comprising methane) contains ethane, heavier hydrocarbons and
possibly other components that are to be removed to a certain
extent before the natural gas is liquefied. Also to this end, the
natural gas stream is treated. One of the treatments may involve
the removal of at least some of the ethane, propane and higher
hydrocarbons such as butane and propane.
[0005] A known method of treating a natural gas stream is disclosed
in U.S. Pat. No. 5,291,736 relating to a method for the
liquefaction of natural gas, at the same time separating
hydrocarbons heavier than methane.
[0006] As the treating process, whether or not forming part of a
liquefaction process, is highly energy consuming there is a
constant need to provide alternative processes of treating natural
gas, wherein the energy consumption is reduced.
[0007] It is an object of the invention to meet the above need and
to provide a process in which the energy consumption is
reduced.
[0008] It is a further object of the present invention to provide
an alternative method for treating a natural gas stream.
[0009] One or more of the above or other objects are achieved
according to the present invention by providing a method of
treating a hydrocarbon stream such as a natural gas stream, the
method at least comprising the steps of: [0010] (a) supplying a
partially condensed feed stream to a first gas/liquid separator,
the feed stream having a pressure >(above) 50 bar; [0011] (b)
separating the feed stream in the first gas/liquid separator into a
first vaporous stream and a first liquid stream; [0012] (c)
expanding the first vaporous stream obtained in step (b), thereby
obtaining an at least partially condensed first vaporous stream;
[0013] (d) supplying the at least partially condensed first
vaporous stream obtained in step (c) to a second gas/liquid
separator; [0014] (e) separating the stream as supplied in step (d)
in the second gas/liquid separator into a second vaporous stream
and a second liquid stream; [0015] (f) increasing the pressure of
the second liquid stream obtained in step (e) to a pressure of at
least 50 bar, thereby obtaining a pressurized second liquid stream;
and [0016] (g) returning the pressurized second liquid stream (50)
obtained in step (f) to the first gas/liquid separator.
[0017] In an alternative embodiment, the invention relates to a
method of treating a hydrocarbon stream such as a natural gas
stream, the method at least comprising the steps of: [0018] (a)
supplying a partially condensed feed stream (10) to a first
gas/liquid separator (2), the feed stream (10) preferably having a
pressure >30 bar; [0019] (b) separating the feed stream (10) in
the first gas/liquid separator (2) into a first vaporous stream
(20) and a first liquid stream (70); [0020] (c) expanding the first
vaporous stream (20) obtained in step (b), thereby obtaining an at
least partially condensed first vaporous stream (30); [0021] (d)
supplying the at least partially condensed first vaporous stream
(30) obtained in step (c) to a second gas/liquid separator (4);
[0022] (e) separating the stream (30) as supplied in step (d) in
the second gas/liquid separator (4) into a second vaporous stream
(60) and a second liquid stream (40); [0023] (f) increasing the
pressure of the second liquid stream (40) obtained in step (e) to a
pressure of at least 30 bar, thereby obtaining a pressurized second
liquid stream (50); and [0024] (g) returning the pressurized second
liquid stream (50) obtained in step (f) to the first gas/liquid
separator (2).
[0025] It has surprisingly been found that using the method
according to the present invention, a significant reduction of
energy consumption may be obtained. The method according to the
invention is especially advantageous as the feed stream is
available at a relatively high pressure, typically >(above) 50
bar, preferably above 55 bar, more preferably above 60 bar.
[0026] Whenever in the specification and claims reference is made
to a pressure in bar, this is a pressure in bar (absolute).
[0027] According to the present invention no expensive refrigerant
scheme has to be used to cool the first vaporous stream.
[0028] The hydrocarbon stream may be any suitable stream to be
treated, but is usually a natural gas stream 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.
[0029] Usually the natural gas stream is comprised substantially of
methane. Preferably the feed stream comprises at least 60 mol %
methane, more preferably at least 75 mol %, such as at least 80 mol
% methane.
[0030] Depending on the source, the natural gas may contain varying
amounts of hydrocarbons heavier than methane such as ethane,
propane, butanes and pentanes as well as some aromatic
hydrocarbons. The natural gas stream may also contain
non-hydrocarbons such as H.sub.2O, mercury, N.sub.2, CO.sub.2,
H.sub.2S and other sulphur compounds.
[0031] 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 H.sub.2O, mercury, N.sub.2, CO.sub.2, H.sub.2S and other
sulphur compounds, or other steps such as pre-cooling or
pre-pressurizing. As these steps are well known to the person
skilled in the art, they are not further discussed here.
[0032] Usually the feed stream has a temperature in the range from
ambient to 90.degree. C., preferably from 20.degree. C. to
80.degree. C. Preferably the pressure of the feedstream is in the
range from more than 50 bar to 100 bar, more preferably from more
than 55 bar to 90 bar, even more preferably from more than 60 bar
to 80 bar.
[0033] The first and second gas/liquid separators may be any
suitable means for obtaining a vaporous stream and a liquid stream,
such as a vessel, a scrubber, a distillation column, etc. Usually
the first gas/liquid separator comprises a column having 1-30
trays, preferably 1-15 trays. In the embodiment of the invention
described with reference to FIG. 1, the second gas/liquid separator
usually comprises a simple vessel with only one tray. In the
embodiment of the invention described with reference to FIG. 2, the
second gas/liquid separator preferably comprises a column having
1-30 trays, more preferably 1-15 trays.
[0034] Alternatively the first and second gas/liquid separators may
each be provided with packing (random or structured). When the
gas/liquid separator is provided with trays, a distillation stage
corresponds to one tray, and when the gas/liquid separator is
provided with packing (random or structured) a distillation stage
corresponds to a theoretical stage.
[0035] Where in the specification and in the claims a level of
introducing a stream into the gas/liquid separator is defined
relative to introducing another stream, there is at least one
distillation stage between the two levels, the same applies to
defining the level of removing a stream from the gas/liquid
separator. The top of the gas/liquid separator is that part of the
gas/liquid separator that is located above the uppermost
distillation stage, and the bottom of the gas/liquid separator is
that part of the gas/liquid separator that is located below the
lowermost distillation stage.
[0036] The first liquid stream and the second vaporous stream may
be used as product streams or may be further processed, if
desired.
[0037] In step (f) of the method of the present invention, the
pressure of the second liquid stream obtained in step (e) is
increased to a pressure of at least 50 bar, thereby obtaining a
pressurized second liquid stream. Preferably, the pressure of the
second liquid stream is increased to a pressure in the range from
more than 50 bar to 100 bar, more preferably from more than 55 bar
to 90 bar, even more preferably from more than 60 bar to 80
bar.
[0038] Typically, the pressure of the second liquid stream is in
the range from 0 to 5 bar higher than the pressure in the first
gas/liquid separator, preferably from 0 to 2 bar higher, even more
preferably from 0 to 1 bar higher, in particular substantially the
same pressure.
[0039] It is preferred according to the present invention that in
step (a) the feed stream is supplied as at least two different
streams to the first gas/liquid separator, the feed stream
comprising a higher feed stream and a lower feed stream. In this
embodiment, the higher feed stream is fed at a warmer (i.e. higher)
point of the first gas/liquid separator than the lower feed stream
(that is fed at a lower, i.e. colder, point of the first gas/liquid
separator).
[0040] Further it is preferred that the higher feed stream is
cooled, preferably against the second vaporous stream obtained in
step (e). To this end a heat exchanger may be used.
[0041] Also it is preferred that the first liquid stream obtained
in step (b) is supplied to a third gas/liquid separator thereby
obtaining a third vaporous stream and a third liquid stream.
Preferably the third vaporous stream is combined with the second
vaporous stream.
[0042] In a further aspect the present invention relates to an
apparatus for treating a hydrocarbon stream such as a natural gas
stream, the apparatus at least comprising: [0043] a first
gas/liquid separator for separating a partially condensed feed
stream into a first vaporous stream and a first liquid stream;
[0044] an expander for expanding the first vaporous stream; [0045]
a second gas/liquid separator for separating the expanded first
vaporous stream into a second vaporous stream and a second liquid
stream; and [0046] a pressurizing unit for increasing the pressure
of the second liquid stream to at least 50 bar before being
returned to the first gas/liquid separator.
[0047] Preferably the first gas/liquid separator comprises at least
two inlets for the feed stream, including an inlet for a higher
feed stream and an inlet for a lower feed stream.
[0048] It is especially preferred that the apparatus further
comprises a heat exchanger for cooling the higher feed stream
against the second vaporous stream.
[0049] Further it is preferred that the apparatus further comprises
a third gas/liquid separator for separating the first liquid stream
into a third vaporous stream and a third liquid stream. Preferably
the third vaporous stream can be combined with the second vaporous
stream.
[0050] Hereinafter the invention will be further illustrated by the
following non-limiting drawing. Herein shows:
[0051] FIG. 1 schematically a process scheme in accordance with an
embodiment of the present invention; and
[0052] FIG. 2 schematically a process scheme in accordance with
another embodiment of the present invention.
[0053] 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.
[0054] FIG. 1 schematically shows a process scheme enabling
selective low temperature separation of heavy hydrocarbons
(C.sub.5.sup.+) in a gas plant with flexibility to recover/reject
LPGs.
[0055] The process scheme (or apparatus) is generally indicated
with reference number 1.
[0056] A partially condensed hydrocarbon feed stream 10 such as
natural gas is supplied to a first gas/liquid separator 2 at a
certain inlet pressure and inlet temperature. In the embodiment of
FIG. 1 the feed stream 10 is fed as two different streams, viz. a
higher feed stream 10a and a lower feed stream 10b. If desired the
feed stream 10 may be split in more than two sub-streams. The
higher feed stream 10a is pre-cooled in heat exchanger 6 and fed to
the separator 2 at first inlet 11; the lower feed stream 10b is fed
to the separator 2 at second inlet 12. In the shown embodiment,
stream 10a is cooled against another stream in the process (i.e.
stream 60). However, any other cooling may be used, if desired.
[0057] Typically, the feed stream 10 has a temperature in the range
from ambient to 90.degree. C., preferably from 20.degree. C. to
80.degree. C. Preferably the pressure of the feedstream is in the
range from more than 50 bar to 100 bar, more preferably from more
than 55 bar to 90 bar, even more preferably from more than 60 bar
to 80 bar. The temperature and pressure of the streams 10a and 10b
is chosen to optimise a gas/liquid separation step in separator 2.
If desired, the pressure of the streams 10a and 10b may have been
adjusted in valves 13 and 14, respectively.
[0058] As mentioned above, stream 10 is fed to the gas/liquid
separator 2 as streams 10a and 10b. There, the feed stream 10 is
separated into a first vaporous (i.c. overhead) stream 20 and a
first liquid (i.c. bottom) stream 70. The overhead stream 20 leaves
the separator 2 at first outlet 15 and is enriched in methane (and
usually also ethane) relative to the feed stream 10.
[0059] The bottom stream 70 leaves the separator 2 at second outlet
16 and is generally liquid; stream 70 may contain hydrocarbons that
can be separately processed to form liquefied petroleum gas (LPG)
products. Usually, the bottom stream 70 is subjected to one or more
fractionation steps to collect various natural gas liquid
products.
[0060] The overhead stream 20 is led to an expander 3, thereby at
least partially condensing the stream 20, thereby obtaining stream
30. Subsequently, stream 30 is fed to a second gas/liquid separator
4 at inlet 21. In the second separator 4, the partially condensed
stream 30 is separated into a second vaporous (i.c. overhead)
stream 60 and a second liquid (i.c. bottom) stream 40. The overhead
stream 60 leaves the separator 4 at outlet 22 and is generally
vaporous; the bottom stream 40 leaves the separator 4 at outlet 23
and is generally liquid.
[0061] Then the stream 40 is pressurized in pressurizing unit 5 to
a pressure of at least 50 bar. The pressurizing unit 5 may be any
suitable means for increasing the pressure such as a pump. The
pressurized stream 50 leaving the pressurizing unit 5 is
subsequently returned to the first gas/liquid separator 2,
preferably at the warm (i.c. high) part thereof, at third inlet 17
of the first separator 2.
[0062] The first liquid stream 70 and the second vaporous stream 60
may be used as product streams or may be further processed, if
desired.
[0063] In the embodiment as shown in FIG. 1, the second vaporous
stream 60 is used to cool the higher feed stream 10a in heat
exchanger 6.
[0064] Furthermore, the first liquid stream 70 is (after being
optionally depressurized in valve 33) fed (as stream 70a) to a
third gas/liquid separator 7 (at inlet 34) thereby obtaining (at
outlet 31) a third vaporous stream 80 and (at outlet 32) a third
liquid stream 90.
[0065] The third vaporous stream 80 is combined with the second
vaporous stream 65 (i.e. stream 60 after being heat exchanged in
heat exchanger 6) at junction point 18 and is subsequently
compressed in compressor 8 thereby obtaining product gas 100 which
will usually be subjected to a liquefaction step in one or more
heat exchangers (not shown) thereby obtaining liquefied natural gas
(LNG). In case that stream 100 is to be liquefied, some further
treatment steps may take place to remove any contaminants that may
solidify during the liquefaction process. As an example a (n
optionally additional) CO.sub.2 removal step may take place.
[0066] Stream 80 may be compressed to about the same pressure of
the second vaporous stream 65 before stream 80 is combined with the
second vaporous stream 65 at the junction point 18.
[0067] FIG. 2 schematically shows an alternative embodiment of the
present invention to provide an integrated gas dew pointing and
condensate stabilizing process, wherein the third column 7 is in
the form of a debutanizer/stabilizer, thereby obtaining a third
vaporous stream 80 being enriched in butane and lower hydrocarbons
(such as methane, ethane and or propane) relative to the third
liquid stream 90.
[0068] Furthermore, FIG. 2 shows that the third vaporous stream 80,
before being combined with stream 65 in junction point 18, has
previously been cooled (as stream 80a) against (an air cooler or
water cooler or, as shown) an external refrigerant in heat
exchanger 55, fed (as stream 80b) to a fourth gas/liquid separator
19 at inlet 41, and removed at outlet 42 from the fourth gas/liquid
separator 19 (as stream 80). The fourth gas/liquid separator 19
functions as an overhead condenser drum. The liquid bottom stream
110 removed at outlet 43 from the fourth gas/liquid separator 19 is
pressurized in pump 51 and returned as stream 120 to the top (at
inlet 33) of the debutanizer 7.
[0069] A part of the bottom stream 90 (or `condensate`) of the
debutanizer/stabilizer 7 is split off at splitter 56, heat
exchanged as stream 130 against an external stream in heat
exchanger 52 (functioning as a reboiler) and returned as stream 140
to the bottom (at inlet 35) of the debutanizer/stabilizer 7. The
major part of the condensate stream 90 is (after splitter 56) heat
exchanged against the first liquid stream 70 in heat exchanger 53
and subsequently against stream 10b in heat exchanger 54 and used
as a product stream.
[0070] In addition to or instead of heat exchanging stream 70 (or
70a) against stream 90 (in heat exchanger 53), stream 70 (or 70a)
may be heat exchanged against stream 80a, for example in heat
exchanger 55.
[0071] If desired, one or more further gaseous and/or liquid
streams (not shown) may be introduced into the
debutanizer/stabilizer 7.
[0072] The line-up as used in FIG. 2 allows to produce a product
gas stream 80 with a surprisingly high content of LPGs (i.e.
propane and/or butane) and a condensate stream 90 with a
surprisingly high content of C.sub.5.sup.+ (i.e. pentane and higher
components). As indicated above, stream 80 may be used as a
separate product stream, but will usually combined with stream 65
to enrich the latter stream.
[0073] Table I gives an overview of the estimated pressures and
temperatures of a stream at various parts in an example process of
FIG. 2. Also the mole fraction of methane is indicated. The feed
stream in line 10 of FIG. 2 comprised approximately the following
composition: 75.2 mole % methane, 9.2 mole % ethane, 4.3 mole %
propane, 2.1 mole % butanes, 5.2 mole % C.sub.5.sup.+, 1.2 mole %
N.sub.2 and 2.7 mole % CO.sub.2. H.sub.2S and H.sub.2O were
previously removed.
TABLE-US-00001 TABLE I Methane Pressure Temperature [mole Line
[bar] [.degree. C.] fraction] 10 67.7 61.1 0.752 20 66.8 -1.0 0.807
30 42.2 -21.3 0.807 40 42.2 -21.3 0.291 50 69.7 -19.2 0.291 60 42.2
-21.3 0.831 65 41.7 85.6 0.831 70 67.0 4.9 0.287 80 42.7 10.0 0.456
90 9.5 173.3 0.0 100 49.6 78.8 0.795 110 8.9 10.0 0.027
[0074] The person skilled in the art will readily understand that
many modifications may be made, without departing from the scope of
the appended claims.
[0075] As an example, the expander 3 and compressor 8 may be
functionally coupled.
* * * * *