Note: Descriptions are shown in the official language in which they were submitted.
CA 02880441 2016-11-09
TITLE
HEAVY HYDROCARBON REMOVAL
FROM A NATURAL GAS STREAM
CROSS REFERENCE TO RELATED APPLICATION(S)
[0001] This application claims the benefit of International Application
No.
PCT/US2012/049506, filed 3 August 2012 (03.08.2012), U.S. Application No.
13/565,881,
filed 3 August 2012 (03.08.2012), and U.S. Application No. 13/611,169, filed
12
September 2012 (12.09.2012), which application is a continuation-in-part of
U.S.
Application No. 13/565,881.
BACKGROUND
[0002] The present 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 C3-05
hydrocarbons) and/or a
stream that is already lean in aliphatic hydrocarbons having from 2 to 5
carbon atoms in
total (also referred to herein as C2-05 hydrocarbons).
[0003] 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.
[0004] 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
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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.
[0005] 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 C3-05 hydrocarbons and/or C2-05
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 C3-05 hydrocarbons and/or C2-05
hydrocarbons and contains relatively high concentrations of heavy hydrocarbons
the
conventional scrub column technology is energy inefficient.
[0006] 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
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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.
[0007] 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 F, 232-315 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.
[0008] Prior art in this field includes documents WO 2009/074737, WO
2007/018677,
US 3,841,058, and US 5,486,227 (which describe processes in which adsorption
systems
are used); and US 7,600,395, US 5,325,673, WO 2006/061400, US 2006/0042312,
and
US 2005/0072186 (which describe processes in which scrub columns are
employed).
[0009] 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
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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
[0010] According to a first aspect, 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.
[0011] 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.
[0012] 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.
[0013] 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
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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 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.
[0014] 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.
[0015] 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 C3-05
hydrocarbons in the feed stream (i.e. the concentration of any and all C3-05
hydrocarbons
in the feed stream when taken together) is 5 mol% or less, or 3 mol% or less,
or 2 mol% or
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less, or 1 mol% or less; and/or the natural gas feed stream may be lean in
aliphatic
hydrocarbons having from 2 to 5 carbon atoms in total, such as for example
where the total
concentration of any and all C2-05 hydrocarbons in the feed stream (i.e. the
concentration
of any and all C2-05 hydrocarbons in the feed stream when taken together) is
10 mol% or
less, or 5 mol% or less, or 4 mol% or less. Likewise, the natural gas feed
stream may,
alternatively or additionally, have a relatively high concentration of heavy
hydrocarbons,
such as where the natural gas feed stream has a total concentration of heavy
hydrocarbon
components of 100ppm or more, or 250ppm or more (i.e. the concentration of all
aromatics
and C6+ aliphatic hydrocarbons in the feed stream, taken together, totals
100ppm or more,
or 250ppm or more).
[0016] 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.
[0017] 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.
[0018] 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
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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.
[0019] 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.
[0020] According to a second aspect, 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.
[0021] The apparatus according to the second aspect is suitable for
carrying out the
method according to the first aspect. Preferred embodiments of the apparatus
according to
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the second aspect will therefore be apparent from the above discussion of
preferred
embodiments of the method according to the first aspect. In particular:
[0022] Preferably, the gas-liquid separation system comprises a
stripping column or a
phase separator.
[0023] Preferably, the adsorption system comprises a temperature swing
adsorption
system.
[0024] 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.
[0025] 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.
[0026] In an alternative embodiment, the adsorption system is the first
heavy
hydrocarbon removal system, and the apparatus comprises: an adsorption system
for
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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.
[0027] According to a third aspect, 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.
[0028] Preferred aspects include the following aspects, numbered #1 to
#33:
#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
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heavy hydrocarbon containing natural gas into a heavy hydrocarbon depleted
natural gas
vapor and a heavy hydrocarbon enriched liquid.
#2. The method of Aspect #1, wherein the gas-liquid separation system
comprises a
stripping column or a phase separator.
#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.
#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:
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 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.
#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.
#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.
#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.
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#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.
#10. The method of Aspect #9, wherein the method further comprises liquefying
the
cooled natural gas stream lean in heavy hydrocarbons.
#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.
#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.
#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.
#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
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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 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.
#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.
#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.
#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:
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
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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 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.
#20. The method of Aspect #19, wherein the method further comprises liquefying
the
natural gas stream lean in heavy hydrocarbons.
#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.
#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.
#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.
#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
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CA 02880441 2016-11-09
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 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.
#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.
#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,
and/or is lean in
aliphatic hydrocarbons having from 2 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
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containing natural gas into a heavy hydrocarbon depleted natural gas vapor and
a heavy
hydrocarbon enriched liquid.
#29. An apparatus according to Aspect #28, wherein the gas-liquid separation
system
comprises a stripping column or a phase separator.
#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.
#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:
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 any one of Aspects #28 to #30, 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;
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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 any one of Aspects #28 to #30, 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.
[0028a] In one aspect, there is provided a method of removing heavy
hydrocarbons
from a natural gas feed stream, the method comprising the steps of: cooling
the natural gas
feed stream; introducing the cooled natural gas feed stream into a gas-liquid
separation
system and separating the cooled natural gas feed stream into a heavy
hydrocarbon
depleted natural gas vapor stream and a heavy hydrocarbon enriched liquid
stream;
warming the heavy hydrocarbon depleted natural gas vapor stream; passing at
least a
portion of the warmed heavy hydrocarbon depleted natural gas vapor stream
through one
or more beds of adsorbent of an adsorption system to adsorb heavy hydrocarbons
therefrom, thereby producing a natural gas stream lean in heavy hydrocarbons;
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
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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.
[002813] In
another aspect, there is provided an apparatus for removing heavy
hydrocarbons from a natural gas feed stream and producing a liquefied natural
gas stream,
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 a natural
gas stream
lean in heavy hydrocarbons; 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; and a liquefier
connected in fluid
flow communication with the gas-liquid separation system and the adsorption
system, for
receiving and cooling the natural gas feed stream prior to said stream being
introduced into
the gas-liquid separation system, and for receiving and liquefying at least a
portion of the
natural gas stream lean in heavy hydrocarbons to produce the liquefied natural
gas stream,
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 at least a
portion of 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.
BRIEF DESCRIPTION OF THE DRAWINGS
[0029]
Figures 1(a) to (f) depict a first set of embodiments, 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;
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CA 02880441 2016-11-09
[0030]
Figures 2(a) to (d) depict a second set of embodiments, 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;
[0031]
Figures 3(a) to (d) depict a third set of embodiments, 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
[0032]
Figure 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
[0033] In
certain aspects, the present 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.
[0034] When
the natural gas stream has a composition that is lean in C3-05
components and/or lean in C2-05 components, and contains relatively 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 in some embodiments 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).
[0035] In
particular, the method and apparatus according to some embodiments 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.
[0036] 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 some embodiments can prevent the LNG plant from having freezing problems
within a
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wide range of heavy hydrocarbon concentrations, thus offering the plant
operational
flexibility when dealing with uncertain or changing gas compositions.
[0037]
Furthermore, in the method and apparatus according to some embodiments 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 F, 232-315 C) regeneration
of said
bed or beds, which cracking can otherwise result in bed deactivation.
[0038] 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.
[0039] 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.
[0040]
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.
[0041] 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.
[0042]
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.
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CA 02880441 2016-11-09
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.
[0043] Solely by way of example, various preferred embodiments will now
be
described with reference to the accompanying drawings, a first group being
depicted in
Figures 1(a)-(0, a second group being depicted in Figures 2(a)-(d), and a
third group being
depicted in Figures 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.
Figures 1(a)-(f)
[0044] In a first group of embodiments, depicted in Figures 1(a)-(0, 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.
[0045] 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).
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CA 02880441 2016-11-09
[0046] Referring now to Figure 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).
[0047] 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.
[0048] In the embodiment depicted in Figure 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 Figure 1(c), but in the particular
embodiment depicted in
Figure 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).
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[0049] 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.
[0050] 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).
[0051] 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 Figure
1(a)).
[0052] Referring now to Figure 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
Figure 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.
[0053] 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
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CA 02880441 2016-11-09
Figure 1(a), the phase separator (31) in Figure 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 Figure 1(a), the embodiment in Figure 1(b) may have the advantage of lower
capital
costs but the disadvantage that it loses more methane in the heavy hydrocarbon
enriched
liquid stream (103).
[0054] As described above, the embodiment depicted in Figure 1(a) (and
Figure 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 Figure 1(c).
[0055] Accordingly, referring now to Figure 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 Figure 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 (85). 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).
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CA 02880441 2016-11-09
[0056] Likewise, with reference to Figure 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 Figure 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.
[0057] Referring to Figures 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 Figures 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).
[0058] 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
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CA 02880441 2016-11-09
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
Figure 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.
[0059] 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).
[0060] As shown in Figure 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 Figure 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.
[0061] Although Figures 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.
[0062] 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
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CA 02880441 2016-11-09
system is used on its own (i.e. not in combination with a gas-liquid
separation system) or in
conjunction with any other system.
[0063] Finally, with reference to Figure 1(0, another embodiment is
shown that varies
from that depicted in Figure 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)).
[0064] 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 (95) 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.
Figures 2(a)-(d)
[0065] In the second group of embodiments, depicted in Figures 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 Figures 1(a)-(0) the second group of embodiments (depicted in
Figures 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.
[0066] 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
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CA 02880441 2016-11-09
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).
[0067] 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).
[0068] 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.
[0069] Referring now to Figure 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
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CA 02880441 2016-11-09
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).
[0070] In Figures 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.
[0071] 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 Figure 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.
[0072] 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 C).
[0073] 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
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CA 02880441 2016-11-09
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).
[0074] 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.
[0075] Referring now to Figure 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
Figure 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 Figure 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 Figure 2(a), the embodiment in
Figure
2(b) may have the advantage of lower capital costs but the disadvantage that
it loses more
methane in the heavy hydrocarbon enriched liquid stream (203).
[0076] Similar to the various embodiments of the first group of embodiments
depicted
in Figures 1(d)-(0, 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 Figures
2(c) and (d).
[0077] Thus, referring to Figure 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
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CA 02880441 2016-11-09
depicted in Figure 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 (207) of said natural gas stream lean in heavy hydrocarbons
(206) 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 Figure 2(c)).
[0078] With reference to Figures 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 Figures 1(d)-(0, 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).
[0079] As shown in Figure 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 Figure 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
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CA 02880441 2016-11-09
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.
Figures 3(a)-(d)
[0080] In the third group of embodiments, depicted in Figures 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.
[0081] 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.
[0082] 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 Figures 1(a)-(f) and Figures 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 Figures 1(a)-(f) and Figures 2(a)-(d)) may 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
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CA 02880441 2016-11-09
and second groups of embodiments also mean that these embodiments may 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 Figures 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 may provide savings in terms of capitals costs.
[0083] With
reference to Figure 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 Figures 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 Figure 3(a)).
[0084] 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 Figures 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.
[0085] 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
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CA 02880441 2016-11-09
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 Figure
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).
[0086] 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.
[0087] 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
may save
capital costs but increase the loss of methane in the heavy hydrocarbon
enriched liquid
stream (304).
[0088] Thus, referring now to Figure 3(b), in an alternative embodiment
a phase
separator (31) is used (in place of the stripping column used in the
embodiment depicted in
Figure 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 Figure 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.
[0089] Similar to the various embodiments of the first group of
embodiments depicted
in Figures 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
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CA 02880441 2016-11-09
column some of the gas generated during regeneration of the bed or beds of the
adsorption
system (40).
[0090] 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).
[0091] Thus, with reference to Figures 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 Figures 1(d)-(0, 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).
[0092] As shown in Figure 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 Figure 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
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CA 02880441 2016-11-09
hydrocarbon enriched liquid stream (304) obtained from the bottom of the
stripping
column.
[0093] Alternatively, as shown in Figure 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
Figure 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
[0094] In order to demonstrate the effects of using, in accordance with
the present, 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
Figures 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) 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 and those employing the prior art (scrub column
only)
process, was generated using ASPENTM Plus software (CD 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).
[0095] 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
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CA 02880441 2016-11-09
Table 2 as "Heavy Hydrocarbon Lean Stream") that was obtained from each
embodiment
(i.e. from each of the embodiments depicted in Figures 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".
[0096] 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 9.9x10-1, or 0.99.
[0097] As can be seen from the data in Table 2, the embodiments 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 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).
[0098] These results are also shown in Figure 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 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
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CA 02880441 2016-11-09
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 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-l-lexane 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
-37-
Table 2. Stream Compositions and Column/Separator Operating Conditions
Prior Art - Prior Art -
Scrub Scrub
Configuratbn Column Column 1(a) 1(e)
2(a) 2(b) 2(c) 3(a) 3(b) 3(c)
Tray may NO Tray
NOTE dry out Dry-out ,
LPG as %of Feed S 0,63% 1.67%
0.64% 0,66% 0.65% 0.70% 0.69% 0.75% 1135% 0.50%
Relative LNG Production S 100.0%
95.7% 104.0% 104.0% 103.7% 104.75 103.8%
104.8% 104.7% 103.2%
Heavy Hydrocarbon Lean Stream
Nitrogen mol% 9.9E-01
1.0E+00 9.8E-01 1.1E400 9.8E-01 9.8E-01 1.0E+00 9.8E-01 9.8E-01 1.0E+00
Methane mot% 9.6E4.01
9.6E+01 9.6E401 9.6E401 9.6E+01 9.6E+01 9.6E+01 9.6E401 9.6E+01 9,6E+01
co
Ethane mol% 2.7E+00
2.6E+0) 2.7E+00 2.7E+00 2.7E+00 2.7E+00 2.7E+00 2.7E400 2.7E+00 2.7E+00
co
Propane mol% 4.6E01
2.8E-01 45E-01 4,5E-01 4.5E-01 45E-01 45E-01 44E-01 4.3E-01 4.7E01
i-Butane mol% 4.4E02
1.2E-02 4.3E-02 4.3E-02 4.3E-02 43E-02 4.3E-02 3.7E-02 3.7E-02 4.9E-02
00 n-Butane mot%
7.1E-02 1.9E-02 6.9E-02 6.9E02 6.9E-02 6.9E-
02 , 6.9E-02 5.6E-02 5.6E02 8.2E02
i-Pentane mol% 1.2E-02
8.9E-04 1.2E-02 1.2E-02 1.2E02 1.2E-02 1.2E-02 8.0E-03 8.0E-03 1.9E-02
n-Pentane mol% 1.0E-02
5.3E-04 12E-02 1.2E-02 1.2E-02 1.2E-02 1.2E-02 73E-03 73E-03 , 2.0E-02
Cydo-Pentane mol% 3.3E-06
7.9E-07 12E-05 1.1E-05 1.2E-05 12E-05 12E-05 6.6E-05 6.6E-06 15E-05
n-Hexane mol% 1.0E-0$
9.7E-06 83E-033 8.3E-03 8.8E-03 8.8E-03 8.8E-03 3.8E-03 3.9E-03 3.1E-03
Cyclo-Hexane mot% 9.5E-09
5.0E-08 75E-06 7,3E-06 8.1E-06 80E-06 7,9E-06 3.6E-06 3.6E06 2,7E-06
Methyl-Cydohexane mol% 2.0E40
2.7E-09 33E-06 3.4E06 4.0E-06 4.0E-06 , 3.9E-06 1.1E-03 1.1E-03 50E-04
Heptane mol% 2.1E08
1.0E-07 2.2E-03 2.1E03 00E+00 00E+00 0.0E+03 1.2E-04 1.3E-04 7.9E-05
Octane mol% 1.3E-13
4.2E-11 0.0E+00 0.0E+00 00E400 0.0E+00 0.0E+00 6.6E-06 6.6E-06 3.6E-06
Nonane mol% 2.0E-17
1.1E-13 0,0E400 0.0E+00 ODE400 0.0E+03 0.0E+03 1.6E-07 1.7E-07 84E-08
Benzene mol% 6.0E-05
4.8E-05 0.0E400 0.0E+00 0.0E400 0.0E+03 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 13E-04 7.9E-05
Column/Phase Separator
Operating Conditions
Temperature C -650 -73.8 -51.2 -51.2 -54.5 -534 -
53.8 -60.1 -60.3 -55.7
Pressure bara 483 48.3 53.5
54.0 56.9 563 57.3 48.7 48.7 47.2
CA 02880441 2016-11-09
[0099] It
will be appreciated that the present 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 from the spirit or scope as defined
in the
following claims.
-39-
