U.S. patent application number 12/575846 was filed with the patent office on 2010-02-04 for removing contaminants from natural gas.
This patent application is currently assigned to WOODSIDE ENERGY LIMITED. Invention is credited to Robert Amin, Casper Krijno Groothuis.
Application Number | 20100024472 12/575846 |
Document ID | / |
Family ID | 30005234 |
Filed Date | 2010-02-04 |
United States Patent
Application |
20100024472 |
Kind Code |
A1 |
Amin; Robert ; et
al. |
February 4, 2010 |
Removing Contaminants from Natural Gas
Abstract
A process is described for removing contaminants from a natural
gas feed stream including water. The process includes the steps of
cooling the natural gas feed stream in a first vessel to a first
operating temperature at which hydrates are formed, heating the
hydrates to a temperature that is above the first operating
temperature by introducing a warm liquid to the first vessel so as
to melt the hydrates and liberate a dehydrated gas and a
water-containing liquid, and removing from the first vessel a
stream of dehydrated gas.
Inventors: |
Amin; Robert; (Bentley WA,
AU) ; Groothuis; Casper Krijno; (The Hague,
NE) |
Correspondence
Address: |
EDELL, SHAPIRO & FINNAN, LLC
1901 RESEARCH BOULEVARD, SUITE 400
ROCKVILLE
MD
20850
US
|
Assignee: |
WOODSIDE ENERGY LIMITED
Perth
AU
|
Family ID: |
30005234 |
Appl. No.: |
12/575846 |
Filed: |
October 8, 2009 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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11556869 |
Nov 6, 2006 |
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12575846 |
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10772621 |
Feb 5, 2004 |
7152431 |
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11556869 |
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Current U.S.
Class: |
62/541 ; 62/532;
62/617 |
Current CPC
Class: |
F25J 2205/20 20130101;
F25J 2205/30 20130101; C10L 3/10 20130101; F25J 2220/64 20130101;
F25J 2215/04 20130101; F25J 2245/02 20130101; F25J 3/0635 20130101;
Y02C 20/40 20200801; F25J 2220/66 20130101; F25J 3/067 20130101;
F25J 3/061 20130101; F25J 2220/68 20130101; C10L 3/102 20130101;
Y02C 10/12 20130101 |
Class at
Publication: |
62/541 ; 62/532;
62/617 |
International
Class: |
B01D 9/04 20060101
B01D009/04; F25J 3/00 20060101 F25J003/00 |
Foreign Application Data
Date |
Code |
Application Number |
Feb 7, 2003 |
AU |
2003900534 |
Claims
1. A process for removing contaminants from a natural gas feed
stream including water, which process 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, heating
the hydrates to a temperature that is above the first operating
temperature by introducing a warm liquid to the first vessel so as
to melt the hydrates and liberate a dehydrated gas and a
water-containing liquid; and, removing from the first vessel a
stream of dehydrated gas.
2. The process of claim 1, wherein the warm liquid is a natural gas
liquid.
3. The process of claim 2, further comprising the step of
separating natural gas liquids from the natural gas feed stream
upstream of the first vessel and using the separated natural gas
liquid as the warm liquid introduced to the first vessel to melt
the hydrates.
4. The process of claim 1, further comprising the step of removing
the water-containing liquid from the first vessel and recovering
natural gas liquids from the water-containing liquid.
5. The process of claim 4, wherein the natural gas liquids
recovered from the water-containing liquid are heated and recycled
as the warm liquid introduced to the first vessel to melt the
hydrates.
6. The process of claim 1, wherein the step of cooling the natural
gas feed stream in a first vessel to a first operating temperature
comprises introducing the natural gas feed stream into the first
vessel at a temperature that is below the first operating
temperature.
7. The process of claim 1, wherein the step of cooling the natural
gas feed stream comprises expanding the natural gas feed stream
through an expansion device.
8. The process of claim 1, wherein the step of cooling the natural
gas feed stream in a first vessel to a first operating temperature
comprises introducing a sub-cooled liquid into the first vessel in
addition to introducing the natural gas feed stream to the first
vessel, the sub-cooled liquid being introduced at a temperature
that is below the first operating temperature.
9. The process of claim 8, wherein the first vessel includes an
inlet for the natural gas feed stream and the sub-cooled liquid is
introduced through a sub-cooled liquid inlet located in the first
vessel above the inlet for the natural gas feed stream.
10. The process of claim 8, wherein the sub-cooled liquid is
sprayed into the first vessel.
11. The process of claim 8, wherein the sub-cooled liquid is a
natural gas liquid.
12. The process of claim 11, further comprising the step of cooling
the dehydrated gas removed from the first vessel to form a
two-phase mixture of gas and condensate at a temperature higher
than -56.degree. C. and separating condensate from the two-phase
mixture in a second flash tank.
13. The process of claim 12, further comprising the step of
recycling the separated condensate from the second flash tank as
the sub-cooled liquid.
14. The process of claim 1, wherein the natural gas feed stream
further includes sour gas species, and the process further
comprises the step of sweetening the stream of dehydrated gas
removed from the first vessel by removal of the sour gas species.
Description
RELATED APPLICATIONS
[0001] This application claims priority to co-pending U.S. patent
application 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 Ser.
No. 10/772,621 is herein incorporated by reference in its
entirety.
FIELD OF INVENTION
[0002] The present invention relates to a process for removing a
contaminant from a natural gas feed stream.
BACKGROUND
[0003] 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.
[0004] 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.
[0005] 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.
[0006] 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.
[0007] Natural gas also typically contains sour species, such as
hydrogen sulphide (H.sub.2S) and carbon dioxide (CO.sub.2). Such a
natural gas is classified as "sour gas". When the H.sub.2S and
CO.sub.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.sub.2S because of the bad odour that
is emitted even at low concentrations from an unsweetened gas.
H.sub.2S is a contaminant of natural gas that must be removed to
satisfy legal requirements, as H.sub.2S and its combustion products
of sulphur dioxide and sulphur trioxide are also toxic.
Furthermore, H.sub.2S 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.
[0008] 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.
SUMMARY OF THE INVENTION
[0009] 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.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] FIG. 1 is a schematic process flow diagram of one embodiment
of the invention.
[0011] FIG. 2 is a schematic process flow diagram of a further
embodiment of the invention.
DETAILED DESCRIPTION OF THE INVENTION
[0012] The present invention represents an improvement on the
process and device discussed in International patent application
publication No. 03/062 725.
[0013] Contaminants from a natural gas feed stream is removed by
forming a solid of the contaminant and suitably subsequently
melting the solid contaminant.
[0014] When the contaminant is water, one embodiment of the present
invention relates to a process for dehydrating a natural gas feed
stream.
[0015] 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.
[0016] In another embodiment of the present invention relates to a
process for sequentially dehydrating and sweetening the natural gas
feed stream.
[0017] 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.
[0018] 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.
[0019] 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.
[0020] 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.
[0021] 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.
[0022] The invention will now be described in more detail with
reference to the accompanying drawings.
[0023] Reference is now made to FIG. 1. 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, however, is lower
than its equilibrium dew point due to the formation of
hydrates.
[0024] In the embodiment as illustrated in FIG. 1, 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.
[0025] 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. Upon
expansion of the wet sour gas feed stream into 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.
[0026] 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.
[0027] 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 H.sub.2S and CO.sub.2, are formed. This is done to produce
hydrates and to prevent the formation of solids of sour species in
the first vessel 12.
[0028] Dry sour gas exits the first vessel 12 via dry sour gas
outlet 34. Typically the 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. The term "dry gas" is used to refer to
water-free gas.
[0029] 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.
[0030] 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-cooled liquid 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 through inlet 26. In case of spray cooling, the
natural gas feed stream can enter into the first vessel 12 at a
temperature that is at or above the hydrate-formation
temperature.
[0031] 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.
In the illustrated embodiment, 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.
[0032] 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.
[0033] The dry sour gas exits the second flash tank 40 via gas
outlet 47 and is fed through conduit 45 to the intermediate heat
exchanger 22 and from there to an end user (not shown). Conduit 45
may comprise a Joule-Thompson valve 48.
[0034] As observed earlier, the present invention relates to
dehydrating natural gas by forming hydrates. To prevent hydrates
from blocking outlet 28 and conduit 29, 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.
[0035] 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.
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 the
first vessel 12 through conduit 37 (after heating, not shown).
[0036] 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 the first
vessel 12 via inlet 20.
[0037] 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 C.sub.2, liquefied petroleum gas components,
C.sub.3 and C.sub.4 and C.sub.5+ hydrocarbon components.
[0038] Suitably, the warm liquid that is introduced into the first
vessel through inlet 18 is also a natural gas liquid.
[0039] 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 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.
[0040] 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. As with the first vessel 12, 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. As before with the first vessel 12,
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.
[0041] 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.
[0042] 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. Please note that
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.
[0043] Through outlet 52 a liquid is removed that contains the sour
species.
[0044] 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 through inlet 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 through inlet 49. In case of spray cooling, 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.
[0045] The sub-cooled liquid inlet 49 should be located in the
second vessel 14 above the dry sour gas inlet 46. In the
illustrated embodiment 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. 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.
[0046] Suitably, the sub-cooled liquid is part of the liquid
passing through conduit 43. In order to reduce the temperature 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).
[0047] Applicant had found that in particular the concentration of
C.sub.2-C.sub.4 hydrocarbon components in the liquid should be in
the range of from 0.5 to 1.5 mol per mol of CO.sub.2 in the feed
gas. The liquid in the second vessel 14 is the liquid sprayed in
the vessel through the inlet 49. Thus the concentration of
C.sub.2-C.sub.4 hydrocarbon components in the sub-cooled liquid
should be in the specified range. It will be understood that if the
concentration of C.sub.2-C.sub.4 hydrocarbon components in the
liquid stream in conduit 50 is too low, additional C.sub.2-C.sub.4
hydrocarbon components can be added to this stream.
[0048] To prevent sour species from blocking outlet 52, 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. Alternatively liquid
passing through conduit 31 can be used.
[0049] 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 through
outlet 52 can be recycled to inlet 26 of the first 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.
[0050] 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.
* * * * *