U.S. patent application number 13/565881 was filed with the patent office on 2014-02-06 for heavy hydrocarbon removal from a natural gas stream.
This patent application is currently assigned to AIR PRODUCTS AND CHEMICALS, INC.. The applicant listed for this patent is Fei Chen, Gowri Krishnamurthy, Xukun Luo, Christopher Michael Ott, Mark Julian Roberts. Invention is credited to Fei Chen, Gowri Krishnamurthy, Xukun Luo, Christopher Michael Ott, Mark Julian Roberts.
Application Number | 20140033762 13/565881 |
Document ID | / |
Family ID | 50024151 |
Filed Date | 2014-02-06 |
United States Patent
Application |
20140033762 |
Kind Code |
A1 |
Chen; Fei ; et al. |
February 6, 2014 |
Heavy Hydrocarbon Removal From A Natural Gas Stream
Abstract
A method and apparatus of removing heavy hydrocarbons from a
natural gas feed stream, the method comprising using first and
second hydrocarbon removal systems in series such that the first
system processes the natural gas feed stream to produce a heavy
hydrocarbon depleted natural gas stream and the second system
processes at least a portion of the heavy hydrocarbon depleted
natural gas stream from the first system to produce a natural gas
stream lean in heavy hydrocarbons, wherein one of said systems is a
adsorption system that comprises one or more beds of adsorbent for
adsorbing and thereby removing heavy hydrocarbons from a heavy
hydrocarbon containing natural gas, and the other of said systems
is a gas-liquid separation system for separating a heavy
hydrocarbon containing natural gas into a heavy hydrocarbon
depleted natural gas vapor and a heavy hydrocarbon enriched
liquid.
Inventors: |
Chen; Fei; (Whitehouse
Station, NJ) ; Luo; Xukun; (Allentown, PA) ;
Ott; Christopher Michael; (Laurys Station, PA) ;
Roberts; Mark Julian; (Kempton, PA) ; Krishnamurthy;
Gowri; (Allentown, PA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Chen; Fei
Luo; Xukun
Ott; Christopher Michael
Roberts; Mark Julian
Krishnamurthy; Gowri |
Whitehouse Station
Allentown
Laurys Station
Kempton
Allentown |
NJ
PA
PA
PA
PA |
US
US
US
US
US |
|
|
Assignee: |
AIR PRODUCTS AND CHEMICALS,
INC.
Allentown
PA
|
Family ID: |
50024151 |
Appl. No.: |
13/565881 |
Filed: |
August 3, 2012 |
Current U.S.
Class: |
62/620 |
Current CPC
Class: |
C10L 2290/06 20130101;
C10L 2290/545 20130101; F25J 2205/40 20130101; C10L 3/101 20130101;
C10L 2290/10 20130101; C10L 2290/48 20130101; F25J 3/065 20130101;
F25J 2230/30 20130101; F25J 2245/90 20130101; F25J 3/0233 20130101;
F25J 3/0635 20130101; F25J 2200/40 20130101; F25J 2205/60 20130101;
F25J 2210/06 20130101; F25J 3/061 20130101; F25J 2205/66 20130101;
F25J 3/0209 20130101; C10L 2290/12 20130101; F25J 1/0237 20130101;
F25J 2210/62 20130101; F25J 1/0238 20130101; F25J 2220/64 20130101;
F25J 1/0022 20130101; F25J 2220/60 20130101; F25J 1/0231 20130101;
C10L 3/10 20130101; F25J 3/0247 20130101; F25J 2245/02 20130101;
C10L 2290/542 20130101 |
Class at
Publication: |
62/620 |
International
Class: |
F25J 1/00 20060101
F25J001/00 |
Claims
1. A method of removing heavy hydrocarbons from a natural gas feed
stream, the method comprising the steps of using a first heavy
hydrocarbon removal system and a second heavy hydrocarbon removal
system to process the natural gas feed stream to produce a natural
gas stream lean in heavy hydrocarbons, wherein said first and
second systems are used in series such that the first system
processes the natural gas feed stream to produce a heavy
hydrocarbon depleted natural gas stream and the second system
processes at least a portion of the heavy hydrocarbon depleted
natural gas stream from the first system to produce the natural gas
stream lean in heavy hydrocarbons, and wherein one of said systems
is an adsorption system that comprises one or more beds of
adsorbent for adsorbing and thereby removing heavy hydrocarbons
from a heavy hydrocarbon containing natural gas, and the other of
said systems is a gas-liquid separation system for separating a
heavy hydrocarbon containing natural gas into a heavy hydrocarbon
depleted natural gas vapor and a heavy hydrocarbon enriched
liquid.
2. The method of claim 1, wherein the gas-liquid separation system
comprises a stripping column or a phase separator.
3. The method of claim 1, wherein the method is further a method of
producing a liquefied natural gas stream, and further comprises
liquefying at least a portion of the natural gas stream lean in
heavy hydrocarbons to produce the liquefied natural gas stream.
4. The method of claim 1, wherein the gas-liquid separation system
is the first heavy hydrocarbon removal system, the method
comprising the steps of: introducing the natural gas feed stream
into the gas-liquid separation system and separating the natural
gas feed stream into a heavy hydrocarbon depleted natural gas vapor
stream and a heavy hydrocarbon enriched liquid stream; and passing
at least a portion of the heavy hydrocarbon depleted natural gas
vapor stream through the one or more beds of the adsorption system
to adsorb heavy hydrocarbons therefrom, thereby producing the
natural gas stream lean in heavy hydrocarbons.
5. The method of claim 4, wherein the method further comprises
cooling the natural gas feed stream prior to said stream being
introduced into gas-liquid separation system, and warming the heavy
hydrocarbon depleted natural gas vapor stream prior to said stream
or portion thereof being passed through the one or more beds of the
adsorption system.
6. The method of claim 5, wherein the natural gas feed stream is
cooled and the heavy hydrocarbon depleted natural gas vapor stream
is warmed in an economizer heat exchanger via indirect heat
exchange between the natural gas feed stream and the heavy
hydrocarbon depleted natural gas vapor stream.
7. The method of claim 6, wherein the natural gas feed stream is
further cooled prior to being introduced into gas-liquid separation
system via expansion of the natural gas feed stream and/or via
direct or indirect heat exchange with one or more other
streams.
8. The method of claim 6, wherein the method further comprises
liquefying at least a portion of the natural gas stream lean in
heavy hydrocarbons.
9. The method of claim 5, wherein the method further comprises
cooling at least a portion of the natural gas stream lean in heavy
hydrocarbons to produce a cooled natural gas stream lean in heavy
hydrocarbons, and wherein the heavy hydrocarbon depleted natural
gas vapor stream is warmed and the at least a portion of the
natural gas stream lean in heavy hydrocarbons is cooled in an
economizer heat exchanger via indirect heat exchange between the
heavy hydrocarbon depleted natural gas vapor stream and the at
least a portion of the natural gas stream lean in heavy
hydrocarbons.
10. The method of claim 9, wherein the method further comprises
liquefying the cooled natural gas stream lean in heavy
hydrocarbons.
11. The method of claim 10, wherein the natural gas feed stream is
cooled and the cooled natural gas stream lean in heavy hydrocarbons
is liquefied in a liquefier, the natural gas feed stream being
introduced into a warm end of the liquefier and withdrawn from an
intermediate location of the liquefier, and the cooled natural gas
stream lean in heavy hydrocarbons being introduced into an
intermediate location of the liquefier and withdrawn from a cold
end of the liquefier.
12. The method of claim 4, wherein the gas-liquid separation system
is a stripping column, the method further comprising introducing a
stripping gas into the stripping column at a location below the
location at which the natural gas feed stream is introduced into
the stripping column.
13. The method of claim 6, wherein the gas liquid separation system
is a stripping column, the method further comprising introducing a
stripping gas into the stripping column at a location below the
location at which the natural gas feed stream is introduced into
the stripping column, and wherein the stripping gas comprises one
or more gases selected from the group consisting of: natural gas
taken from the natural gas feed stream prior to said stream being
cooled and introduced into the stripping column; a portion of the
natural gas stream depleted in heavy hydrocarbons that has been
warmed in the economiser heat exchanger; a portion of the natural
gas stream lean in heavy hydrocarbons; a gas obtained from
re-boiling all or a portion of the heavy hydrocarbon enriched
liquid stream; and a flash or boil-off gas obtained from a
liquefied natural gas.
14. The method of claim 9, wherein the gas liquid separation system
is a stripping column, the method further comprising introducing a
stripping gas into the stripping column at a location below the
location at which the natural gas feed stream is introduced into
the stripping column, and wherein the stripping gas comprises one
or more gases selected from the group consisting of: natural gas
taken from the natural gas feed stream prior to said stream being
cooled and introduced into the stripping column; a portion of the
natural gas stream lean in heavy hydrocarbons that is not cooled in
the economizer heat exchanger; a portion of the natural gas stream
depleted in heavy hydrocarbons that has been warmed in the
economiser heat exchanger; a gas obtained from re-boiling all or a
portion of the heavy hydrocarbon enriched liquid stream; and a
flash or boil-off gas obtained from a liquefied natural gas.
15. The method of claim 4, wherein the adsorption system is a
temperature swing adsorption system, and the method further
comprises regenerating the one or more beds of the temperature
swing adsorption system by passing a gas, selected from a portion
of the natural gas stream lean in heavy hydrocarbons or a flash or
boil off gas obtained from a liquefied natural gas, through the one
or more beds, the temperature of the one or more beds during
regeneration being higher than the temperature of the one or more
beds during adsorption of heavy hydrocarbons from the heavy
hydrocarbon depleted natural gas vapor stream or portion
thereof.
16. The method of claim 15, wherein the method further comprises
cooling and separating into liquid and vapor phases the gas
obtained from the one or more beds of the temperature swing
adsorption system during regeneration of said one or more beds, and
recycling the vapor phase into the natural gas feed stream prior to
the introduction thereof into the gas-liquid separation system.
17. The method of claim 15, wherein the gas liquid separation
system is a stripping column, and the method further comprises
cooling and separating into liquid and vapor phases the gas
obtained from the one or more beds of the temperature swing
adsorption system during regeneration of said one or more beds, and
introducing the vapor phase as a stripping gas into the stripping
column at a location below the location at which the natural gas
feed stream is introduced into the stripping column.
18. The method of claim 1, wherein the adsorption system is the
first heavy hydrocarbon removal system, the method comprising the
steps of: passing the natural gas feed stream through the one or
more beds of the adsorption system to adsorb heavy hydrocarbons
therefrom, thereby producing a heavy hydrocarbon depleted natural
gas stream; and introducing at least a portion of the heavy
hydrocarbon depleted natural gas stream into the gas-liquid
separation system and separating said stream or portion thereof
into a natural gas vapor stream that is further depleted in heavy
hydrocarbons, thereby providing the natural gas stream lean in
heavy hydrocarbons, and a heavy hydrocarbon enriched liquid
stream.
19. The method of claim 18, wherein the method further comprises
cooling the heavy hydrocarbon depleted natural gas stream or
portion thereof introduced into gas-liquid separation system prior
to said stream or portion thereof being introduced into gas-liquid
separation system.
20. The method of claim 19, wherein the method further comprises
liquefying the natural gas stream lean in heavy hydrocarbons.
21. The method of claim 20, wherein the heavy hydrocarbon depleted
natural gas stream or portion thereof is cooled and the natural gas
stream lean in heavy hydrocarbons is liquefied in a liquefier, the
heavy hydrocarbon depleted natural gas stream or portion thereof
being introduced into a warm end of the liquefier and withdrawn
from an intermediate location of the liquefier, and the natural gas
stream lean in heavy hydrocarbons being introduced into an
intermediate location of the liquefier and withdrawn from a cold
end of the liquefier.
22. The method of claim 18, wherein the gas liquid separation
system is a stripping column, the method further comprising
introducing a stripping gas into the stripping column at a location
below the location at which the heavy hydrocarbon depleted natural
gas stream or portion thereof is introduced into the stripping
column.
23. The method of claim 22, wherein the stripping gas comprises one
or more gases selected from the group consisting of: natural gas
taken from the natural gas feed stream prior to said stream being
passed through the one or more beds of the adsorption system; a
portion of the heavy hydrocarbon depleted natural gas stream; a gas
obtained from re-boiling all or a portion of the heavy hydrocarbon
enriched liquid stream; and a flash or boil-off gas obtained from a
liquefied natural gas.
24. The method of claim 18, wherein the adsorption system is a
temperature swing adsorption system, and the method further
comprises regenerating the one or more beds of the temperature
swing adsorption system by passing a gas, selected from a portion
of the heavy hydrocarbon depleted natural gas stream or a flash or
boil off gas obtained from a liquefied natural gas, through the one
or more beds, the temperature of the one or more beds during
regeneration being higher than the temperature of the one or more
beds during adsorption of heavy hydrocarbons from the natural gas
feed stream.
25. The method of claim 24, wherein the method further comprises
cooling and separating into liquid and vapor phases the gas
obtained from the one or more beds of the temperature swing
adsorption system during regeneration of said one or more beds, and
recycling the vapor phase into the natural gas feed stream prior to
said stream being passed through the one or more beds of the
temperature swing adsorption system.
26. The method of claim 24, wherein the gas liquid separation
system is a stripping column, and the method further comprises
introducing a stripping gas into the stripping column at a location
below the location at which the heavy hydrocarbon depleted natural
gas stream or portion thereof is introduced into the stripping
column, wherein said stripping gas comprises: the gas obtained from
the one or more beds of the temperature swing adsorption system
during regeneration of said one or more beds; or the vapor phase
obtained from cooling and separating into liquid and vapor phases
the gas obtained from the one or more beds of the temperature swing
adsorption system during regeneration of said one or more beds.
27. The method of claim 1, wherein the natural gas feed stream is
lean in aliphatic hydrocarbons having from 3 to 5 carbon atoms in
total.
28. An apparatus for removing heavy hydrocarbons from a natural gas
feed stream, the apparatus comprising a first heavy hydrocarbon
removal system and a second heavy hydrocarbon removal system for
processing the natural gas feed stream to produce a natural gas
stream lean in heavy hydrocarbons, wherein said first and second
systems are connected in fluid flow communication with each other
and are arranged in series such that in use the first system
processes the natural gas feed stream to produce a heavy
hydrocarbon depleted natural gas stream and the second system
processes at least a portion of the heavy hydrocarbon depleted
natural gas stream from the first system to produce the natural gas
stream lean in heavy hydrocarbons, and wherein one of said systems
is an adsorption system comprising one or more beds of adsorbent
for adsorbing and thereby removing heavy hydrocarbons from a heavy
hydrocarbon containing natural gas, and the other of said systems
is a gas-liquid separation system for separating a heavy
hydrocarbon containing natural gas into a heavy hydrocarbon
depleted natural gas vapor and a heavy hydrocarbon enriched
liquid.
29. An apparatus according to claim 28, wherein the gas-liquid
separation system comprises a stripping column or a phase
separator.
30. An apparatus according to claim 28, wherein the apparatus is
further for producing a liquefied natural gas stream, and further
comprises a liquefier connected in fluid flow communication with
the second heavy hydrocarbon removal system for receiving and
liquefying at least a portion of the natural gas stream lean in
heavy hydrocarbons to produce the liquefied natural gas stream.
31. An apparatus according to claim 28, wherein the gas-liquid
separation system is the first heavy hydrocarbon removal system,
the apparatus comprising: a gas-liquid separation system for
receiving and separating the natural gas feed stream into a heavy
hydrocarbon depleted natural gas vapor stream and a heavy
hydrocarbon enriched liquid stream; an adsorption system, in fluid
flow communication with the gas-liquid separation system, for
receiving at least a portion of the heavy hydrocarbon depleted
natural gas vapor stream, and comprising one or more beds of
adsorbent for adsorbing heavy hydrocarbons from said at least a
portion of the heavy hydrocarbon depleted natural gas vapor stream,
to thereby produce the natural gas stream lean in heavy
hydrocarbons; and an economizer heat exchanger for cooling the
natural gas feed stream, prior to said stream being introduced into
gas-liquid separation system, and warming the heavy hydrocarbon
depleted natural gas vapor stream, prior to said stream or portion
thereof being passed through the one or more beds of the adsorption
system, via indirect heat exchange between the natural gas feed
stream and the heavy hydrocarbon depleted natural gas vapor
stream.
32. An apparatus according to claim 28, wherein the gas-liquid
separation system is the first heavy hydrocarbon removal system,
the apparatus comprising: a gas-liquid separation system for
receiving and separating the natural gas feed stream into a heavy
hydrocarbon depleted natural gas vapor stream and a heavy
hydrocarbon enriched liquid stream; an adsorption system, in fluid
flow communication with the gas-liquid separation system, for
receiving at least a portion of the heavy hydrocarbon depleted
natural gas vapor stream, and comprising one or more beds of
adsorbent for adsorbing heavy hydrocarbons from said at least a
portion of the heavy hydrocarbon depleted natural gas vapor stream,
to thereby produce the natural gas stream lean in heavy
hydrocarbons; and an economizer heat exchanger for warming the
heavy hydrocarbon depleted natural gas vapor stream, prior to said
stream or portion thereof being passed through the one or more beds
of the adsorption system, and cooling at least a portion of the
natural gas stream lean in heavy hydrocarbons via indirect heat
exchange between the heavy hydrocarbon depleted natural gas vapor
stream and the at least a portion of the natural gas stream lean in
heavy hydrocarbons.
33. An apparatus according to claim 28, wherein the adsorption
system is the first heavy hydrocarbon removal system, the apparatus
comprising: an adsorption system for receiving the natural gas feed
stream, and comprising one or more beds of adsorbent for adsorbing
heavy hydrocarbons from the natural gas feed stream, to thereby
produce a heavy hydrocarbon depleted natural gas stream; and a
gas-liquid separation system, in fluid flow communication with the
adsorption system, for receiving at least a portion of the heavy
hydrocarbon depleted natural gas stream and separating said stream
or portion thereof into a heavy hydrocarbon enriched liquid stream
and a natural gas vapor stream that is further depleted in heavy
hydrocarbons, the latter providing the natural gas stream lean in
heavy hydrocarbons.
Description
BACKGROUND OF THE INVENTION
[0001] The present invention relates to a method and apparatus for
removing heavy hydrocarbons (i.e. aliphatic hydrocarbons having six
or more carbon atoms in total and aromatic hydrocarbons--also
referred to herein as C6+ hydrocarbons and aromatics, respectively)
from a natural gas stream. In certain preferred embodiments, it
concerns a method and apparatus for removing heavy hydrocarbons
from and liquefying a natural gas stream. The natural gas stream
may be a stream that is already lean in aliphatic hydrocarbons
having from 3 to 5 carbon atoms in total (also referred to herein
as C3-C5 hydrocarbons).
[0002] It is important to remove heavy hydrocarbons from a natural
gas stream prior to liquefying the natural gas stream, as otherwise
the heavy hydrocarbons may freeze in the liquefied natural gas
(LNG) stream. It is also known that the heavy hydrocarbon
components contained in natural gas feed streams can be removed
using temperature swing adsorption (TSA) or by using a scrub
column.
[0003] As is well known in the art, a scrub column is a type of
separation device for removing less volatile components from a feed
stream to produce a gas stream depleted in said less volatile
components. The feed stream is introduced (as a gaseous stream or
as two-phase, gas-liquid stream) into the scrub column, where it is
brought into contact with a liquid reflux stream. The reflux stream
is introduced into the column at a location that is above the
location at which the feed stream is introduced, so that the
falling stream of liquid comes into countercurrent contact with the
rising stream of vapor originating from the feed stream, thereby
"scrubbing" said vapor stream (i.e. removing at least some of the
less volatile components from the vapor stream). Typically, the
scrub column contains one or more separation stages, positioned
below the location at which the reflux stream is introduced and
above the location at which the feed stream is introduced, and
composed of trays, packing, or some other form of insert that acts
to increase the amount and/or duration of contact between the
rising vapor and falling reflux streams, thereby increasing mass
transfer between the streams.
[0004] In the case of treatment of a natural gas stream, a scrub
column can be effective in removing all the heavy hydrocarbon
components from the stream, but it must be operated at pressures
lower than the mixture's critical pressure in order to achieve
gas-liquid phase separation. The operating pressure of the column
is lower than the optimum natural gas liquefaction pressure, which
leads to lower liquefaction process energy efficiency. Also, stable
scrub column operation requires sufficient liquid (i.e. reflux) to
vapor flow ratio in order to avoid column dryout. The reflux for
the column is typically provided by condensing a portion of the gas
stream from the top of the column, and if the natural gas feed is
in particular too lean in C3-C5 hydrocarbons (i.e. the
concentration of these components is too low) it becomes very
energy inefficient to maintain the required liquid to vapor flow
ratio inside the column. Therefore, if the natural gas feed is lean
in C3-C5 hydrocarbons and contains high concentrations of heavy
hydrocarbons the conventional scrub column technology is energy
inefficient.
[0005] As is well known in the art, TSA involves at least two
steps. During a first step (typically referred to as the
"adsorption step") a gaseous feed stream is passed through one or
more beds of adsorbent at a first temperature and for a first
period of time, during which the adsorbent selectively adsorbs one
or more components of the feed, thereby providing a gaseous steam
depleted in the adsorbed components. At the end of said adsorption
step (which will typically be when the adsorbent is approaching
saturation) introduction of the feed stream into the beds in
question is stopped. Then, in a subsequent step (typically referred
to as a "desorption step" or "regeneration step") the beds are
regenerated by desorbing the adsorbed components from the bed(s) at
a second, higher temperature, and for a second period of time,
sufficient to desorb enough of the adsorbed components to allow the
bed or beds in question to be used for another adsorption step.
Typically, during the regeneration step another gas stream
(referred to as a "regeneration gas") is passed through the bed to
aid desorption and the removal of the desorbed components. In some
TSA processes (often referred to as temperature pressure swing
adsorption, or TPSA, processes), the regeneration step is also
carried out at a lower pressure than the pressure during the
adsorption step. In most TSA processes it is also the case that two
or more beds of adsorbent are used in parallel, with the timings of
the adsorption steps being staggered between the beds so that at
any point there is always at least one bed undergoing an adsorption
step, thereby allowing continuous processing of a feed stream. Each
adsorbent bed may contain a single type of adsorbent material, or
may contain more than one type of adsorbent material, and where
there is more than one bed different beds may contain different
materials (in particular where there are two or more beds arranged
in series). Suitable types of adsorbent material for selectively
adsorbing heavy hydrocarbons are well known.
[0006] TSA can be used to effectively remove heavy hydrocarbons
from a natural gas stream at the optimum pressure for subsequent
liquefaction of the stream, allowing for high liquefaction process
energy efficiency. However, if the concentrations of heavy
hydrocarbons are too high then the TSA vessel size and the
regeneration gas requirements become economically infeasible.
Therefore, TSA is effective in removing heavy hydrocarbons in
natural gas liquefaction processes only when the concentrations of
the heavy hydrocarbons are relatively low. In addition, a further
complication is that the TSA adsorbent beds used for hydrocarbon
removal need to be regenerated at high temperatures (i.e.
450-600.degree. F., 232-315.degree. C.). At these high temperatures
there is a risk of the adsorbed heavy hydrocarbons cracking and
producing coke, which will deactivate the adsorbent and be
detrimental to productivity.
[0007] Prior art in this field includes documents WO 2009/074737,
WO 2007/018677, U.S. Pat. No. 3,841,058, and U.S. Pat. No.
5,486,227 (which describe processes in which adsorption systems are
used); and U.S. Pat. No. 7,600,395, U.S. Pat. No. 5,325,673, WO
2006/061400, US 2006/0042312, and US 2005/0072186 (which describe
processes in which scrub columns are employed).
[0008] Accordingly, there is a need in the art for improved methods
and apparatus for removing heavy hydrocarbons from natural gas
streams, in particular where the natural gas stream has a
relatively high concentration of heavy hydrocarbons or where the
exact composition of the natural gas stream is liable to vary
and/or may otherwise be unknown such that there is a risk of said
stream having (at least at times) a relatively high concentration
of heavy hydrocarbons.
BRIEF SUMMARY OF THE INVENTION
[0009] According to a first aspect of the present invention, there
is provided a method of removing heavy hydrocarbons from a natural
gas feed stream, the method comprising the steps of using a first
heavy hydrocarbon removal system and a second heavy hydrocarbon
removal system to process the natural gas feed stream to produce a
natural gas stream lean in heavy hydrocarbons, wherein said first
and second systems are used in series such that the first system
processes the natural gas feed stream to produce a heavy
hydrocarbon depleted natural gas stream and the second system
processes at least a portion of the heavy hydrocarbon depleted
natural gas stream from the first system to produce the natural gas
stream lean in heavy hydrocarbons, and wherein one of said systems
is an adsorption system that comprises one or more beds of
adsorbent for adsorbing and thereby removing heavy hydrocarbons
from a heavy hydrocarbon containing natural gas, and the other of
said systems is a gas-liquid separation system for separating a
heavy hydrocarbon containing natural gas into a heavy hydrocarbon
depleted natural gas vapor and a heavy hydrocarbon enriched
liquid.
[0010] The gas-liquid separation system may be any type of system
that is suitable for separating a heavy hydrocarbon containing
natural gas (typically a partially condensed heavy hydrocarbon
containing natural gas) into a heavy hydrocarbon depleted natural
gas vapor and a heavy hydrocarbon enriched liquid. For example, the
gas-liquid separation system may comprise a stripping column, a
scrubbing column, or a phase separator. Preferably, however, the
gas-liquid separation system comprises a stripping column or a
phase separator.
[0011] The adsorption system may be any type of system that
comprises one or more beds of adsorbent suitable for adsorbing and
thereby removing heavy hydrocarbons from a heavy hydrocarbon
containing natural gas. Preferably, however, the adsorption system
comprises a temperature swing adsorption (TSA) system.
[0012] The term "portion", as used herein in reference to a stream,
and unless otherwise indicated, refers to a portion of a stream
that preferably is a divided portion. A divided portion of a stream
is a portion of a stream obtained by dividing said stream into two
or more portions that retain the same molecular composition (i.e.
that have the same components, in the same mole fractions) as said
stream from which they have been divided. Thus, for example, in the
first aspect of the invention it is preferably the case that the
second heavy hydrocarbon removal system either processes the whole
of the heavy hydrocarbon depleted natural gas stream from the first
heavy hydrocarbon removal system, or processes a divided portion of
the heavy hydrocarbon depleted natural gas stream from the first
heavy hydrocarbon removal system.
[0013] The heavy hydrocarbon components present in the natural gas
feed stream that are to be removed comprise one or more
hydrocarbons selected from the group consisting of: aliphatic
hydrocarbons having six or more carbon atoms in total; and aromatic
hydrocarbons. The natural gas stream lean in heavy hydrocarbons,
obtained from the second heavy hydrocarbon removal system, is
depleted in each of these heavy hydrocarbon components relative to
the natural gas feed stream, such that the mole fraction of each of
these components in the natural gas stream lean in heavy
hydrocarbons is less than that in the natural gas feed stream. The
heavy hydrocarbon depleted natural gas stream, obtained from the
first heavy hydrocarbon removal system, is depleted in at least
some of these heavy hydrocarbon components relative to the natural
gas feed stream, such that the total concentration of these
components (i.e. the combined mole fraction of these components) in
the heavy hydrocarbon depleted natural gas stream is less than that
in the natural gas feed stream, although of course not let as low
as that in the natural gas stream lean in heavy hydrocarbons
obtained from the second heavy hydrocarbon removal system (via
removal of heavy hydrocarbons from the heavy hydrocarbon depleted
natural gas stream). Preferably, the heavy hydrocarbon depleted
natural gas stream, obtained from the first heavy hydrocarbon
removal system, is depleted in each of these heavy hydrocarbon
components relative to the natural gas feed stream.
[0014] In certain embodiments the method may be used to remove
heavy hydrocarbons from a natural gas feed stream that has a
composition that would render it problematic to treat using a TSA
system on its own or scrubbing column on its own. For example, the
natural gas feed stream may be lean in aliphatic hydrocarbons
having from 3 to 5 carbon atoms in total, such as for example where
the total concentration of any and all C3-C5 hydrocarbons in the
feed stream (i.e. the concentration of any and all C3-C5
hydrocarbons in the feed stream when taken together) is 10 mol % or
less, or 5 mol % or less, or 3 mol % or less. Likewise, the natural
gas feed stream may, alternatively or additionally, have a total
concentration of heavy hydrocarbon components of 100 ppm or more,
or 250 ppm or more (i.e. the concentration of all aromatics and C6+
aliphatic hydrocarbons in the feed stream, taken together, may
total 100 ppm or more, or 250 ppm or more).
[0015] In certain preferred embodiments, the method further
comprises liquefying at least a portion of the natural gas stream
lean in heavy hydrocarbons to produce a liquefied natural gas
stream.
[0016] In preferred embodiments, the composition of the natural gas
stream lean in heavy hydrocarbons is such that any and all heavy
hydrocarbons that are still present in said stream are present in
said stream at concentrations below (and most preferably well
below) their respective solid solubility limits at the temperature
of the liquefied natural gas stream.
[0017] In one embodiment, the gas-liquid separation system is the
first heavy hydrocarbon removal system, and the method comprises
the steps of: introducing the natural gas feed stream into the
gas-liquid separation system and separating the natural gas feed
stream into a heavy hydrocarbon depleted natural gas vapor stream
and a heavy hydrocarbon enriched liquid stream; and passing at
least a portion of the heavy hydrocarbon depleted natural gas vapor
stream through the one or more beds of the adsorption system to
adsorb heavy hydrocarbons therefrom, thereby producing the natural
gas stream lean in heavy hydrocarbons. The method may further
comprise cooling the natural gas feed stream prior to said stream
being introduced into gas-liquid separation system, and warming the
heavy hydrocarbon depleted natural gas vapor stream prior to said
stream or portion thereof being passed through the one or more beds
of the adsorption system, wherein the natural gas feed stream is
cooled and the heavy hydrocarbon depleted natural gas vapor stream
is warmed in an economizer heat exchanger via indirect heat
exchange between the natural gas feed stream and the heavy
hydrocarbon depleted natural gas vapor stream. Alternatively, the
method may further comprise warming the heavy hydrocarbon depleted
natural gas vapor stream prior to said stream or portion thereof
being passed through the one or more beds of the adsorption system,
and cooling at least a portion of the natural gas stream lean in
heavy hydrocarbons to produce a cooled natural gas stream lean in
heavy hydrocarbons, wherein the heavy hydrocarbon depleted natural
gas vapor stream is warmed and the at least a portion of the
natural gas stream lean in heavy hydrocarbons is cooled in an
economizer heat exchanger via indirect heat exchange between the
heavy hydrocarbon depleted natural gas vapor stream and the at
least a portion of the natural gas stream lean in heavy
hydrocarbons.
[0018] In an alternative embodiment, the adsorption system is the
first heavy hydrocarbon removal system, and the method comprises
the steps of: passing the natural gas feed stream through the one
or more beds of the adsorption system to adsorb heavy hydrocarbons
therefrom, thereby producing a heavy hydrocarbon depleted natural
gas stream; and introducing at least a portion of the heavy
hydrocarbon depleted natural gas stream into the gas-liquid
separation system and separating said stream or portion thereof
into a natural gas vapor stream that is further depleted in heavy
hydrocarbons, thereby providing the natural gas stream lean in
heavy hydrocarbons, and a heavy hydrocarbon enriched liquid
stream.
[0019] According to a second aspect of the present invention, there
is provided an apparatus for removing heavy hydrocarbons from a
natural gas feed stream, the apparatus comprising a first heavy
hydrocarbon removal system and a second heavy hydrocarbon removal
system for processing the natural gas feed stream to produce a
natural gas stream lean in heavy hydrocarbons, wherein said first
and second systems are connected in fluid flow communication with
each other and are arranged in series such that in use the first
system processes the natural gas feed stream to produce a heavy
hydrocarbon depleted natural gas stream and the second system
processes at least a portion of the heavy hydrocarbon depleted
natural gas stream from the first system to produce the natural gas
stream lean in heavy hydrocarbons, and wherein one of said systems
is an adsorption system comprising one or more beds of adsorbent
for adsorbing and thereby removing heavy hydrocarbons from a heavy
hydrocarbon containing natural gas, and the other of said systems
is a gas-liquid separation system for separating a heavy
hydrocarbon containing natural gas into a heavy hydrocarbon
depleted natural gas vapor and a heavy hydrocarbon enriched
liquid.
[0020] The apparatus according to the second aspect of the
invention is suitable for carrying out the method according to the
first aspect of the invention. Preferred embodiments of the
apparatus according to the second aspect will therefore be apparent
from the above discussion of preferred embodiments of the method
according to the first aspect. In particular:
[0021] Preferably, the gas-liquid separation system comprises a
stripping column or a phase separator.
[0022] Preferably, the adsorption system comprises a temperature
swing adsorption system.
[0023] Preferably, the apparatus further comprises a liquefier
connected in fluid flow communication with the second heavy
hydrocarbon removal system for receiving and liquefying at least a
portion of the natural gas stream lean in heavy hydrocarbons to
produce a liquefied natural gas stream.
[0024] In one embodiment, the gas-liquid separation system is the
first heavy hydrocarbon removal system, and the apparatus
comprises: a gas-liquid separation system for receiving and
separating the natural gas feed stream into a heavy hydrocarbon
depleted natural gas vapor stream and a heavy hydrocarbon enriched
liquid stream; and an adsorption system, in fluid flow
communication with the gas-liquid separation system, for receiving
at least a portion of the heavy hydrocarbon depleted natural gas
vapor stream, and comprising one or more beds of adsorbent for
adsorbing heavy hydrocarbons from said at least a portion of the
heavy hydrocarbon depleted natural gas vapor stream, to thereby
produce the natural gas stream lean in heavy hydrocarbons. The
apparatus may further comprise an economizer heat exchanger for
cooling the natural gas feed stream, prior to said stream being
introduced into gas-liquid separation system, and warming the heavy
hydrocarbon depleted natural gas vapor stream, prior to said stream
or portion thereof being passed through the one or more beds of the
adsorption system, via indirect heat exchange between the natural
gas feed stream and the heavy hydrocarbon depleted natural gas
vapor stream. Alternatively, the apparatus may further comprise an
economizer heat exchanger for warming the heavy hydrocarbon
depleted natural gas vapor stream, prior to said stream or portion
thereof being passed through the one or more beds of the adsorption
system, and cooling at least a portion of the natural gas stream
lean in heavy hydrocarbons via indirect heat exchange between the
heavy hydrocarbon depleted natural gas vapor stream and the at
least a portion of the natural gas stream lean in heavy
hydrocarbons.
[0025] In an alternative embodiment, the adsorption system is the
first heavy hydrocarbon removal system, and the apparatus
comprises: an adsorption system for receiving the natural gas feed
stream, and comprising one or more beds of adsorbent for adsorbing
heavy hydrocarbons from the natural gas feed stream, to thereby
produce a heavy hydrocarbon depleted natural gas stream; and a
gas-liquid separation system, in fluid flow communication with the
adsorption system, for receiving at least a portion of the heavy
hydrocarbon depleted natural gas stream and separating said stream
or portion thereof into a heavy hydrocarbon enriched liquid stream
and a natural gas vapor stream that is further depleted in heavy
hydrocarbons, the latter providing the natural gas stream lean in
heavy hydrocarbons.
[0026] According to a third aspect of the present invention, there
is provided a method for removing heavy hydrocarbons from and
liquefying a natural gas stream, the method comprising: passing the
natural gas stream through an adsorption system that comprises one
or more beds of adsorbent for adsorbing and thereby removing heavy
hydrocarbons from the natural gas stream, to thereby provide a
natural gas stream depleted in heavy hydrocarbons; liquefying the
natural gas stream depleted in heavy hydrocarbons to produce a
liquefied natural gas stream; and regenerating the one or more beds
of the temperature swing adsorption system by passing a flash or
boil off gas obtained from the liquefied natural gas through the
one or more beds. Preferably the adsorption system is a temperature
swing adsorption system, the temperature of the one or more beds
during regeneration being higher than the temperature of the one or
more beds during adsorption of heavy hydrocarbons from the natural
gas stream.
[0027] Preferred aspects of the present invention include the
following aspects, numbered #1 to #33: [0028] #1. A method of
removing heavy hydrocarbons from a natural gas feed stream, the
method comprising the steps of using a first heavy hydrocarbon
removal system and a second heavy hydrocarbon removal system to
process the natural gas feed stream to produce a natural gas stream
lean in heavy hydrocarbons, wherein said first and second systems
are used in series such that the first system processes the natural
gas feed stream to produce a heavy hydrocarbon depleted natural gas
stream and the second system processes at least a portion of the
heavy hydrocarbon depleted natural gas stream from the first system
to produce the natural gas stream lean in heavy hydrocarbons, and
wherein one of said systems is an adsorption system that comprises
one or more beds of adsorbent for adsorbing and thereby removing
heavy hydrocarbons from a heavy hydrocarbon containing natural gas,
and the other of said systems is a gas-liquid separation system for
separating a heavy hydrocarbon containing natural gas into a heavy
hydrocarbon depleted natural gas vapor and a heavy hydrocarbon
enriched liquid. [0029] #2. The method of Aspect #1, wherein the
gas-liquid separation system comprises a stripping column or a
phase separator. [0030] #3. The method of Aspect #1 or #2, wherein
the method is further a method of producing a liquefied natural gas
stream, and further comprises liquefying at least a portion of the
natural gas stream lean in heavy hydrocarbons to produce the
liquefied natural gas stream. [0031] #4. The method of any one of
Aspects #1 to #3, wherein the gas-liquid separation system is the
first heavy hydrocarbon removal system, the method comprising the
steps of:
[0032] introducing the natural gas feed stream into the gas-liquid
separation system and separating the natural gas feed stream into a
heavy hydrocarbon depleted natural gas vapor stream and a heavy
hydrocarbon enriched liquid stream; and
[0033] passing at least a portion of the heavy hydrocarbon depleted
natural gas vapor stream through the one or more beds of the
adsorption system to adsorb heavy hydrocarbons therefrom, thereby
producing the natural gas stream lean in heavy hydrocarbons. [0034]
#5. The method of Aspect #4, wherein the method further comprises
cooling the natural gas feed stream prior to said stream being
introduced into gas-liquid separation system, and warming the heavy
hydrocarbon depleted natural gas vapor stream prior to said stream
or portion thereof being passed through the one or more beds of the
adsorption system. [0035] #6. The method of Aspect #5, wherein the
natural gas feed stream is cooled and the heavy hydrocarbon
depleted natural gas vapor stream is warmed in an economizer heat
exchanger via indirect heat exchange between the natural gas feed
stream and the heavy hydrocarbon depleted natural gas vapor stream.
[0036] #7. The method of Aspect #6, wherein the natural gas feed
stream is further cooled prior to being introduced into gas-liquid
separation system via expansion of the natural gas feed stream
and/or via direct or indirect heat exchange with one or more other
streams. [0037] #8. The method of Aspect #6 or #7, wherein the
method further comprises liquefying at least a portion of the
natural gas stream lean in heavy hydrocarbons. [0038] #9. The
method of Aspect #5, wherein the method further comprises cooling
at least a portion of the natural gas stream lean in heavy
hydrocarbons to produce a cooled natural gas stream lean in heavy
hydrocarbons, and wherein the heavy hydrocarbon depleted natural
gas vapor stream is warmed and the at least a portion of the
natural gas stream lean in heavy hydrocarbons is cooled in an
economizer heat exchanger via indirect heat exchange between the
heavy hydrocarbon depleted natural gas vapor stream and the at
least a portion of the natural gas stream lean in heavy
hydrocarbons. [0039] #10. The method of Aspect #9, wherein the
method further comprises liquefying the cooled natural gas stream
lean in heavy hydrocarbons. [0040] #11. The method of Aspect #10,
wherein the natural gas feed stream is cooled and the cooled
natural gas stream lean in heavy hydrocarbons is liquefied in a
liquefier, the natural gas feed stream being introduced into a warm
end of the liquefier and withdrawn from an intermediate location of
the liquefier, and the cooled natural gas stream lean in heavy
hydrocarbons being introduced into an intermediate location of the
liquefier and withdrawn from a cold end of the liquefier. [0041]
#12. The method of any one of Aspects #4 to #11, wherein the
gas-liquid separation system is a stripping column, the method
further comprising introducing a stripping gas into the stripping
column at a location below the location at which the natural gas
feed stream is introduced into the stripping column. [0042] #13.
The method of any one of Aspects #6 to #8, wherein the gas liquid
separation system is a stripping column, the method further
comprising introducing a stripping gas into the stripping column at
a location below the location at which the natural gas feed stream
is introduced into the stripping column, and wherein the stripping
gas comprises one or more gases selected from the group consisting
of: natural gas taken from the natural gas feed stream prior to
said stream being cooled and introduced into the stripping column;
a portion of the natural gas stream depleted in heavy hydrocarbons
that has been warmed in the economiser heat exchanger; a portion of
the natural gas stream lean in heavy hydrocarbons; a gas obtained
from re-boiling all or a portion of the heavy hydrocarbon enriched
liquid stream; and a flash or boil-off gas obtained from a
liquefied natural gas. [0043] #14. The method of any one of Aspects
#9 to #11, wherein the gas liquid separation system is a stripping
column, the method further comprising introducing a stripping gas
into the stripping column at a location below the location at which
the natural gas feed stream is introduced into the stripping
column, and wherein the stripping gas comprises one or more gases
selected from the group consisting of: natural gas taken from the
natural gas feed stream prior to said stream being cooled and
introduced into the stripping column; a portion of the natural gas
stream lean in heavy hydrocarbons that is not cooled in the
economizer heat exchanger; a portion of the natural gas stream
depleted in heavy hydrocarbons that has been warmed in the
economiser heat exchanger; a gas obtained from re-boiling all or a
portion of the heavy hydrocarbon enriched liquid stream; and a
flash or boil-off gas obtained from a liquefied natural gas. [0044]
#15. The method of any one of Aspects #4 to #14, wherein the
adsorption system is a temperature swing adsorption system, and the
method further comprises regenerating the one or more beds of the
temperature swing adsorption system by passing a gas, selected from
a portion of the natural gas stream lean in heavy hydrocarbons or a
flash or boil off gas obtained from a liquefied natural gas,
through the one or more beds, the temperature of the one or more
beds during regeneration being higher than the temperature of the
one or more beds during adsorption of heavy hydrocarbons from the
heavy hydrocarbon depleted natural gas vapor stream or portion
thereof. [0045] #16. The method of Aspect #15, wherein the method
further comprises cooling and separating into liquid and vapor
phases the gas obtained from the one or more beds of the
temperature swing adsorption system during regeneration of said one
or more beds, and recycling the vapor phase into the natural gas
feed stream prior to the introduction thereof into the gas-liquid
separation system. [0046] #17. The method of Aspect #15, wherein
the gas liquid separation system is a stripping column, and the
method further comprises cooling and separating into liquid and
vapor phases the gas obtained from the one or more beds of the
temperature swing adsorption system during regeneration of said one
or more beds, and introducing the vapor phase as a stripping gas
into the stripping column at a location below the location at which
the natural gas feed stream is introduced into the stripping
column. [0047] #18. The method of any one of Aspects #1 to #3,
wherein the adsorption system is the first heavy hydrocarbon
removal system, the method comprising the steps of:
[0048] passing the natural gas feed stream through the one or more
beds of the adsorption system to adsorb heavy hydrocarbons
therefrom, thereby producing a heavy hydrocarbon depleted natural
gas stream; and
[0049] introducing at least a portion of the heavy hydrocarbon
depleted natural gas stream into the gas-liquid separation system
and separating said stream or portion thereof into a natural gas
vapor stream that is further depleted in heavy hydrocarbons,
thereby providing the natural gas stream lean in heavy
hydrocarbons, and a heavy hydrocarbon enriched liquid stream.
[0050] #19. The method of Aspect #18, wherein the method further
comprises cooling the heavy hydrocarbon depleted natural gas stream
or portion thereof introduced into gas-liquid separation system
prior to said stream or portion thereof being introduced into
gas-liquid separation system. [0051] #20. The method of Aspect #19,
wherein the method further comprises liquefying the natural gas
stream lean in heavy hydrocarbons. [0052] #21. The method of Aspect
#20, wherein the heavy hydrocarbon depleted natural gas stream or
portion thereof is cooled and the natural gas stream lean in heavy
hydrocarbons is liquefied in a liquefier, the heavy hydrocarbon
depleted natural gas stream or portion thereof being introduced
into a warm end of the liquefier and withdrawn from an intermediate
location of the liquefier, and the natural gas stream lean in heavy
hydrocarbons being introduced into an intermediate location of the
liquefier and withdrawn from a cold end of the liquefier. [0053]
#22. The method of any one of Aspects #18 to #21, wherein the gas
liquid separation system is a stripping column, the method further
comprising introducing a stripping gas into the stripping column at
a location below the location at which the heavy hydrocarbon
depleted natural gas stream or portion thereof is introduced into
the stripping column. [0054] #23. The method of Aspect #22, wherein
the stripping gas comprises one or more gases selected from the
group consisting of: natural gas taken from the natural gas feed
stream prior to said stream being passed through the one or more
beds of the adsorption system; a portion of the heavy hydrocarbon
depleted natural gas stream; a gas obtained from re-boiling all or
a portion of the heavy hydrocarbon enriched liquid stream; and a
flash or boil-off gas obtained from a liquefied natural gas. [0055]
#24. The method of any one of Aspects #18 to #23, wherein the
adsorption system is a temperature swing adsorption system, and the
method further comprises regenerating the one or more beds of the
temperature swing adsorption system by passing a gas, selected from
a portion of the heavy hydrocarbon depleted natural gas stream or a
flash or boil off gas obtained from a liquefied natural gas,
through the one or more beds, the temperature of the one or more
beds during regeneration being higher than the temperature of the
one or more beds during adsorption of heavy hydrocarbons from the
natural gas feed stream. [0056] #25. The method of Aspect #24,
wherein the method further comprises cooling and separating into
liquid and vapor phases the gas obtained from the one or more beds
of the temperature swing adsorption system during regeneration of
said one or more beds, and recycling the vapor phase into the
natural gas feed stream prior to said stream being passed through
the one or more beds of the temperature swing adsorption system.
[0057] #26. The method of Aspect #24, wherein the gas liquid
separation system is a stripping column, and the method further
comprises introducing a stripping gas into the stripping column at
a location below the location at which the heavy hydrocarbon
depleted natural gas stream or portion thereof is introduced into
the stripping column, wherein said stripping gas comprises: the gas
obtained from the one or more beds of the temperature swing
adsorption system during regeneration of said one or more beds; or
the vapor phase obtained from cooling and separating into liquid
and vapor phases the gas obtained from the one or more beds of the
temperature swing adsorption system during regeneration of said one
or more beds. [0058] #27. The method of any one of Aspects #1 to
#26, wherein the natural gas feed stream is lean in aliphatic
hydrocarbons having from 3 to 5 carbon atoms in total. [0059] #28.
An apparatus for removing heavy hydrocarbons from a natural gas
feed stream, the apparatus comprising a first heavy hydrocarbon
removal system and a second heavy hydrocarbon removal system for
processing the natural gas feed stream to produce a natural gas
stream lean in heavy hydrocarbons, wherein said first and second
systems are connected in fluid flow communication with each other
and are arranged in series such that in use the first system
processes the natural gas feed stream to produce a heavy
hydrocarbon depleted natural gas stream and the second system
processes at least a portion of the heavy hydrocarbon depleted
natural gas stream from the first system to produce the natural gas
stream lean in heavy hydrocarbons, and wherein one of said systems
is an adsorption system comprising one or more beds of adsorbent
for adsorbing and thereby removing heavy hydrocarbons from a heavy
hydrocarbon containing natural gas, and the other of said systems
is a gas-liquid separation system for separating a heavy
hydrocarbon containing natural gas into a heavy hydrocarbon
depleted natural gas vapor and a heavy hydrocarbon enriched liquid.
[0060] #29. An apparatus according to Aspect #28, wherein the
gas-liquid separation system comprises a stripping column or a
phase separator. [0061] #30. An apparatus according to Aspect #28
or #29, wherein the apparatus is further for producing a liquefied
natural gas stream, and further comprises a liquefier connected in
fluid flow communication with the second heavy hydrocarbon removal
system for receiving and liquefying at least a portion of the
natural gas stream lean in heavy hydrocarbons to produce the
liquefied natural gas stream. [0062] #31. An apparatus according
any one of Aspects #28 to #30, wherein the gas-liquid separation
system is the first heavy hydrocarbon removal system, the apparatus
comprising:
[0063] a gas-liquid separation system for receiving and separating
the natural gas feed stream into a heavy hydrocarbon depleted
natural gas vapor stream and a heavy hydrocarbon enriched liquid
stream;
[0064] an adsorption system, in fluid flow communication with the
gas-liquid separation system, for receiving at least a portion of
the heavy hydrocarbon depleted natural gas vapor stream, and
comprising one or more beds of adsorbent for adsorbing heavy
hydrocarbons from said at least a portion of the heavy hydrocarbon
depleted natural gas vapor stream, to thereby produce the natural
gas stream lean in heavy hydrocarbons; and
[0065] an economizer heat exchanger for cooling the natural gas
feed stream, prior to said stream being introduced into gas-liquid
separation system, and warming the heavy hydrocarbon depleted
natural gas vapor stream, prior to said stream or portion thereof
being passed through the one or more beds of the adsorption system,
via indirect heat exchange between the natural gas feed stream and
the heavy hydrocarbon depleted natural gas vapor stream. [0066]
#32. An apparatus according to any one of Aspects #28 to #30,
wherein the gas-liquid separation system is the first heavy
hydrocarbon removal system, the apparatus comprising:
[0067] a gas-liquid separation system for receiving and separating
the natural gas feed stream into a heavy hydrocarbon depleted
natural gas vapor stream and a heavy hydrocarbon enriched liquid
stream;
[0068] an adsorption system, in fluid flow communication with the
gas-liquid separation system, for receiving at least a portion of
the heavy hydrocarbon depleted natural gas vapor stream, and
comprising one or more beds of adsorbent for adsorbing heavy
hydrocarbons from said at least a portion of the heavy hydrocarbon
depleted natural gas vapor stream, to thereby produce the natural
gas stream lean in heavy hydrocarbons; and
[0069] an economizer heat exchanger for warming the heavy
hydrocarbon depleted natural gas vapor stream, prior to said stream
or portion thereof being passed through the one or more beds of the
adsorption system, and cooling at least a portion of the natural
gas stream lean in heavy hydrocarbons via indirect heat exchange
between the heavy hydrocarbon depleted natural gas vapor stream and
the at least a portion of the natural gas stream lean in heavy
hydrocarbons. [0070] #33. An apparatus according to any one of
Aspects #28 to #30, wherein the adsorption system is the first
heavy hydrocarbon removal system, the apparatus comprising:
[0071] an adsorption system for receiving the natural gas feed
stream, and comprising one or more beds of adsorbent for adsorbing
heavy hydrocarbons from the natural gas feed stream, to thereby
produce a heavy hydrocarbon depleted natural gas stream; and
[0072] a gas-liquid separation system, in fluid flow communication
with the adsorption system, for receiving at least a portion of the
heavy hydrocarbon depleted natural gas stream and separating said
stream or portion thereof into a heavy hydrocarbon enriched liquid
stream and a natural gas vapor stream that is further depleted in
heavy hydrocarbons, the latter providing the natural gas stream
lean in heavy hydrocarbons.
BRIEF DESCRIPTION OF SEVERAL VIEWS OF THE DRAWINGS
[0073] FIGS. 1(a) to (f) depict a first set of embodiments of the
present invention, in which a gas-liquid separation system is used
and arranged upstream of and in series with an adsorption system in
order to remove heavy hydrocarbons from a natural gas feed
stream;
[0074] FIGS. 2(a) to (d) depict a second set of embodiments of the
present invention, in which a gas-liquid separation system is used
and arranged upstream of and in series with an adsorption system in
order to remove heavy hydrocarbons from a natural gas feed
stream;
[0075] FIGS. 3(a) to (d) depict a third set of embodiments of the
present invention, in which an adsorption system is used and
arranged upstream of and in series with a gas-liquid separation
system in order to remove heavy hydrocarbons from a natural gas
feed stream; and
[0076] FIG. 4 is a graph plotting the results of using in series an
adsorption system and a gas-liquid separation system to remove
heavy hydrocarbons from a natural gas feed stream, as compared to
using a scrubbing column on its own to remove heavy hydrocarbons
from a natural gas feed stream.
DETAILED DESCRIPTION OF THE INVENTION
[0077] In certain aspects, the present invention concerns a method
and apparatus in which an adsorption system is used in combination
with a gas-liquid separation system so as to effectively remove
heavy hydrocarbons (i.e. one or more C6+ hydrocarbons and/or
aromatics) from a natural gas stream.
[0078] When the natural gas stream has a composition that is lean
in C3-C5 components and contains high levels of heavy hydrocarbons,
any heavy hydrocarbon removal scheme employing a TSA system or
scrub column alone is ineffective or energy inefficient. The
inventors have found that this problem can be solved by using an
adsorption system (preferably a TSA system) in combination with a
gas-liquid separation system (preferably comprising a phase
separator or a stripping column).
[0079] In particular, the method and apparatus according to the
present invention can improve the energy efficiency of the
liquefaction process by allowing a phase separator or stripping
column (or other gas-liquid separation system) to be operated at a
higher pressure than a conventional scrub column.
[0080] In addition, when a LNG production plant has natural gas
feeds from different gas fields or that are contaminated with heavy
components, the LNG plant faces the challenge of uncertain levels
of heavy hydrocarbons. The method and apparatus according to the
present invention can prevent the LNG plant from having freezing
problems within a wide range of heavy hydrocarbon concentrations,
thus offering the plant operational flexibility when dealing with
uncertain or changing gas compositions.
[0081] Furthermore, in the method and apparatus according to the
present invention the load on the adsorption beds of the TSA (or
other adsorption) system is reduced due to the fact that some of
the heavy hydrocarbons are removed in the gas-liquid separation
system, which lessens the risk of heavy hydrocarbon cracking
occurring in the bed or beds of the TSA system during high
temperature (e.g. 450-600.degree. F., 232-315.degree. C.)
regeneration of said bed or beds, which cracking can otherwise
result in bed deactivation.
[0082] In the present method and apparatus, the adsorption system
and the gas-liquid separation system are used in series to process
the natural gas stream to remove heavy hydrocarbons therefrom.
[0083] The adsorption system can be placed downstream of the
gas-liquid separation system, such that the gas-liquid separation
system removes the bulk of the heavy hydrocarbons and controls the
amount of heavy hydrocarbons at the inlet of the adsorption system,
the adsorption system then removing the rest of the heavy
hydrocarbons to the levels necessary or acceptable for preventing
subsequent freezing during liquefaction of the natural gas.
[0084] Alternatively, the adsorption system can be placed upstream
of the gas-liquid separation system, such that the adsorption
system removes most of the heavy hydrocarbons, and the gas-liquid
separation system removes the remainder of the heavy hydrocarbons
to the levels necessary or acceptable for preventing subsequent
freezing during liquefaction of the natural gas. The composition of
the natural gas stream to the gas-liquid separation system is, in
this case, controlled by the adsorption system design and
capacity.
[0085] The adsorption system and gas-liquid separation system can
be installed as a front-end heavy hydrocarbon removal unit that
processes the natural gas before the natural gas stream enters a
separate liquefaction unit. Alternatively, the adsorption system
and gas-liquid separation system can be integrated into a
liquefaction unit.
[0086] Typically (and depending in part on factors such as the
starting temperature of the natural gas stream and whether the
gas-liquid separation system is upstream or downstream of the
adsorption system) the gas-liquid separation system will require
refrigeration to partially condense the stream being fed to the
gas-liquid separation system. As will be discussed in further
detail below, this refrigeration can be provided in a variety of
ways, including but not limited to: refrigeration provided via
Joule-Thompson effect (i.e. via isenthalpic, or largely
isenthalpic, expansion of the stream); cooling of the stream via
indirect heat exchange in a part of the natural gas liquefier;
cooling of the stream via indirect heat exchange in another heat
exchanger (against another process stream and/or against a separate
refrigerant such as, for example, a mixed-refrigerant); or addition
of LNG to cool to the stream via direct heat exchange.
[0087] Solely by way of example, various preferred embodiments of
the invention will now be described with reference to the
accompanying drawings, a first group being depicted in FIGS.
1(a)-(f), a second group being depicted in FIGS. 2(a)-(d), and a
third group being depicted in FIGS. 3(a)-(d). In the drawings,
where a feature is common to more than one drawing that feature has
been assigned the same reference numeral in each drawing, for
clarity and brevity.
FIGS. 1(a)-(f)
[0088] In a first group of embodiments, depicted in FIGS. 1(a)-(f),
the gas-liquid separation system is upstream of the adsorption
system, such that the gas-liquid separation system processes the
natural gas feed stream (from which heavy hydrocarbons are to be
removed) to produce a heavy hydrocarbon depleted natural gas
stream, and the adsorption system processes at least a portion of
the heavy hydrocarbon depleted natural gas stream from the
gas-liquid separation system to produce the desired natural gas
stream lean in heavy hydrocarbons.
[0089] More specifically, in the first group of embodiments the
natural gas feed stream is cooled in an economizer heat exchanger
and then introduced into the gas-liquid separation system and
separated into a heavy hydrocarbon depleted natural gas vapor
stream and a heavy hydrocarbon enriched liquid stream. The heavy
hydrocarbon depleted natural gas vapor stream is then warmed in the
economizer heat exchanger, via indirect heat exchange with the
natural gas feed stream. The resulting warmed heavy hydrocarbon
depleted natural gas vapor stream, or a portion thereof, is then
passed through the one or more beds of the adsorption system to
adsorb heavy hydrocarbons therefrom and thereby further reduce the
concentration of heavy hydrocarbons in said stream or portion
thereof (thereby providing the desired natural gas stream lean in
heavy hydrocarbons).
[0090] Referring now to FIG. 1(a), a specific embodiment is shown
in which a stripping column and temperature swing adsorption system
are used in series to remove heavy hydrocarbons from a natural gas
feed stream. A methane rich natural gas feed stream (100) is first
passed through an economizer heat exchanger (10), where it is
cooled via indirect heat exchange with a heavy hydrocarbon depleted
natural gas vapor stream (104), to be described in further detail
below. The cooled natural gas feed stream (101) is then further
cooled via pressure reduction through a Joule-Thompson (J-T) valve
(20). The further cooled and now partially condensed natural gas
feed stream (102) is then introduced into a stripping column
(30).
[0091] The stripping column (30) may be of any suitable design. As
is well known in the art, in a stripping column a condensed or
partially condensed feed stream (in this case a partially condensed
natural gas feed stream) is introduced into the stripping column,
where it is brought into contact with a stripping gas. The feed
stream is introduced into the stripping column at a location that
is above the location at which the stripping gas is introduced, so
that the falling stream of liquid from the feed stream comes into
countercurrent contact with the rising stream of stripping gas,
thereby "stripping" said liquid of less volatile components.
Typically, the stripping column contains one or more separation
stages, positioned between the location at which the feed stream is
introduced and the location at which the stripping gas is
introduced, and composed of trays, packing, or some other form of
insert that acts to increase the amount and/or duration of contact
between the feed liquid and stripping gas streams, thereby
increasing mass transfer between the streams. Typically, there are
no separation stages above the location at which the feed stream is
introduced into the stripping column.
[0092] In the embodiment depicted in FIG. 1(a), the further cooled
and partially condensed natural gas feed stream (102) is introduced
into the top of the stripping column (30), and a stripping gas
(109) is introduced into the bottom of the stripping column, the
stripping column comprising one or more separation stages
positioned between the feed locations of the natural gas feed
stream and stripping gas. The stripping gas for the stripping
column may come from any of a variety of different sources, as will
be described in further detail with reference to FIG. 1(c), but in
the particular embodiment depicted in FIG. 1(a) it comprises a
stream of natural gas (109) taken from the natural gas feed stream
(100) upstream of the economizer heat exchanger (10).
[0093] The stripping column (30) separates the partially condensed
natural gas feed stream (102) into a heavy hydrocarbon depleted
natural gas vapor stream (104), that is withdrawn from the top of
the stripping column, and a heavy hydrocarbon enriched liquid
stream (103), that is removed from the bottom of the stripping
column. Optionally, the temperature of the stripping gas (109)
entering the stripping column (30) can be adjusted using heater
(not shown), if it is desirable to raise the temperature of heavy
hydrocarbon enriched liquid stream (103) or reduce the methane
content in said stream.
[0094] The heavy hydrocarbon depleted natural gas vapor stream
(104) withdrawn from the top of the stripping column (30) is then
passed, as described above, through the economizer heat exchanger
(10) to recover the refrigeration therefrom and to cool down
natural gas feed stream (100). The now warmed heavy hydrocarbon
depleted natural gas vapor stream (105) from the economizer heat
exchanger (10) is then sent to temperature swing adsorption system
(40), comprising one or more beds of adsorbent selective for heavy
hydrocarbon components of the natural gas stream (i.e. that
preferentially adsorb the heavy hydrocarbon components of the
stream). Where there are multiple beds these may be arranged in
parallel and/or in series. The heavy hydrocarbon depleted natural
gas vapor stream (105) is passed through one or more of said beds
to further reduce (down to acceptable levels) the concentration of
heavy hydrocarbons in said stream and provide the desired natural
gas stream lean in heavy hydrocarbons (107).
[0095] The natural gas stream lean in heavy hydrocarbons (107) can
then be supplied as natural gas feed (107) to a natural gas
liquefaction system (90) and liquefied to provide an LNG stream
(110). The heavy hydrocarbons adsorbed by the adsorbent(s) can
subsequently be removed in an adsorbent regeneration step (not
shown in FIG. 1(a)).
[0096] Referring now to FIG. 1(b), in an alternative embodiment a
phase separator (31) can be used (in place of the stripping column
used in the embodiment depicted in FIG. 1(a)) to separate the
partially condensed natural gas feed stream (102) into a heavy
hydrocarbon depleted natural gas vapor (104), that is withdrawn
from the top of the phase separation vessel, and a heavy
hydrocarbon enriched liquid (103), that is withdrawn from the
bottom of the vessel.
[0097] As is known in the art, a phase separator differs from a
stripping column in that in a phase separator a partially condensed
feed is simply allowed to separate (for example via gravity) into
its liquid phase and bulk gas phases, without contact with any
additional stripping gases or reflux streams. Thus, in comparison
with the stripping column (30) in FIG. 1(a), the phase separator
(31) in FIG. 1(b) contains no separation stages (i.e. trays or
packing to enhance mass transfer between countercurrent streams),
and no stripping gas is generated and supplied to the phase
separator. As compared to the embodiment depicted in FIG. 1(a), the
embodiment in FIG. 1(b) has the advantage of lower capital costs
but the disadvantage that it loses more methane in the heavy
hydrocarbon enriched liquid stream (103).
[0098] As described above, the embodiment depicted in FIG. 1(a)
(and FIG. 1(b)) uses a J-T valve (20) to provide additional
refrigeration (i.e. refrigeration additional to that provided by
the economiser heat exchanger (10)) for partially condensing the
natural gas feed stream (102) to the stripping column (30) (or
phase separator (31)). However, other options are additionally or
alternatively available. Furthermore, and as noted above, it is
also the case that instead of or in addition to using as the
stripping gas for the stripping column (30) natural gas (109) taken
from the natural gas feed stream (100) upstream of the economizer
heat exchanger (10), other sources of stripping gas can also be
used. These variations are further illustrated in FIG. 1(c).
[0099] Accordingly, referring now to FIG. 1(c), in other
embodiments the additional refrigeration for partially condensing
the natural gas feed stream (102) to the stripping column (30) can
be provided by another stream that is colder than the cooled
natural gas feed stream (101) exiting the economiser heat exchanger
(10). For example, the natural gas feed stream may be cooled by
indirect heat exchange with a refrigerant stream (130, 131), such
as for example a mixed refrigerant stream, in a heat exchanger
(21). This heat exchanger may be arranged as a separate unit from
the economizer heat exchanger (10) unit and the natural gas
liquefier (90) unit, as is shown in FIG. 1(c), or it may be
combined with one or both of the economizer heat exchanger (10) and
natural gas liquefier (90) as a single unit. Alternatively or
additionally, the natural gas feed stream may be cooled by direct
heat exchange, such as via direct injection of a cold stream (133)
into the natural gas stream (101, 102). In the case of direct
injection, it is possible that the cold stream (133) is itself
obtained from a stream (132) that is further cooled via pressure
let down through an J-T valve (82). A suitable source of a cold
stream (132, 133) for direct injection into the natural gas feed
stream may, for example, be a portion of the LNG obtained from the
liquefier (90), the pressure of which has been raised in a liquid
pump (not shown).
[0100] Likewise, with reference to FIG. 1(c), in other embodiments
the stripping gas (129) supplied to the stripping column (30) may
comprise one or more of: a stream of natural gas (109) taken from
the natural gas feed stream (100) upstream of the economizer heat
exchanger (10) (as already described in relation to FIG. 1(a)); a
portion (119) of the warmed natural gas stream depleted in heavy
hydrocarbons (105) from the economiser heat exchanger (10); or a
portion (108) of the natural gas stream lean in heavy hydrocarbons
(106) from the temperature swing adsorption system (40) (in which
case only a portion (107) of said natural gas stream lean in heavy
hydrocarbons (106) is then sent to the liquefier (90) for
liquefaction). Where a portion (119) of the natural gas stream
depleted in heavy hydrocarbons (105) and/or a portion (108) of the
natural gas stream lean in heavy hydrocarbons (106) are used as the
stripping gas (129), these may first require compression in a
compressor (75) prior to being used as the stripping gas (129). It
is preferred that the stripping gas (or at least some of the
stripping gas) is natural gas (109) taken from the natural gas feed
stream (100), because the natural gas feed stream is typically at a
pressure higher than the pressure at the bottom of the stripping
column, and thus natural gas taken from this stream will typically
not require any compression in order to be used as the stripping
gas.
[0101] Referring to FIGS. 1(d) and (e), in embodiments where a
stripping column (30) is used it is also possible to recover
through the stripping column some of the gas generated during
regeneration of the bed or beds of the adsorption system (40). As
shown in FIGS. 1(d) and 1(e), the adsorption system may for example
comprise two, or more, beds in parallel (40A and 40B), wherein
while one of the beds (40A) is undergoing the adsorption step, i.e.
is adsorbing heavy hydrocarbons from the heavy hydrocarbon depleted
natural gas vapor stream (105), the other bed (40B) is being
regenerated, regeneration gas being passed through the bed during
this regeneration step in order to assist with the desorption and
removal from the bed of heavy hydrocarbons adsorbed in a preceding
adsorption step (the temperature of the bed during the regeneration
step being higher than the temperature of the bed during the
adsorption step).
[0102] The regeneration gas passed through the bed (40B) undergoing
the regeneration step may, for example, comprise a portion (120) of
the natural gas lean in heavy hydrocarbons (106) obtained from the
outlet of the bed (40A) undergoing the adsorption step.
Alternatively or additionally, the regeneration gas may, for
example, comprise a stream (111) of flash or boil-off gas, obtained
from processing or storage of the LNG stream (110) in, for example,
and LNG storage facility (91), and which has first been compressed
in a compressor (92). It should be noted that, as illustrated in
FIG. 1(d), said compressed flash or boil-off gas may additionally
or alternatively be used as all or part of the stripping gas (112)
for the stripping column (30), which compressed flash or boil-off
gas may be used in addition to or as an alternative to any and all
of the sources of stripping gas discussed above.
[0103] The stream of desorbed gas (121) exiting the bed (40B) or
beds of the adsorption system during regeneration thereof, which
will typically be at a lower pressure than the pressure of the
natural gas feed stream (102) to the striping column (30), can then
be cooled down and partially condensed in a cooler (60), and phase
separated in a phase separator (70) into a liquid condensate stream
(124) containing the majority of the heavy hydrocarbons and a
natural gas vapour stream (125).
[0104] As shown in FIG. 1(d), this recovered natural gas vapour
stream (125) can be recompressed in a compressor (50) and cooled in
a further cooler (80), and can then be recycled by being
reintroduced into the stripping column (30) at a location below the
natural gas feed stream (102), thereby providing yet another
additional or alternative source of stripping gas. The cooler (80)
after the compressor (50) is optional, and can be used to control
the temperature of the recovered natural gas stream (125) entering
the stripping column. Alternatively, as shown in FIG. 1(e), the
recovered natural gas vapour stream (125) can be recovered by being
recycled into the natural gas feed stream (100), for example
upstream of a feed gas boost compressor (51). In-between the feed
gas boost compressor (51) and the economizer heat exchanger (10)
there may be various equipment (generically indicated as unit 55),
such as for example a dryer, cooler, etc.
[0105] Although FIGS. 1(d) and 1(e) depict only two parallel
adsorption beds (40A and 40B), this is merely for the sake of
brevity, and in practice the methods depicted in these Figures can
be carried out using single or multiple adsorption beds, in
parallel or in series.
[0106] It should also be noted that the method and apparatus
described above, in which the bed or beds of the TSA system are
regenerated using a gas comprising a flash gas or boil-off gas
obtained from the LNG stream, can equally be applied to other forms
of regenerative adsorption system (such as PSA systems), and indeed
to methods and apparatus for removing heavy hydrocarbons from a
natural gas stream where an adsorption system is used on its own
(i.e. not in combination with a gas-liquid separation system) or in
conjunction with any other system.
[0107] Finally, with reference to FIG. 1(f), another embodiment is
shown that varies from that depicted in FIG. 1(d) in that the
stripping column (30) comprises at least two separations stages
such that there are separation stages both above and below the
point of entry of the recovered natural gas stream (125) into the
stripping column (both stages therefore being below the point of
entry of the natural gas feed stream (101)).
[0108] As also illustrated in this Figure, a yet further source of
stripping gas to the stripping column (30) may be provided by using
a reboiler (90) at the bottom of the column to reboil a portion of
the heavy hydrocarbon enriched liquid stream (103) obtained from
the bottom of the stripping column, this reboiled portion then
being reintroduced into the bottom as stripping gas. The heat
source for the reboiler can be steam, hot oil, electric power, or
any stream that is hotter than the desired vapor temperature
returning to the column. This use of such a reboiler may equally be
applied to any of the preceding embodiments in which a stripping
column is used.
FIGS. 2(a)-(d)
[0109] In the second group of embodiments, depicted in FIGS.
2(a)-(d), the gas-liquid separation system is again upstream of the
adsorption system, such that the gas-liquid separation system
processes the natural gas feed stream (from which heavy
hydrocarbons are to be removed) to produce a heavy hydrocarbon
depleted natural gas stream, and the adsorption system processes at
least a portion of the heavy hydrocarbon depleted natural gas
stream from the gas-liquid separation system to produce the desired
natural gas stream lean in heavy hydrocarbons. However, as compared
to the first group of embodiments (depicted in FIGS. 1(a)-(f)) the
second group of embodiments (depicted in FIGS. 2(a)-(d)) differs in
the manner in which the natural gas feed stream to the gas-liquid
separation system is cooled and the heavy hydrocarbon depleted
natural gas vapor stream from the gas-liquid separation system is
warmed.
[0110] More specifically, in the second group of embodiments the
natural gas feed stream is again introduced into the gas-liquid
separation system and separated into a heavy hydrocarbon depleted
natural gas vapor stream and a heavy hydrocarbon enriched liquid
stream, and the heavy hydrocarbon depleted natural gas vapor stream
or a portion thereof is passed through the one or more beds of the
adsorption system to adsorb heavy hydrocarbons therefrom and
thereby further reduce the concentration of heavy hydrocarbons in
said stream (thereby providing the desired natural gas stream lean
in heavy hydrocarbons). However, in the second group of embodiments
the heavy hydrocarbon depleted natural gas vapor stream is warmed
in an economizer heat exchanger, prior said stream or portion
thereof to being passed through the one or more beds of the
adsorption system, via indirect heat exchange with at least a
portion of the natural gas stream lean in heavy hydrocarbons
obtained from the adsorption system (at least a portion of the
natural gas stream lean in heavy hydrocarbons therefore being also
cooled in said economizer heat exchanger to provide a cooled
natural gas stream lean in heavy hydrocarbons).
[0111] Due to the fact that, in the second group of embodiments,
the refrigeration recovered from the heavy hydrocarbon depleted
natural gas vapor stream is transferred in the economizer heat
exchanger to at least a portion of the natural gas stream lean in
heavy hydrocarbons rather than (as in the first group of
embodiments) to the natural gas feed stream, in the second group of
embodiments a colder temperature natural gas stream lean in heavy
hydrocarbons is obtained (as compared to the natural gas stream
lean in heavy hydrocarbons that is obtained in the first group of
embodiments) but an additional source of refrigeration for the
natural gas feed stream is required (to "replace" the refrigeration
that, in the first group of embodiments, was being supplied to the
natural gas feed stream by the economizer heat exchanger).
[0112] Thus, in contrast to the first group of embodiments (where
it is preferably the case that the natural gas stream lean in heavy
hydrocarbons is liquefied by being introduced into the warm end of
and withdrawn from the cold end of a natural gas liquefier), in the
second group of embodiments it is preferably the case that the
natural gas feed stream is cooled prior to being introduced into
the gas-liquid separation system by being introduced into the warm
end of and withdrawn from an intermediate location of a natural gas
liquefier, and that the cooled natural gas stream lean in heavy
hydrocarbons obtained from the economizer heat exchanger is
liquefied by being introduced into an intermediate location of and
withdrawn from the cold end of the liquefier.
[0113] Referring now to FIG. 2(a), an embodiment is shown in which
a methane rich natural gas feed stream (100, 201) is introduced
into the warm end of a natural gas liquefier (90), is cooled in the
warm stage of the liquefier, and withdrawn from an intermediate
location (i.e. a location between two cooling stages of the
liquefier, and thus neither at the warm end nor at the cold end of
the liquefier) as a cooled natural gas stream (202). This cooled
natural gas stream (202) exiting the intermediate location of the
liquefier (90) may be a partially condensed stream (i.e. it may
have been cooled and partially condensed in the warm stage of the
liquefier). Alternatively, the natural gas stream (202) exiting the
intermediate location of the liquefier (90) may also be reduced in
pressure (for example using a J-T valve, not shown) in order to
further cool and partially condense the natural gas stream
(202).
[0114] In FIGS. 2(a)-(d) the liquefier is depicted as a single unit
having two cooling stages. For example, where the liquefier is a
wound-coil heat exchanger, it may comprise two bundles, each bundle
representing a cooling stage. However, it is equally the case that
liquefier may comprise more cooling stages, and instead of the
stages all being contained in a single unit the liquefier may
comprise more than one unit, arranged in series, with the cooling
stages being distributed amongst the units.
[0115] The cooled and partially condensed natural gas stream (202)
is then introduced into the top of a stripping column (30) where,
as in the embodiment described above with reference to FIG. 1(a),
it is separated into a heavy hydrocarbon depleted natural gas vapor
(204) that is withdrawn from the top of the stripping column and a
heavy hydrocarbon enriched liquid (203) that is removed from the
bottom of the stripping column. A stripping gas (209) is again also
introduced into the stripping column, at the bottom thereof, and
the stripping column may again comprise one or more separation
stages separating the feed locations of the natural gas feed stream
and stripping gas.
[0116] The heavy hydrocarbon depleted natural gas vapor stream
(204) withdrawn from the top of the stripping column (30) is then
passed through an economizer heat exchanger (10) to recover
refrigeration therefrom. Typically, the economizer heat exchanger
(10) warms the heavy hydrocarbon depleted natural gas vapor stream
(204) up to a temperature of (0-40.degree. C.).
[0117] The warmed heavy hydrocarbon depleted natural gas vapor
stream (205) from the economizer heat exchanger (20) is then sent
to temperature swing adsorption system (40), which again comprising
one or more beds of adsorbent selective for the heavy hydrocarbon
components of the natural gas stream, the heavy hydrocarbon
depleted natural gas vapor stream (205) being passed through one or
more of said beds to further reduce (down to acceptable levels) the
concentration of heavy hydrocarbons in said stream and provide the
desired natural gas stream lean in heavy hydrocarbons (206). Again,
where the absorber system (40) comprises a plurality of beds these
can arranged in series and/or in parallel, and again the heavy
hydrocarbons adsorbed by the adsorbent(s) can subsequently be
removed in an adsorbent regeneration step (not shown in the
figure).
[0118] The natural gas stream lean in heavy hydrocarbons (206)
obtained from the outlet of the adsorption system (40) is then
passed through economizer heat exchanger (10) where it is cooled
down via indirect heat exchange with heavy hydrocarbon depleted
natural gas vapor stream (204), thereby recovering refrigeration
therefrom as previously described. The cooled natural gas stream
(208) lean in heavy hydrocarbons exiting in the economizer heat
exchanger (30) is then returned to an intermediate location of the
natural gas liquefier (90), preferably the same intermediate
location as the intermediate location from which the cooled and
partially condensed natural gas stream (202) is withdrawn, and
cooled and liquefied in the cold stage (or colder stages) of the
liquefier to provide a LNG stream (110) withdrawn from the cold end
of the liquefier.
[0119] Referring now to FIG. 2(b), in an alternative embodiment a
phase separator (31) can be used (in place of the stripping column
used in the embodiment depicted in FIG. 2(a)) to separate the
partially condensed natural gas feed stream (202) into the heavy
hydrocarbon depleted natural gas vapor (204), withdrawn from the
top of the phase separation vessel, and the heavy hydrocarbon
enriched liquid (203), withdrawn from the bottom of the vessel. As
described above in relation to the operation of the phase separator
depicted in FIG. 1(b), the phase separator (31) does not contain
any separation stages or make use of a stripping gas, and thus in
this embodiment no stripping gas is generated or used. As compared
to the embodiment depicted in FIG. 2(a), the embodiment in FIG.
2(b) has the advantage of lower capital costs but the disadvantage
that it loses more methane in the heavy hydrocarbon enriched liquid
stream (203).
[0120] Similar to the various embodiments of the first group of
embodiments depicted in FIGS. 1(d)-(f), in those embodiments of the
second group of embodiments where a stripping column (30) is used
it is possible to obtain the stripping gas for the stripping column
from a variety of sources, and it is again possible to recover
through the stripping column a some of the gas generated during
regeneration of the bed or beds of the adsorption system (40).
These variations are further illustrated in FIGS. 2(c) and (d).
[0121] Thus, referring to FIG. 2(c), although it is preferred that
the stripping gas (or at least a portion thereof) supplied to the
stripping column (30) is a stream of natural gas (209) taken from
the natural gas feed stream (100) upstream of the liquefier (90)
(as also depicted in FIG. 2(a), various additional and/or
alternative sources are available. For example, the stripping gas
may additionally or alternatively comprise one or more of: a
portion (219) of the warmed natural gas stream depleted in heavy
hydrocarbons (205) from the economiser heat exchanger (10); a
portion (208) of the natural gas stream lean in heavy hydrocarbons
(206) from the temperature swing adsorption system (40) (in which
case only a portion (107) of said natural gas stream lean in heavy
hydrocarbons (106) is then cooled in economizer heat exchanger (10)
and sent to the liquefier (90) for liquefaction); or a flash or
boil-off gas (111, 112) obtained from processing or storage of the
LNG stream (110) in, for example, and LNG storage facility (91).
Such additional/alternative sources of stripping gas will typically
require compression prior to being used as the stripping gas (in
for example compressors 75 or 92 as depicted in FIG. 2(c)).
[0122] With reference to FIGS. 2(c) and (d), the adsorption system
may for example comprise one, two, or more, beds (40A and 40B),
arranged and operated in any of the manners as described above with
reference to FIGS. 1(d)-(f), with a regeneration gas being passed
through said beds during the regeneration thereof and some of the
gas generated during regeneration of the bed or beds being
recovered through the stripping column. In particular, the
regeneration gas may comprise a portion (120) of the natural gas
lean in heavy hydrocarbons (106), obtained from the outlet of the
bed (40A) undergoing the adsorption step, or a stream (111) of
flash or boil-off gas. The stream of desorbed gas (121) exiting the
bed or beds being regenerated (40B) can then be cooled down and
partially condensed in a cooler (60), and phase separated in an
phase separator (70) into a liquid condensate stream (124),
containing the majority of the heavy hydrocarbons, and a natural
gas vapour stream (125).
[0123] As shown in FIG. 2(c), the recovered natural gas vapour
stream (125) can then be recompressed in a compressor (50) and
cooled in a further cooler (80), and then recycled by being
reintroduced into the stripping column (30) at a location below the
natural gas feed stream (102), thereby providing yet another
additional or alternative source of stripping gas. The cooler after
the compressor (50) is optional and can be used to control the
temperature of the recovered natural gas stream (125) entering the
stripping column. Alternatively, as shown in FIG. 2(d), the
recovered natural gas vapour stream (125) can be recovered by being
recycled into the natural gas feed stream (100), for example
upstream of a feed gas boost compressor (51). In-between the feed
gas boost compressor (51) and the economizer heat exchanger (10)
there may be various equipment (generically indicated as unit 55),
such as for example a dryer, cooler, etc.
FIGS. 3(a)-(d)
[0124] In the third group of embodiments, depicted in FIGS.
3(a)-(d), the adsorption system is upstream of the gas-liquid
separation system, such that such that the adsorption system
processes the natural gas feed stream (from which heavy
hydrocarbons are to be removed) to produce a heavy hydrocarbon
depleted natural gas stream, and the gas-liquid separation system
processes at least a portion of a heavy hydrocarbon depleted
natural gas stream from the adsorption system to produce the
desired natural gas stream lean in heavy hydrocarbons.
[0125] More specifically, in the third group of embodiments the
natural gas feed stream is passed through the one or more beds of
the adsorption system to adsorb heavy hydrocarbons therefrom,
thereby producing a heavy hydrocarbon depleted natural gas stream.
At least a portion of the heavy hydrocarbon depleted natural gas
stream is cooled and then introduced into the gas-liquid separation
system and separated into a natural gas vapor stream that is
further depleted in heavy hydrocarbons (thereby providing the
desired natural gas stream lean in heavy hydrocarbons), and a heavy
hydrocarbon enriched liquid stream. Preferably, the heavy
hydrocarbon depleted natural gas stream or portion thereof is
cooled and the natural gas stream lean in heavy hydrocarbons is
liquefied in a natural gas liquefier, the heavy hydrocarbon
depleted natural gas stream or portion thereof being introduced
into a warm end of the liquefier and withdrawn from an intermediate
location of the liquefier, and the natural gas stream lean in heavy
hydrocarbons being introduced into an intermediate location of the
liquefier and withdrawn from a cold end of the liquefier.
[0126] The beds of the adsorption system in the third group of
embodiments have to be larger than the beds of the adsorption
system in the first and second groups of embodiments (depicted in
FIGS. 1(a)-(f) and FIGS. 2(a)-(d)), because in the first and second
groups of embodiments the gas-liquid separation system column
removes the bulk of the heavy hydrocarbons in the natural gas feed
stream. Put another way, for the same size of adsorber bed, the
methods and apparatus according to the first and second groups of
embodiments (depicted in FIGS. 1(a)-(f) and FIGS. 2(a)-(d)) can
tolerate higher concentrations of heavy hydrocarbon in the natural
gas feed, and offers better operational flexibility if the natural
gas source changes or the concentrations of the heavy hydrocarbons
fluctuate over a wide range. The smaller adsorption beds used in
the first and second groups of embodiments also mean that these
embodiments have lower requirements as regards regeneration gas
usage and lower power costs in relation to feed gas compression.
However, the embodiments in the third group of embodiments (as
depicted in FIGS. 3(a)-(d)) do not need an economizer heat
exchanger for recovery of refrigeration from the vapour stream
obtained from the gas-liquid separation column, thereby providing
savings in terms of capitals costs.
[0127] With reference to FIG. 3(a), in one embodiment a methane
rich natural gas feed stream (100) is introduced into an adsorption
system (40), which again comprising one or more beds of adsorbent
selective for the heavy hydrocarbon components of the natural gas
stream, the natural gas feed stream (100) being passed through one
or more of said beds to adsorb heavy hydrocarbons therefrom,
thereby producing a heavy hydrocarbon depleted natural gas stream
(301). As described above in connection with the embodiments
depicted in FIGS. 1 and 2, where the absorption system (40)
comprises a plurality of beds these can arranged in series and/or
in parallel, and again the heavy hydrocarbons adsorbed by the
adsorbent(s) can subsequently be removed in an adsorbent
regeneration step (not shown in FIG. 3(a)).
[0128] At least a portion (302) of the heavy hydrocarbon depleted
natural gas stream (301) is then is introduced into the warm end of
a natural gas liquefier (90), is cooled in the warm stage of the
liquefier, and is withdrawn from an intermediate location of the
liquefier as a cooled heavy hydrocarbon depleted natural gas stream
(303). This cooled stream (303) exiting the intermediate location
of the liquefier (90) may be a partially condensed stream (i.e. it
may have been cooled and partially condensed in the warm stage of
the liquefier). Alternatively, the cooled stream (303) exiting the
intermediate location of the liquefier (90) may also be reduced in
pressure (for example using a J-T valve, not shown) in order to
further cool and partially condense stream. Again, although the
liquefier is depicted in FIGS. 3(a)-(d) as a single unit having two
cooling stages, it is equally the case that liquefier may comprise
more cooling stages, and that the liquefier may comprise more than
one unit, arranged in series, with the cooling stages being
distributed amongst the units.
[0129] The cooled and partially condensed heavy hydrocarbon
depleted natural gas stream (303) is introduced into the top of the
stripping column (30) where it is separated into a natural gas
vapor stream (305) withdrawn from the top of the column that is
further depleted in heavy hydrocarbons (this stream being the
desired natural gas stream lean in heavy hydrocarbons), and a heavy
hydrocarbon enriched liquid (304) removed from the bottom of the
column. A stripping gas is again introduced into the stripping
column, at the bottom thereof, the stripping column comprising one
or more separation stages separating the feed locations of the
natural gas feed stream and stripping gas. The stripping gas can
any come from a variety of different sources but, in the embodiment
depicted in FIG. 3(a), comprises: a portion (306) of the heavy
hydrocarbon depleted natural gas taken from the heavy hydrocarbon
depleted natural gas stream (301) prior to the remainder (302) of
said stream being cooled and partially condensed in the natural gas
liquefier (90); and/or a stream of natural gas (307) taken from the
natural gas feed stream (100) prior to the processing of the latter
in the adsorption system (40).
[0130] The natural gas stream lean in heavy hydrocarbons (305)
obtained from the top of the stripping column is then returned to
an intermediate location of the natural gas liquefier (preferably
the same intermediate location as the intermediate location from
which the cooled and partially condensed heavy hydrocarbon depleted
natural gas stream (303) is withdrawn) and cooled and liquefied in
a cold stage (or colder stages) of the liquefier to provide a LNG
stream (110) withdrawn from the cold end of the liquefier.
[0131] As with the first and second groups of embodiments, in the
third group of embodiments a phase separator can be used instead of
stripping column, which will save capital costs but increase the
loss of methane in the heavy hydrocarbon enriched liquid stream
(304).
[0132] Thus, referring now to FIG. 3(b), in an alternative
embodiment a phase separator (31) is used (in place of the
stripping column used in the embodiment depicted in FIG. 3(a)) to
separate the partially condensed heavy hydrocarbon depleted natural
gas stream (303) into the natural gas vapor stream (305) further
depleted in heavy hydrocarbons depleted (the desired natural gas
stream lean in heavy hydrocarbons), withdrawn from the top of the
phase separation vessel, and a heavy hydrocarbon enriched liquid
(304), withdrawn from the bottom of the vessel. As described above
in relation to the operation of the phase separator depicted in
FIG. 1(b), the phase separator (31) does not contain any separation
stages or make use of a stripping gas, and thus in this embodiment
no stripping gas is generated or used.
[0133] Similar to the various embodiments of the first group of
embodiments depicted in FIGS. 1(d)-(f), in those embodiments of the
third group of embodiments where a stripping column (30) is used it
is again also possible to recover through the stripping column some
of the gas generated during regeneration of the bed or beds of the
adsorption system (40).
[0134] The stream of desorbed gas (121) exiting the bed or beds
being regenerated (40B) can then be cooled down and partially
condensed in a cooler (60), and phase separated in an phase
separator (70) into a liquid condensate stream (124), containing
the majority of the heavy hydrocarbons, and a natural gas vapour
stream (125).
[0135] Thus, with reference to FIGS. 3(c) and (d), the adsorption
system may for example comprise one, two, or more, beds (40A and
40B), arranged and operated in any of the manners as described
above with reference to FIGS. 1(d)-(f), with a regeneration gas
being passed through said beds during the regeneration thereof and
some of the gas generated during regeneration of the bed or beds
being recovered through the stripping column. In particular, the
regeneration gas may comprise a portion (320) of the heavy
hydrocarbon depleted natural gas stream (301), obtained from the
outlet of the bed (40A) undergoing the adsorption step, or a stream
(111) of flash or boil-off gas. The stream of desorbed gas (321)
exiting the bed or beds being regenerated (40B) can then be cooled
down and partially condensed in a cooler (60), and phase separated
in a phase separator (70) into a liquid condensate stream (323),
containing the majority of the heavy hydrocarbons, and a natural
gas vapour stream (324).
[0136] As shown in FIG. 3(c), the recovered natural gas vapour
stream (324) can then be recompressed in a compressor (50) and
cooled in a further cooler (80), and then recycled by being
reintroduced into the stripping column (30) at a location below the
heavy hydrocarbon depleted natural gas stream (303), thereby
providing yet another additional or alternative source of stripping
gas (326). The cooler after the compressor (50) is optional and can
be used to control the temperature of the recovered natural gas
stream (324) entering the stripping column. The compressor (50) is
also optional, and may not be needed if the adsorption system is
regenerated at a pressure that is higher than the pressure at the
bottom of the column. In a further variation, the phase separator
(70) can also be omitted, such that all of the cooled stream of
desorbed gas (321) exiting the cooler (60) is sent to the stripping
column. As also illustrated in FIG. 3(c), the stripping column (30)
may comprise at least two separations stages such that there are
separation stages both above and below the point of entry of the
recovered natural gas stream (324) into the stripping column, and
stripping gas to the stripping column (30) may also be provided by
using a reboiler (95) at the bottom of the column to reboil a
portion of the heavy hydrocarbon enriched liquid stream (304)
obtained from the bottom of the stripping column.
[0137] Alternatively, as shown in FIG. 3(d), the recovered natural
gas vapour stream (324) can be recycled into the natural gas feed
stream (100), for example upstream of a feed gas boost compressor
(51). In-between the feed gas boost compressor (51) and the
economizer heat exchanger (10) there may be various equipment
(generically indicated as unit 55), such as for example a dryer,
cooler, etc. As also illustrated in FIG. 3(d), flash or boil-off
gas may again, additionally or alternatively, also be used as
stripping gas (112) for the stripping column (30).
EXAMPLES
[0138] In order to demonstrate the effects of using, in accordance
with the present invention, a TSA system and gas-liquid separation
system in combination to remove heavy hydrocarbons from a natural
gas stream, the performance of the embodiments depicted in FIGS.
1(a), 1(e), 2(a), 2(b), 2(c), 3(a), 3(b) and 3(c) in removing heavy
hydrocarbons from a natural gas stream was compared to the
performance of a prior art process (not in accordance with the
present invention) that uses a scrub column, only, to remove heavy
hydrocarbons from the natural gas stream. In the first run using
the traditional (scrub column only) process, the operating
conditions used for the scrub column would lead to a risk of scrub
column dry-out (and resulting failure of the heavy hydrocarbon
removal process). Therefore, a second run using the traditional
(scrub column only) process was also conducted, using different
operating conditions (namely a colder column temperature) that
prevented any risk of column dry-out. The data for all runs, i.e.
both those employing the aforementioned embodiments of the present
invention and those employing the prior art (scrub column only)
process, was generated using ASPEN.TM. Plus software (.COPYRGT.
Aspen Technology, Inc.) and an internal adsorption simulation tool,
SIMPAC (a detailed adsorption process simulator, which considers
multicomponent adsorption isotherms, various mass transfer modes,
numerous adsorbent layers, and general process flowsheeting--more
details of this simulator being provided in Kumar et al., Chemical
Engineering Science, Volume 49, Number 18, pages 3115-3125).
[0139] The starting composition of the natural gas feed stream that
was used (which was the same for all cases) is given below, in
Table 1, and the composition of the product stream (i.e. the
natural gas stream desired to be lean in heavy hydrocarbons,
labelled in Table 2 as "Heavy Hydrocarbon Lean Stream") that was
obtained from each embodiment (i.e. from each of the embodiments
depicted in FIGS. 1(a), 1(e), 2(a), 2(b), 2(c), 3(a), 3(b) and
3(c)) and from the traditional (scrub column only) process (both
runs) is given below, in Table 2. In Table 2, the first run
employing the prior art (scrub column only) process where there was
a risk of scrub column dry-out is indicated by the note "Tray may
dry out", and the second run employing the prior art (scrub column
only) process, where this risk was removed, is indicated by the
note "NO Tray dry-out".
[0140] Table 2 also lists: the gas-liquid separation system
operating conditions (i.e. the scrub column/stripping column/phase
separator vessel temperature and pressure); the flow rate of heavy
hydrocarbon enriched liquid obtained from the gas-liquid separation
system as a percentage of the flow rate of the natural gas stream
fed to said system (designated in the table as "LPG as % of Feed");
and the total LNG flow rate produced by each run, expressed as a
percentage of the total LNG production flow rate obtained in the
first run using the prior art process (designated in the table as
"Relative LPG Production"). With reference to the data provided in
Table 2, as is well known in the art the letter E when used as part
of a number stands for exponent--thus, for example, in Table 2 the
number 9.9E-01 refers to 9.9.times.10.sup.-1, or 0.99.
[0141] As can be seen from the data in Table 2, the embodiments
according to the present invention were able to effectively remove
the heavy hydrocarbons from the NG gas stream and provide increased
LNG production compared to that provided by the prior art (scrub
column only) process, despite the gas-liquid separation system in
the embodiments according to the present invention being operated
at higher temperatures or higher pressures (thereby consuming less
energy) than the temperature and pressure of the scrubbing column
in the prior art process (even in the prior art process run where
the scrubbing column was operated at a temperature risking column
dry-out).
[0142] These results are also shown in FIG. 4, in which relative
LNG production (i.e. the total LNG flow rate produced by each run,
expressed as a fraction of the best total LNG production flow rate
obtained using the prior art process) is plotted against LPG Flow
as a % of Feed Flow (i.e. the flow rate of heavy hydrocarbon
enriched liquid obtained from the gas-liquid separation system as a
percentage of the flow rate of the natural gas stream fed to said
system). As is again shown, the embodiments according to the
present invention provide improved LNG production rates as compared
to the prior art process, even where the prior art process is run
under conditions risking column dry out, and these benefits are
even more marked in comparison to those runs of the prior art
process which were run under operating conditions that prevent any
risk of column dry out (i.e. sufficiently high LPG Flow as a % of
Feed Flow, as provided by operating the scrub column at lower
temperatures to increase the amount of heavy hydrocarbon enriched
liquid produced).
TABLE-US-00001 TABLE 1 Feed Composition Component mol % Nitrogen
7.0E-01 Methane 9.6E+01 Ethane 2.8E+00 Propane 4.8E-01 i-Butane
5.0E-02 n-Butane 8.5E-02 i-Pentane 2.0E-02 n-Pentane 2.2E-02
Cyclo-Pentane 3.0E-05 n-Hexane 3.2E-02 Cyclo-Hexane 5.0E-05
Methyl-Cyclohexane 4.0E-05 Heptane 2.9E-02 Octane 3.3E-03 Nonane
1.1E-03 Benzene 1.9E-02 Toluene 3.4E-03
TABLE-US-00002 TABLE 2 Stream Compositions and Column/Separator
Operating Conditions Prior Art- Prior Art- Scrub Scrub
Configuration Column Column 1(a) 1(e) 2(a) 2(b) 2(c) 3(a) 3(b) 3(c)
NOTE Tray may NO Tray dry out Dry-out LPG as % of Feed % 0.63%
1.67% 0.64% 0.66% 0.65% 0.70% 0.69% 0.75% 1.05% 0.50% Relative LNG
% 100.0% 95.7% 104.0% 104.0% 103.7% 104.7% 103.8% 104.8% 104.7%
103.2% Production Heavy Hydrocarbon Lean Stream Nitrogen mol %
9.9E-01 1.0E+00 9.8E-01 1.1E+00 9.8E-01 9.8E-01 1.0E+00 9.8E-01
9.8E-01 1.0E+00 Methane mol % 9.6E+01 9.6E+01 9.6E+01 9.6E+01
9.6E+01 9.6E+01 9.6E+01 9.6E+01 9.6E+01 9.6E+01 Ethane mol %
2.7E+00 2.6E+00 2.7E+00 2.7E+00 2.7E+00 2.7E+00 2.7E+00 2.7E+00
2.7E+00 2.7E+00 Propane mol % 4.6E-01 2.8E-01 4.5E-01 4.5E-01
4.5E-01 4.5E-01 4.5E-01 4.4E-01 4.3E-01 4.7E-01 i-Butane mol %
4.4E-02 1.2E-02 4.3E-02 4.3E-02 4.3E-02 4.3E-02 4.3E-02 3.7E-02
3.7E-02 4.9E-02 n-Butane mol % 7.1E-02 1.9E-02 6.9E-02 6.9E-02
6.9E-02 6.9E-02 6.9E-02 5.6E-02 5.6E-02 8.2E-02 i-Pentane mol %
1.2E-02 8.9E-04 1.2E-02 1.2E-02 1.2E-02 1.2E-02 1.2E-02 8.0E-03
8.0E-03 1.9E-02 n-Pentane mol % 1.0E-02 5.3E-04 1.2E-02 1.2E-02
1.2E-02 1.2E-02 1.2E-02 7.3E-03 7.3E-03 2.0E-02 Cyclo-Pentane mol %
3.3E-06 7.9E-07 1.2E-05 1.1E-05 1.2E-05 1.2E-05 1.2E-05 6.6E-06
6.6E-06 1.5E-05 n-Hexane mol % 1.0E-04 9.7E-06 8.3E-03 8.3E-03
8.8E-03 8.8E-03 8.8E-03 3.8E-03 3.9E-03 3.1E-03 Cyclo-Hexane mol %
9.5E-09 5.0E-08 7.5E-06 7.3E-06 8.1E-06 8.0E-06 7.9E-06 3.6E-06
3.6E-06 2.7E-06 Methyl- mol % 2.0E-10 2.7E-09 3.5E-06 3.4E-06
4.0E-06 4.0E-06 3.9E-06 1.1E-03 1.1E-03 5.0E-04 Cyclohexane Heptane
mol % 2.1E-08 1.0E-07 2.2E-03 2.1E-03 0.0E+00 0.0E+00 0.0E+00
1.2E-04 1.3E-04 7.9E-05 Octane mol % 1.3E-13 4.2E-11 0.0E+00
0.0E+00 0.0E+00 0.0E+00 0.0E+00 6.6E-06 6.6E-06 3.6E-06 Nonane mol
% 2.0E-17 1.1E-13 0.0E+00 0.0E+00 0.0E+00 0.0E+00 0.0E+00 1.6E-07
1.7E-07 8.4E-08 Benzene mol % 6.0E-05 4.8E-05 0.0E+00 0.0E+00
0.0E+00 0.0E+00 0.0E+00 6.0E-05 6.0E-05 6.0E-05 Toluene mol %
8.5E-09 6.0E-08 2.8E-04 2.7E-04 3.2E-04 3.2E-04 3.1E-04 1.2E-04
1.3E-04 7.9E-05 Column/Phase Separator Operating Conditions
Temperature C. -65.0 -73.8 -51.2 -51.2 -54.5 -53.4 -53.8 -60.1
-60.3 -55.7 Pressure bara 48.5 48.3 53.5 54.0 56.9 56.3 57.3 48.7
48.7 47.2
[0143] It will be appreciated that the invention is not restricted
to the details described above with reference to the preferred
embodiments but that numerous modifications and variations can be
made without departing form the spirit or scope of the invention as
defined in the following claims.
* * * * *