Note: Descriptions are shown in the official language in which they were submitted.
CA 02767369 2016-11-15
- 1 -
METHOD FOR TREATING A MULTI-PHASE HYDROCARBON STREAM AND
AN APPARATUS THEREFOR
The present invention relates to a method and
apparatus for treating a multi-phase hydrocarbon stream.
The method and apparatus provide a treated liquid
hydrocarbon stream. A low pressure fuel gas stream may
additionally be provided.
A common source for a multi-phase hydrocarbon stream
is a natural gas stream or a multi-phase stream produced
from natural gas e.g. by forming a multi-phase stream
comprising a vapour phase and a liquid phase by way of
cooling and/or changing the pressure of the natural gas.
The methods described herein may thus be employed to
provide a treated liquid hydrocarbon stream in the form
of a liquefied natural gas (LNG) stream.
Natural gas is a useful fuel source, as well as being
a source of various hydrocarbon compounds. It is often
desirable to liquefy natural gas in a liquefied natural
gas (LNG) plant at or near the source of a natural gas
stream for a number of reasons. As an example, natural
gas can be stored and transported over long distances
more readily as a liquid than in gaseous form because it
occupies a smaller volume and does not need to be stored
at high pressure.
Usually, natural gas, comprising predominantly
methane, enters an LNG plant at elevated pressures and is
pre-treated to produce a purified feed stream suitable
for liquefaction at cryogenic temperatures. The purified
gas is processed through a plurality of cooling stages
using heat exchangers to progressively reduce its
temperature until liquefaction is achieved. The liquid
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 2 -
natural gas is then further cooled and expanded to final
atmospheric pressure suitable for storage and
transportation. The flashed vapour from each expansion
can be used as a source of fuel gas.
Some hydrocarbon streams, such as natural gas, may
contain significant quantities of nitrogen such that if
special measures are not taken to remove at least a part
of the nitrogen from the hydrocarbon stream, the fuel gas
and any liquefied hydrocarbon stream produced may contain
undesirably high nitrogen levels. Many LNG specifications
require less than 1 mol% nitrogen in the final product.
US 2008/0066493 discloses a method of treating
liquefied natural gas to provide a liquid natural gas
stream having a reduced content of components having low
boiling points, such as nitrogen (N2). The method
comprises expanding liquefied natural gas to provide an
expanded multi-phase fluid and introducing the multi-
phase fluid into a column below a gas-liquid contacting
section to obtain a bottoms liquid stream having a
reduced content of components having low boiling points
and an overhead gaseous stream enriched in components
having low boiling points, such as nitrogen. The bottoms
liquid stream is passed to a flash vessel. The overhead
gaseous stream enriched in components having low boiling
points is heated in a heat exchanger and then compressed
to fuel gas pressure to obtain fuel gas. A recycle stream
is separated from the fuel gas, at least partly condensed
in a heat exchanger against the overhead gaseous stream
enriched in components having low boiling points and
introduced to the column above the gas-liquid contacting
section as a reflux stream. In a number of embodiments of
US 2008/0066493, also the second gaseous stream (from the
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 3 -
flash vessel) is heated in the heat exchanger, compressed
to fuel gas pressure, and added to the recycle stream.
At least part of the cold present in the overhead
gaseous stream is thus used to recondense a recycle
stream to produce reflux, which cold cannot be used to
cool another process stream elsewhere in the process.
In a first aspect, the present invention provides a
method of treating a multi-phase hydrocarbon stream to
provide a treated liquid hydrocarbon stream, comprising
at least the steps of:
- producing a multi-phase hydrocarbon stream from natural
gas, said multi-phase hydrocarbon stream comprising a
vapour phase and a liquid phase;
- passing the multi-phase hydrocarbon stream to a first
gas/liquid separator;
- separating the multi-phase hydrocarbon stream in the
first gas/liquid separator at a first pressure to provide
a first separator hydrocarbon vapour stream, comprising
hydrocarbons and nitrogen, and a first separator bottoms
stream;
- separating the first separator bottoms stream in a
second gas/liquid separator at a second pressure to
provide a second separator hydrocarbon vapour stream and
a treated liquid hydrocarbon stream in the form of LNG,
wherein the second pressure is lower than the first
pressure;
- compressing the second separator hydrocarbon vapour
stream in an overhead stream compressor to provide a
stripping vapour stream; and
- passing the stripping vapour stream to the first
gas/liquid separator at a level gravitationally lower
than the level at which the multi-phase hydrocarbon
stream is passed to the first gas/liquid separator.
CA 02767369 2016-11-15
- 3a -
In accordance with another aspect of the present
invention, there is provided a method of treating a multi-
phase hydrocarbon stream to provide a treated liquid
hydrocarbon stream, comprising at least the steps of:
- producing a multi-phase hydrocarbon stream from natural
gas, said multi-phase hydrocarbon stream comprising a vapour
phase and a liquid phase;
- passing the multi-phase hydrocarbon stream to a first
gas/liquid separator;
- separating the multi-phase hydrocarbon stream in the
first gas/liquid separator at a first pressure to provide a
first separator hydrocarbon vapour stream, comprising
hydrocarbons and nitrogen, and a first separator bottoms
stream;
- separating the first separator bottoms stream in a
second gas/liquid separator at a second pressure to provide
a second separator hydrocarbon vapour stream and a treated
liquid hydrocarbon stream in the form of LNG, wherein the
second pressure is lower than the first pressure;
- compressing the second separator hydrocarbon vapour
stream in an overhead stream compressor to provide a
stripping vapour stream;
- passing the stripping vapour stream to the first
gas/liquid separator at a level gravitationally lower than
the level at which the multi-phase hydrocarbon stream is
passed to the first gas/liquid separator;
- deriving a low pressure fuel gas stream from the first
separator hydrocarbon vapour stream; and
- passing the low pressure fuel gas stream to a
combustion device at a fuel gas pressure not higher than the
pressure of the first separator hydrocarbon vapour stream.
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 4 -
In a further aspect, the present invention provides
an apparatus for treating a multi-phase hydrocarbon
stream comprising a liquid phase and a vapour phase to
provide a treated liquid hydrocarbon stream in the form
of LNG, comprising at least:
- means for producing a multi-phase hydrocarbon stream
from natural gas, said means comprising at least one of a
liquefaction unit and one or more hydrocarbon stream
expansion devices;
- a first gas/liquid separator arranged to receive the
multi-phase hydrocarbon stream and separate it into a
first separator hydrocarbon vapour stream, comprising
hydrocarbons and nitrogen, and a first separator bottoms
stream, said first gas/liquid separator having a first
inlet for feeding the multi-phase hydrocarbon stream into
the first gas/liquid separator, a first outlet for
discharching the first separator hydrocarbon vapour
stream from the first gas/liquid separator, a second
outlet for discharging the first separator bottoms stream
from the first gas/liquid separator and a second inlet,
located at a level gravitationally lower than said first
inlet, for feeding a stripping vapour stream into the
first gas/liquid separator;
- a second gas/liquid separator arranged to receive the
first separator bottoms stream and separate it into a
second separator hydrocarbon vapour stream and a treated
liquid hydrocarbon stream in the form of LNG, said second
gas/liquid separator having a first inlet in fluid
communication with the second outlet of the first
gas/liquid separator, for feeding the first separator
bottoms stream into the second gas/liquid separator, a
first outlet for discharging the second separator
hydrocarbon vapour stream from the second gas/liquid
CA 02767369 2016-11-15
- 5 -
separator and a second outlet for discharing the treated
liquid hydrocarbon stream from the second gas/liquid
separator;
- a bottoms stream expansion device arranged between the
second outlet of the first gas/liquid separator and the
first inlet of the second gas/liquid separator, to reduce
the pressure of the first separator bottoms stream; and
- an overhead stream compressor to compress the second
separator hydrocarbon vapour stream to provide the stripping
vapour stream, said overhead stream compressor having an
inlet in fluid communication with the first outlet of the
second gas/liquid separator to receive the second separator
hydrocarbon vapour stream, and an outlet in fluid
communication with the second inlet of the first gas/liquid
separator for discharging the stripping vapour stream.
In accordance with another aspect of the present
invention, there is provided an apparatus for treating a
multi-phase hydrocarbon stream comprising a liquid phase and
a vapour phase to provide a treated liquid hydrocarbon
stream in the form of LNG, comprising at least:
- means for producing a multi-phase hydrocarbon stream
from natural gas, said means comprising at least one of a
liquefaction unit and one or more hydrocarbon stream
expansion devices;
- a first gas/liquid separator arranged to receive the
multi-phase hydrocarbon stream and separate it into a first
separator hydrocarbon vapour stream, comprising hydrocarbons
and nitrogen, and a first separator bottoms stream, said
first gas/liquid separator having a first inlet for feeding
the multi-phase hydrocarbon stream into the first gas/liquid
separator, a first outlet for discharging the first
separator hydrocarbon vapour stream from the first
gas/liquid separator, a second outlet for discharging the
CA 02767369 2016-11-15
- 5a -
first separator bottoms stream from the first gas/liquid
separator and a second inlet, located at a level
gravitationally lower than said first inlet, for feeding a
stripping vapour stream into the first gas/liquid separator;
- a second gas/liquid separator arranged to receive the
first separator bottoms stream and separate it into a second
separator hydrocarbon vapour stream and a treated liquid
hydrocarbon stream in the form of LNG, said second
gas/liquid separator having a first inlet in fluid
communication with the second outlet of the first gas/liquid
separator, for feeding the first separator bottoms stream
into the second gas/liquid separator, a first outlet for
discharging the second separator hydrocarbon vapour stream
from the second gas/liquid separator and a second outlet for
discharging the treated liquid hydrocarbon stream from the
second gas/liquid separator;
- a bottoms stream expansion device arranged between the
second outlet of the first gas/liquid separator and the
first inlet of the second gas/liquid separator, to reduce
the pressure of the first separator bottoms stream;
- an overhead stream compressor to compress the second
separator hydrocarbon vapour stream to provide the stripping
vapour stream, said overhead stream compressor having an
inlet in fluid communication with the first outlet of the
second gas/liquid separator to receive the second separator
hydrocarbon vapour stream, and an outlet in fluid
communication with the second inlet of the first gas/liquid
separator for discharging the stripping vapour stream; and
- a combustion device operating at a fuel gas pressure
not higher than the pressure of the first separator
hydrocarbon vapour stream, the combustion device arranged to
receive low pressure fuel gas derived from the first
separator hydrocarbon stream.
CA 02767369 2016-11-15
- 5b -
Embodiments of the present invention will now be
described by way of example only and with reference to the
accompanying non-limited drawings in which:
Figure 1 is a diagrammatic scheme of a method of and
apparatus for treating a multi-phase hydrocarbon stream
according to one embodiment; and
Figure 2 is a diagrammatic scheme of a method of and
apparatus for liquefying a hydrocarbon feed stream
incorporating the multi-phase hydrocarbon stream treating
method and apparatus.
For the purpose of this description, a single reference
number will be assigned to a line as well as a stream
carried in that line.
The methods and apparatuses disclosed herein propose an
improvement in component separation of a multi-phase stream
in two subsequent steps in two gas/liquid separators
operating at different pressures. The second
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 6 -
separator hydrocarbon vapour stream from the second
gas/liquid separator is compressed in an overhead stream
compressor and returned to the first gas/liquid separator
as a stripping vapor stream.
The present invention may advantageously provide a
method and apparatus for treating a multi-phase
hydrocarbon stream to provide a treated liquid
hydrocarbon stream that does not require the cold in the
overhead gaseous stream to be used to produce a reflux
stream.
The method and apparatus of the present invention
advantageously utilize a stripping vapor in the first
gas/liquid separator that is provided by the compression
of the vapour stream from the second gas/liquid
separator, to enhance component separation. Producing the
stripping vapour from the second gaseous stream allows
the second gaseous stream to be utilized to assist the
component separation without the need to recondense it or
part of it.
Hence, the cold in the first separator hydrocarbon
vapour stream, which in US 2008/0066493 was necessary to
produce reflux to achieve a desired efficiency in the
separation of the components, has now been freed up to be
used in any way. Of course, the invention does not
exclude the option that a reflux stream may still be
produced (using cold from the first separator hydrocarbon
vapour and/or from an external refrigerant) and employed
to further enhance the component separation, this is now
entirely optional. A group of embodiments of the
invention does not require a reflux stream such as that
used in US 2008/0066493.
The one or more hydrocarbon stream expansion devices
and the first and second gas/liquid separators may form
ak 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 7 -
part of an LNG end flash system. Likewise, the reducing
of the pressure of the at least partially liquefied
hydrocarbon stream to provide the multi-phase hydrocarbon
stream and the subsequent separation in the first and
second gas/liquid separators may form part of an LNG end
flash process.
Accordingly, the producing of the multi-phase
hydrocarbon stream from the natural gas may comprise the
following steps:
- providing a hydrocarbon supply stream from a natural
gas stream at elevated pressure;
- extracting a continuing hydrocarbon stream from the
hydrocarbon supply stream;
- passing the continuing stream to a cooling and
liquefaction unit wherein it is cooled an at least
partially liquefied to provide an at least partially
liquefied hydrocarbon stream;
- passing the at least partially liquefied hydrocarbon
stream to an inlet of at least one hydrocarbon stream
expansion device and therein reducing the pressure of the
at least partially liquefied hydrocarbon stream to
provide the multi-phase hydrocarbon stream.
The multi-phase stream may comprise a vapour phase
and a liquid phase. The treated liquid hydrocarbon
stream produced in accordance with the present invention,
in particular when provided in the form of LNG, may have
a specification suitable for it to be vaporized and used
as network gas.
Without wishing to be bound by the following
explanation by analogy, the Applicant suggests that the
overhead stream compressor provides heat of compression
to the second separator hydrocarbon vapour stream and
thus functions as a special reboiler, providing a
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 8 -
stripping vapour stream at a higher pressure and
temperature than the second separator hydrocarbon vapour
stream for the first gas/liquid separator. This stripping
vapor stream enhances the separation of the lower boiling
point components, such as nitrogen, from the expanded
hydrocarbon stream in the first gas/liquid separator. The
lower boiling point components are ejected to the first
separator hydrocarbon vapor stream.
If the first separator hydrocarbon vapour stream is
not pure nitrogen, but it also comprises an inventory of
hydrocarbons, it is possible to use this stream as fuel
gas. Thus, the method may further comprise:
- deriving a low pressure (LP) fuel gas stream from the
first separator hydrocarbon vapour stream; and
- passing the low pressure fuel gas stream to a
combustion device at a fuel gas pressure not higher than
the pressure of the first separator hydrocarbon vapour
stream. The first pressure of the first gas/liquid
separator may be at or above the fuel gas pressure.
Advantageously, the first separator hydrocarbon vapour
stream nor the low pressure fuel gas stream is compressed
before use in the combustion device.
In US 2008/0066493, N2 and other vapourous
constituents that are separated in the column, are
compressed and ejected to the high pressure fuel gas
stream. Table 1 of US 2008/0066493 discloses an example
in which a natural gas feed stream having a nitrogen
content of 3.05 mol% is treated to provide a liquefied
natural gas stream having a nitrogen content of 0.65 mol%
and a fuel gas having a nitrogen content of 24 mol%.
However, high nitrogen content fuel gas streams can
produce significant problems when used to fuel gas
turbines, which are commonly used to drive compressors or
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 9 -
electrical generators within a liquefaction facility. For
example, many aeroderivative gas turbines cannot
currently tolerate nitrogen contents above 15 mol% in
their fuel gas.
Therefore, in preferred embodiments of the present
methods and apparatuses, the first separator hydrocarbon
vapour stream is employed as low pressure fuel gas
stream. Fuel gas with large amounts of nitrogen can still
be used as low pressure fuel gas to fuel for instance a
furnace, a boiler, and/or a dual fuel diesel engine.
As used herein, the term "low pressure" in the low
pressure fuel gas stream is relative to the "high
pressure" fuel gas stream required to fuel a gas turbine.
For the purpose of the present specification, a low
pressure fuel gas may be at a pressure in a range of from
2 to 15 bara, more specifically in a range of from 2 to
10 bara. A high pressure (HP) fuel may be at a pressure
of higher than 15 bara, generally in a range of 15 to 40
bara, more specifically in a range of from 20 to 30 bara.
The first gas/liquid separator may advantageously be
operated at a suitable fuel gas pressure or above, such
that the first separator hydrocarbon vapour stream may
advantageously be provided at high enough pressure
requiring no, or no extensive, compression before use. It
is thus preferred to select the first pressure of the
first gas/liquid separator such that the first separator
hydrocarbon vapour stream is provided at or above the
desired fuel gas pressure.
Especially when used as low pressure fuel, the first
separator hydrocarbon vapour stream of the present
invention may comprise N2 in a wide range, for instance
in a range of from 30 mol% to 95 mol% N2, more preferably
in the range of from 60 mol% to 95 mol%.
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 10 -
Thus, the present invention may advantageously be
employed to provide a low pressure fuel gas stream,
suitable for use in a combustion device such as a furnace
or incinerator, or for instance in a dual fuel diesel
engine that may be employed for electric power generator.
The low pressure fuel gas stream may be derived from the
first separator hydrocarbon vapour stream by warming. The
first separator hydrocarbon vapour stream can be sent to
any suitable heat exchange device in which it can be used
to cool a process stream. Advantageously, the process
stream may be provided in the form of a part of the
natural gas to cool this part of the natural gas.
In order to provide a high pressure (HP) fuel gas
stream suitable for use as a fuel for a gas turbine, the
treating method and apparatus disclosed herein may be
incorporated into a method of liquefying a hydrocarbon
feed stream and an apparatus therefor. High pressure fuel
gas may be extracted from the hydrocarbon feed stream
prior to liquefaction. This is advantageous because the
hydrocarbon feed stream may have a low nitrogen content
compared to the low pressure fuel gas stream derived from
the first separator hydrocarbon vapour stream. In
addition, the hydrocarbon feed stream is a high pressure
stream, such that further pressurization of a portion of
this stream for use as a fuel gas stream is not required.
Thus, there is no requirement for a high pressure fuel
gas compressor. If necessary, where the hydrocarbon feed
stream is at too high a pressure, the pressure of the
extracted fuel gas may optionally be reduced in pressure
before use as fuel.
In addition, the method disclosed herein is
advantageous because it avoids using a gaseous stream
produced by the expansion of the liquefied hydrocarbon
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 11 -
stream as the high pressure fuel gas stream. Such gaseous
streams produced by gas/liquid separation steps, such as
end flash processes, would have a higher content of lower
boiling components, such as nitrogen, compared to the
liquid product produced by the separator.
Referring to the drawings, Figure 1 shows a method of
and apparatus 1 for treating a multi-phase hydrocarbon
stream 145 according to a first embodiment. The multi-
phase hydrocarbon stream 145 is derived from natural gas.
The multi-phase hydrocarbon stream 145 comprises vapour
and liquid phases. One example of how the multi-phase
hydrocarbon stream 145 may be provided is discussed in
greater detail below with reference to Figure 2.
The multi-phase hydrocarbon stream 145 is passed to a
first inlet 148 of a first gas/liquid separator 150. The
first gas/liquid separator 150 provides a first separator
hydrocarbon vapour stream 205 as an overhead stream at a
first outlet 151 and a first separator bottoms stream
155a, which is a liquid stream, at a second outlet 152 at
or near the bottom of the first gas/liquid separator 150.
The first gas/liquid separator 150 may be in the form of
a separation column such as a fractionation or
distillation column. The first gas/liquid separator 150
is preferably provided in the form of a nitrogen
separation column. The first separator hydrocarbon
vapour stream 205 typically comprises hydrocarbons,
typically predominantly methane, and nitrogen.
The separation is carried out at a first pressure,
which is preferably in the range of from 2 to 15 bara,
more preferably of from 2 to 10 bara in order to an
achieve even lower content of nitrogen in the liquid
hydrocarbon stream and still be useable as low pressure
fuel gas stream.
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 12 -
In order to enhance the separation within the first
gas/liquid separator 150, a stripping vapour stream 185a
is provided at a second inlet 149. The second inlet 149
typically comprises a vapour inlet device known to the
skilled person. The second inlet 149 is preferably at a
level gravitationally lower than the first inlet 148 in
order to provide efficient stripping of the lighter
components of the hydrocarbon mixture, such as nitrogen,
from the liquid phase of the multi-phase hydrocarbon
stream to the vapour phase. The first inlet 148 may
typically comprise an inlet distributor known to the
skilled person.
In a preferred embodiment, the first gas/liquid
separator 150 comprises a contacting zone preferably
comprising contact enhancing means 154 such as trays or
packing, to enhance separation. The contact enhancing
means 154 is preferably placed gravitationally between
the first and second inlets 148, 149.
The contact enhancing means may comprise a plurality
of trays stacked one above the other can be arranged to
force the liquid phase to flow horizontally along each
tray before falling to the next tray, with the vapour
phase bubbling through holes in the trays. This increases
the amount of contact area between the liquid and vapour
phases. Alternatively, the contact enhancing means may
comprise packing. A contacting zone of packing operates
in a similar manner to the trays with the packing, which
can be either structured or random, increasing the
contact area between the liquid and vapour phases.
The first separator hydrocarbon vapour stream 205 may
comprise hydrocarbons and an inventory of greater than or
equal to 30 mol% N2. It is preferred that the first
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 13 -
separator hydrocarbon vapour stream 205 has a pressure of
less than or equal to 10 bara.
A low pressure fuel gas stream 215 may be derived
from the first separator hydrocarbon vapour stream 205.
For instance, the first separator hydrocarbon vapour
stream 205 may be passed to a fuel gas heat exchanger
210, where it is warmed against a warming stream 355 to
provide the low pressure fuel gas stream 215, for
instance at a pressure of about 5 or 6 bara. At the same
time, the warming stream is cooled and turned into a
cooled warming stream 365.
The fuel gas heat exchanger 210 may be a heater, such
as an ambient heater in which case the warming stream 355
may be provided in the form of ambient air or ambient
water, to provide the cooled warming stream 365 in the
form of cooled air or cooled water stream. The cooled
warming stream 365 may be employed as an intermediate
stream to chill another stream. However, in preferred
embodiments, the warming stream 355 is provided in the
form of a process stream that needs to be cooled, thus
additionally providing a cooled process stream. In this
way, the cold energy from the first separator hydrocarbon
vapour stream 205 can be efficiently used to provide
cooling to a process stream in the apparatus 1, such as a
hydrocarbon or refrigerant stream. An example of this is
provided in relation to the embodiment of Figure 2.
The low pressure fuel gas stream 215 may comprise
greater than or equal to 30 mol% N2. The low pressure
fuel gas stream 215 can then be passed to a low pressure
fuel gas network. Figure 1 shows the low pressure fuel
gas stream 215 being passed directly to one or more low
pressure fuel gas consumers 220, for example a combustion
device, such as a furnace, boiler, or dual fuel diesel
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 14 -
engine. Such combustion devices can typically tolerate
high levels of nitrogen in the low pressure fuel gas, as
known to the skilled person.
The first separator bottoms stream 155a from the
first gas/liquid separator 150 may be passed to the first
inlet 158 of a second gas/liquid separator 160. The
second gas/liquid separator 160 operates at a second
pressure, which is lower that the first pressure used to
provide separation in the first gas/liquid separator 150.
The second pressure is preferably less than 4 bara, still
more preferably less than 2 bara. The second pressure may
suitably be at or near atmospheric pressure. For the
purpose of the present disclosure, at or near atmospheric
pressure is preferably interpreted as a pressure of
between 1 and 1.3 bara.
If the pressure drop between the first and second
gas/liquid separators 150, 160 is insufficient to provide
an appropriate second pressure, the first separator
bottoms stream 155a can be passed through a bottoms
stream expansion device 200, which provides an (expanded)
first separator bottoms stream 155b to the first inlet
158 of a second gas/liquid separator 160 at the second
pressure.
The second gas/liquid separator 160 provides a second
separator hydrocarbon vapour stream 175 as an overhead
stream at a first outlet 161 and a treated liquid
hydrocarbon stream 165 at a second outlet 162. The second
gas/liquid separator 160 may be a suitable flash vessel.
The treated liquid hydrocarbon stream 165, which may
be a LNG stream when the multi-phase hydrocarbon stream
145 is derived from natural gas, can be provided at or
near atmospheric pressure. The treated liquid hydrocarbon
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 15 -
stream 165 may be passed to a storage tank 170, such as a
cryogenic storage tank.
The second separator hydrocarbon vapour stream 175 is
passed to an overhead stream compressor 180, where it is
compressed to provide a stripping vapour stream 185. The
overhead stream compressor 180 may be mechanically driven
by an overhead stream compressor driver 190, such as a
gas turbine, a steam turbine, and/or an electric motor.
The stripping vapour stream 185 may optionally be
combined with a supplementary stripping vapour stream 235
to form a combined stripping vapour stream 185a, before
it is passed to the second inlet 149 of the first
gas/liquid separator 150 to enhance the separation
therein. The stripping vapour stream 185 is provided at a
third pressure which should be typically equal to or
slightly higher than the first pressure, for example the
first pressure plus any pressure loss between the
discharge of the overhead stream compressor 180 and the
second inlet 149 of the first gas/liquid separator 150.
For instance, the third pressure may be in the range of
from 0 to 2 bara higher than the first pressure.
The supplementary stripping vapour stream 235 may
comprise boil off gas from a cryogenic storage tank. In
case of cryogenic storage of the treated liquid
hydrocarbon, a degree of vaporisation of the treated
liquid hydrocarbon can be expected from the storage tank
170 due to imperfect thermal insulation and temperature
fluctuations. The resulting boil off vapour can be
removed from the storage tank 170 as boil off gas (BOG)
stream 195. The boil off gas stream 195 can be passed to
boil off gas compressor 230, where it is compressed to
provide compressed a compressed boil off gas stream 235
for use as supplementary stripping vapour stream. The
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 16 -
boil off gas compressor 230 can be driven by a boil off
gas compressor driver 240, such as a gas or steam turbine
and/or electric motor.
In an alternative embodiment not shown in Figure 1,
the supplemental stripping vapour stream 235 may be
passed directly to a further, separate inlet of the first
gas/liquid separator 150. The ultimate choice for where
the supplemental stripping vapour 235 is supplied to the
first gas/liquid separator may be driven by by the
composition and temperature of the supplemental stripping
vapour stream 235, such as the compressed boil off gas
stream.
In a preferred embodiment, the method disclosed
herein can be utilised as part of a liquefaction process
for a hydrocarbon feed stream in which case the multi-
phase hydrocarbon stream to be treated may be formed by
cooling and/or changing the pressure of a hydrocarbon
feed stream. The hydrocarbon feed stream may be any
suitable gas stream to be cooled and liquefied, but is
usually a natural gas stream obtained from natural gas or
petroleum reservoirs. As an alternative the hydrocarbon
feed stream may also be obtained from another source,
also including a synthetic source such as a Fischer-
Tropsch process.
Usually a natural gas stream is a hydrocarbon
composition comprised substantially of methane.
Preferably the hydrocarbon feed stream comprises at least
50 mol% methane, more preferably at least 80 mol%
methane.
Hydrocarbon compositions such as natural gas may also
contain non-hydrocarbons such as H20, N2, CO2, Hg, H2S
and other sulphur compounds, and the like. If desired,
the natural gas may be pre-treated before cooling and any
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 17 -
liquefying. This pre-treatment may comprise reduction
and/or removal of undesired components such as CO2 and
H2S or other steps such as early cooling, pre-
pressurizing or the like. As these steps are well known
to the person skilled in the art, their mechanisms are
not further discussed here.
Thus, the term "hydrocarbon feed stream" may also
include a composition prior to any treatment, such
treatment including cleaning, dehydration and/or
scrubbing, as well as any composition having been partly,
substantially or wholly treated for the reduction and/or
removal of one or more compounds or substances, including
but not limited to sulphur, sulphur compounds, carbon
dioxide, water, Hg, and one or more C2+ hydrocarbons.
Depending on the source, natural gas may contain
varying amounts of hydrocarbons heavier than methane such
as in particular ethane, propane and butanes, and
possibly lesser amounts of pentanes and aromatic
hydrocarbons. The composition varies depending upon the
type and location of the gas.
Conventionally, the hydrocarbons heavier than methane
are removed to various extents from the hydrocarbon feed
stream prior to liquefaction for several reasons, such as
having different freezing or liquefaction temperatures
that may cause them to block parts of a methane
liquefaction plant or to provide a desired specification
for the liquefied product. C2+ hydrocarbons can be
separated from, or their content reduced in a hydrocarbon
feed stream by a demethaniser, which will provide an
overhead hydrocarbon stream which is methane-rich and a
bottoms methane-lean stream comprising the C2+
hydrocarbons. The bottoms methane-lean stream can then be
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 18 -
passed to further separators to provide Liquefied
Petroleum Gas (LPG) and condensate streams.
After separation, the hydrocarbon stream so produced
can be further cooled, preferably liquefied. The cooling
could be provided by a number of methods known in the
art. The hydrocarbon stream is passed against one or more
refrigerant streams in one or more refrigerant circuits.
Such a refrigerant circuit can comprise one or more
refrigerant compressors to compress an at least partly
evaporated refrigerant stream to provide a compressed
refrigerant stream. The compressed refrigerant stream can
then be cooled in a cooler, such as an air or water
cooler, to provide the refrigerant stream. The
refrigerant compressors can be driven by one or more gas
and/or steam turbines and/or electric motors.
The cooling of the hydrocarbon stream can be carried
out in one or more stages. Initial cooling, also called
pre-cooling or auxiliary cooling, can be carried out
using a pre-cooling refrigerant, such as a mixed
refrigerant, of a pre-cooling refrigerant circuit, in one
or more pre-cooling heat exchangers, to provide a pre-
cooled hydrocarbon stream. The pre-cooled hydrocarbon
stream is preferably partially liquefied, such as at a
temperature below 0 C.
Preferably, such pre-cooling heat exchangers could
comprise a pre-cooling stage, with any subsequent cooling
being carried out in one or more main heat exchangers to
liquefy a fraction of the hydrocarbon stream in one or
more main and/or sub-cooling cooling stages.
In this way, two or more cooling stages may be
involved, each stage having one or more steps, parts
etc.. For example, each cooling stage may comprise one to
five heat exchangers. The or a fraction of a hydrocarbon
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 19 -
stream and/or the refrigerant may not pass through all,
and/or all the same, heat exchangers of a cooling stage.
In one embodiment, the hydrocarbon may be cooled and
liquefied in a method comprising two or three cooling
stages. A pre-cooling stage is preferably intended to
reduce the temperature of a hydrocarbon feed stream to
below 0 C, usually in the range -20 C to -70 C.
A main cooling stage is preferably separate from the
pre-cooling stage. That is, the main cooling stage
comprises one or more separate main heat exchangers. A
main cooling stage is preferably intended to reduce the
temperature of a hydrocarbon stream, usually at least a
fraction of a hydrocarbon stream cooled by a pre-cooling
stage, to below -100 C.
Heat exchangers for use as the two or more pre-
cooling or any main heat exchangers are well known in the
art. The pre-cooling heat exchangers are preferably shell
and tube heat exchangers.
At least one of any of the main heat exchangers is
preferably a spool-wound cryogenic heat exchanger known
in the art. Optionally, a heat exchanger could comprise
one or more cooling sections within its shell, and each
cooling section could be considered as a cooling stage or
as a separate 'heat exchanger' to the other cooling
locations.
In another embodiment, one or both of the pre-cooling
refrigerant stream and any main refrigerant stream can be
passed through one or more heat exchangers, preferably
two or more of the pre-cooling and main heat exchangers
described hereinabove, to provide cooled refrigerant
streams.
If the refrigerant is a mixed refrigerant in a mixed
refrigerant circuit, such as the pre-cooling refrigerant
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 20 -
circuit or any main refrigerant circuit, it may be formed
from a mixture of two or more components selected from
the group comprising: nitrogen, methane, ethane,
ethylene, propane, propylene, butanes, pentanes, etc. One
or more other refrigerants may be used, in separate or
overlapping refrigerant circuits or other cooling
circuits.
The pre-cooling refrigerant circuit may comprise a
mixed pre-cooling refrigerant. The main refrigerant
circuit may comprise a mixed main refrigerant. A mixed
refrigerant or a mixed refrigerant stream as referred to
herein comprises at least 5 mol% of two different
components. More preferably, the mixed refrigerant
comprises two or more of the group comprising: nitrogen,
methane, ethane, ethylene, propane, propylene, butanes
and pentanes.
A common composition for a pre-cooling mixed
refrigerant can be:
Methane (Cl) 0-20 mol%
Ethane (C2) 5-80 mol%
Propane (C3) 5-80 mol%
Butanes (C4) 0-15 mol%
The total composition comprises 100 mol%.
A common composition for a main cooling mixed
refrigerant can be:
Nitrogen 0-10 mol%
Methane (Cl) 30-70 mol%
Ethane (C2) 30-70 mol%
Propane (C3) 0-30 mol%
Butanes (C4) 0-15 mol%
The total composition comprises 100 mol%.
In another embodiment, the pre-cooled hydrocarbon
stream, such as a pre-cooled natural gas stream can be
ak 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 21 -
further cooled to provide an at least partially,
preferably fully, liquefied hydrocarbon stream, such as
an LNG stream. The further cooling may be carried out in
the main cooling stage. Preferably, the treated liquid
hydrocarbon stream provided in the method and apparatus
described herein can be stored in one or more storage
tanks. The fully liquefied hydrocarbon stream is
preferably sub-cooled. The further cooling, e.g. in the
main cooling stage or in a separate sub-cooling stage,
may thus comprise sub-cooling of the liquefied
hydrocarbon stream.
After liquefaction, the at least partially,
preferably fully, liquefied hydrocarbon stream can be
expanded to provide the multi-phase hydrocarbon stream
which can be further processed according to the method
and apparatus described herein.
Figure 2 shows a second embodiment of an apparatus in
which a pressurized hydrocarbon feed stream 85 is
treated, cooled, at least partially liquefied and
expanded, to provide the multi-phase hydrocarbon stream
145 used in the treatment method disclosed herein.
Described in more detail, the the multi-phase hydrocarbon
stream 145 may be provided by the steps of:
- providing an at least partially, preferably fully,
liquefied hydrocarbon stream 115; and
- expanding the at least partially, preferably fully,
liquefied hydrocarbon stream 115 in one or more
hydrocarbon stream expansion devices 120,140, to provide
the multi-phase hydrocarbon stream 145 in the form of an
expanded hydrocarbon stream.
The at least partially, preferably fully, liquefied
hydrocarbon stream 115 may be provided by the steps of:
- providing a hydrocarbon supply stream 105;
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 22 -
- splitting the hydrocarbon supply stream 105 into a high
pressure fuel gas stream 107 and a continuing hydrocarbon
stream 108;
- at least partially, preferably fully, liquefying the
continuing hydrocarbon stream 108 by cooling at least
part of the continuing stream 108 in one or more heat
exchangers 110a,110b, to provide the at least partially,
preferably fully, liquefied hydrocarbon stream 115.
The high pressure fuel gas stream 107 may have one or
both of a nitrogen content of lower than 15 mol% and a
pressure of higher than 15 bara.
The high pressure fuel
gas stream 107 may suitably be passed to one or more high
pressure fuel gas consumers 300, such as gas turbines.
A supply stream separation device 80 may be provided
to separate the hydrocarbon supply stream 105 into the
continuing hydrocarbon stream 108 and the high pressure
fuel gas stream 107. The supply stream separation device
80 may suitably have an inlet 78 for the hydrocarbon
supply stream 105, a first outlet 81 for the high
pressure fuel gas stream 107 and a second outlet 82 for
the continuing hydrocarbon stream 108.
In certain embodiments, the at least partially,
preferably fully, liquefying step may comprise:
- pre-cooling at least part of the continuing hydrocarbon
stream 108 in one or more pre-cooling heat exchangers
110a against a pre-cooling refrigerant in a pre-cooling
refrigerant circuit to provide a pre-cooled hydrocarbon
stream 113; and
- at least partially, preferably fully, liquefying at
least part 113b of the pre-cooled hydrocarbon stream 113
in one or more main cooling heat exchangers 110b, against
a main cooling refrigerant being cycled in in a main
cooling refrigerant circuit, to provide the at least
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 23 -
partially, preferably fully, liquefied hydrocarbon stream
115. These embodiments may further comprise the steps
of:
- passing a part 113b of the pre-cooled hydrocarbon
stream 113 to a fuel gas heat exchanger 210 as the
warming stream 355;
- cooling said part 113b of pre-cooled hydrocarbon stream
in the fuel gas heat exchanger 210 against the first
separator hydrocarbon vapour stream 205 to provide a
cooled process stream 365;
- passing the cooled process stream 365 to one of the one
or more hydrocarbon stream expansion devices 120,140.
Thus, the apparatus may comprise one or more cooling
stages 110 to cool and at least partially, preferably
fully, liquefy the continuing hydrocarbon stream 108 to
provide the at least partially, preferably fully,
liquefied hydrocarbon stream 115. Said one or more
cooling stages 110 may suitably have an inlet 109 for the
continuing hydrocarbon stream 108 in fluid communication
with the second outlet 82 of the supply stream separation
device 80 and an outlet 112 for the at least partially,
preferably fully, liquefied hydrocarbon stream 115
connected to an inlet 118 of the one or more hydrocarbon
stream expansion devices 120,140.
The hydrocarbon feed stream 85, which can be a
natural gas stream, is provided as a pressurised stream,
usually at a pressure in the range of from 30 to 90 bara.
The hydrocarbon feed stream 85 may be passed to an acid
gas removal unit 90. The acid gas removal unit 90 lowers
the content of acid gases such as carbon dioxide and
hydrogen sulphide in the hydrocarbon feed stream 85 by
known methods to provide a treated hydrocarbon stream 95.
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 24 -
The treated hydrocarbon stream 95, which will be
depleted in acid gases, may then be passed to a Natural
Gas Liquids (NGL) extraction unit 100, optionally via a
dryer (not shown). In the NGL extraction unit 100, at
least a portion of any natural gas liquids such as
propane, butanes and pentanes, together with heavier
hydrocarbons, can be removed, for instance using one or
more scrub columns or fractionation columns. The NGL
extraction unit 100 provides a hydrocarbon supply stream
105, which can be depleted in natural gas liquids.
Figure 2 shows the hydrocarbon supply stream 105
being passed to the inlet 78 of a supply stream
separation device 80, in which it is split into a high
pressure fuel gas stream 107 at a first outlet 81 and a
continuing hydrocarbon stream 108 at a second outlet 82.
In an alternative embodiment not shown in Figure 2,
the high pressure fuel gas stream 107 can be drawn from
hydrocarbon feed stream 85 and/or treated hydrocarbon
stream 95 instead of the hydrocarbon supply stream 105.
The bleed point for the high pressure fuel gas stream 107
will be determined by the composition of the hydrocarbon
mixture. For example, if the hydrocarbon mixture is
naturally low in acid gasses, the high pressure fuel gas
stream 107 can be drawn from the hydrocarbon feed stream
85 and the pressure be reduced in a device such as
valve 106 provided in line 107, to match the high
pressure fuel pressure requirements as desired.
Alternatively (not shown), the high pressure fuel gas
stream may be drawn from the NGL extraction unit 100 at a
lower pressure if the NGL extraction unit 100 is operated
at a lower pressure. Herewith it can be avoided to spend
power to needlessly recompress the portion of the
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 25 -
hydrocarbon supply stream 105 that is going to be
extracted as fuel gas.
The high pressure fuel gas stream 107 can then be
passed to a high pressure fuel gas network, or as shown
in Figure 2 directly to one or more high pressure fuel
gas consumers 300, such as gas turbines. The gas turbines
may mechanically drive electric generators for power
production, or more preferably mechanically drive
compressors, such as those present in a refrigerant
circuit.
The continuing hydrocarbon stream 108 from the second
outlet 82 of the supply stream separation device 80, can
then be passed to a cooling and liquefaction unit 110,
where it is cooled and at least partially, preferably
fully, liquefied. The liquefaction unit 100 provides an
at least partially, preferably fully, liquefied
hydrocarbon stream 115 at a first outlet 112. Such
liquefaction units are well known in the art, from
instance from U.S. Patent No. 6,370,910.
The liquefaction unit 110 shown in Figure 2 comprises
a first and a second cooling stage. The first cooling
stage comprises one or more pre-cooling heat exchangers
110a, which cool the continuing hydrocarbon stream 108
against a pre-cooling refrigerant in a pre-cooling
refrigerant circuit (not shown). The one or more pre-
cooling heat exchangers 110a provide a pre-cooled
hydrocarbon stream 113.
Pre-cooled hydrocarbon stream 113 can be passed to
pre-cooled stream separation device 70, where it may
optionally be split into a (continuing) pre-cooled
hydrocarbon stream part 113b and a process stream to be
employed as warming stream 355.
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 26 -
The pre-cooled hydrocarbon stream 113, or the
continuing pre-cooled hydrocarbon stream part 113b, is
passed to a second cooling stage. The second cooling
stage comprises one or more main cooling heat exchangers
110b, which at least partially, preferably fully, liquefy
the pre-cooled hydrocarbon stream 113, or at least the
continuing part 113b thereof, against a main cooling
refrigerant in a main cooling refrigerant circuit (not
shown). The one or more main cooling heat exchangers 110b
provide an at least partially, preferably fully,
liquefied hydrocarbon stream 115.
In an alternative embodiment, the NGL extraction unit
100 may be located somewhere in the liquefaction unit 110
instead of upstream thereof such as depicted in Figure 2.
In such a case, the supply stream separation device 80
may also be located in the liquefaction unit 110. Both
the NGL extraction unit 100 as well as the supply stream
separation device 80 would preferably be located upstream
of where full condensation of the feed stream is
accomplished. A good place would typically be upstream of
the second cooling stage.
The at least partially, preferably fully, liquefied
hydrocarbon stream 115 can be passed to an inlet 118 of
one or more hydrocarbon stream expansion devices 120,
140, such as two or more expansion devices in series
which sequentially reduce the pressure of the stream to
provide the multi-phase hydrocarbon stream 145 at outlet
142. In the embodiment shown in Figure 2, the at least
partially, preferably fully, liquefied hydrocarbon stream
115 can be passed to a first hydrocarbon stream expansion
device 120, which may be a turbine, in which it is
dynamically expanded to provide expanded hydrocarbon
stream 125. The energy released in the dynamic expansion
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 27 -
of the at least partially, preferably fully, liquefied
hydrocarbon stream 115 in the first expansion device 120
can be recovered, e.g. by mechanically driving an
electric generator 130 or another device such as a
compressor (not shown).
The expanded hydrocarbon stream 125 can then be
passed to an expanded hydrocarbon stream splitting device
60 to provide expanded hydrocarbon slip stream 305 and
(continuing) expanded hydrocarbon stream 125b. The
(continuing) expanded hydrocarbon stream 125b can then be
passed through the second expansion device 140, such as a
Joule-Thomson valve, in which it is expanded to provide
the multi-phase hydrocarbon stream 145.
In the embodiment of Figure 2 the warming stream 355,
after it has been cooled in fuel gas heat exchanger 210
to provide the cooled warming stream 365, is suitable
form part of stream 145. In such a case, after
appropriate depressurization, e.g. in an expander or
Joule Thomson device 121, the cooled warming stream 365,
may be injected into the (continuing) expanded
hydrocarbon stream 125b to be sent to the second
hydrocarbon stream expansion device 140 as already
discussed. In some embodiments, it may be beneficial to
recombine the cooled warming stream 365 with the
liquefied hydrocarbon stream 115 upstream of the
expansion device 120 so that these streams can be jointly
expanded.
In the embodiment of Figure 2, the warming stream 355
is provided in the form of the slip stream withdrawn from
pre-cooled hydrocarbon stream 113 by pre-cooled stream
separation device 70. However, the warming stream may
also be obtained at different pressures from other
sources, including but not limited to from the NGL
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 28 -
extraction unit 100 or a fractionation train (not shown)
that is typically installed to fractionate the NGL
product obtained from the NGL extraction unit 100.
In a different group of embodiments, the pre-cooled
hydrocarbon stream may not be split at all whereby the
warming stream 355 consist of an entirely different
process stream such as a refrigerant (slip) stream or an
intermediate chilling fluid stream.
The multi-phase hydrocarbon stream 145 can be passed
to a first inlet 148 of a first gas/liquid separator
150a, in which it is separated into vapour and liquid
fractions, in a similar manner to the embodiment of
Figure 1. The first separator vapour stream 205 exits the
first gas/liquid separator 150a overhead via a first
outlet 151 therein. The first separator bottoms stream
155a, which is a liquid stream, exits via second outlet
152 at or near the bottom of the first gas/liquid
separator 150a. A combined stripping vapour stream 185a
is passed to the first gas/liquid separator 150a a second
inlet 149 which is situated gravitationally lower than
the first inlet 148. The second inlet 149 can be above
second outlet 152.
The expanded hydrocarbon slip stream 305 is further
expanded, e.g. using Joule Thomson valve 310, and the
thus further expanded hydrocarbon slip stream 315 is
passed through reflux condenser 320 to recondense some of
the vapours at the top of the first gas/liquid separator
150a. The reflux condenser 320 may be located at a level
between the first inlet 148 and the first outlet 151, to
provide reflux to enhance the separation of the lighter
components of the multi-phase hydrocarbon stream. As
known to the person skilled in the art, an external
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 29 -
reflux condenser may be used instead of such an internal
condenser 320.
The further expanded hydrocarbon slip stream 315 is
warmed in condenser 320 thereby providing a warmed
hydrocarbon slip stream 325, which can be passed to the
(expanded) first separator bottoms stream 155b. The
(expanded) first separator bottoms stream 155b carrying
the warmed hydrocarbon from the warmed hydrocarbon slip
stream 325 can be passed to the inlet 158 of the second
gas/liquid separator 160 as a combined stream 155c.
Reference is made to Figure 1 and its description
hereinabove for a description of the streams drawn from
the second gas/liquid separator 160 and their further
processing.
Returning to the first gas/liquid separator 150a,
this may comprise two zones with contact enhancing means
(154a, 156a), e.g. formed of trays and/or packing, to
enhance separation and nitrogen rejection. A first zone
of the two zones is situated between the first inlet 148
and the second inlet 149 in a similar manner to the
embodiment of Figure 1. A second zone of the two zones
156a is situated between the first outlet 151 for the
first separator hydrocarbon vapour stream 205 and the
first inlet 148 for the multi-phase hydrocarbon stream
145. The second zone 156a should be below the condenser
320, or below an inlet means for reflux from an external
condenser, in order to take advantage of the reflux
provided by the condensation of the hydrocarbon vapour on
the condenser 320.
The first separator hydrocarbon vapour stream 205
which exits the first outlet 151 can be passed to fuel
gas heat exchanger 210 where it is warmed against warming
stream 355, to provide the low pressure fuel gas stream
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 30 -
215 and cooled warming stream 365. If the warming stream
is provided in the form of a process stream, a portion of
the cold energy of the first separator hydrocarbon vapour
stream 205 can thus be used to cool the process stream,
allowing it to bypass the one or more main heat
exchangers 110b, enhancing thermal efficiency.
As already touched on hereinabove, the warming stream
355 may be also be a process stream in the form of a
refrigerant stream, such as a pre-cooling and/or main
cooling refrigerant stream. In this case, a part of the
cold energy of the first separator hydrocarbon vapour
stream 205 can be returned to one or both of the cooling
stages 110, by cooling the refrigerant.
The advantages of the method and apparatus disclosed
herein will be apparent from the following non-limiting
Example.
EXAMPLE
This Example provides a comparison of the nitrogen
contents of various streams produced from a natural gas
hydrocarbon supply stream 105 according to the line-up of
Figure 2, with three comparative examples calculated
according to the embodiment of Figure 3 of
US 2008/0066493 discussed above.
The nitrogen contents of a hydrocarbon supply stream
105, composed of natural gas, the high and low pressure
fuel gas streams 107, 215 respectively, the boil off gas
stream 195 and the LNG stream 165 were calculated,
together with additional data for the line-up of Figure 2
disclosed herein and is presented in the Table below
under "Invention".
In the embodiment of Figure 3 of US 2008/0066493, the
high pressure fuel gas stream is provided by conduit 34a,
from the overhead 25 of the upper part 10u of column 10'
CA 02767369 2012-01-05
WO 2011/009832 PCT/EP2010/060409
- 31 -
after heat exchange and compression combined with the
overhead 42 of flash vessel 101 after heat exchange and
compression. It is pointed out that conduit 33, arising
solely form the heat exchange and compression of the
overhead 25 of the upper part 10u of column 10' was
unable to provide sufficient high pressure fuel gas, such
that it was drawn instead from conduit 34a in this
comparison. In the absence of a check valve in line 34,
the conduits 33 and 34a would be in fluid communication.
US 2008/0066493 does not disclose a corresponding low
pressure fuel gas stream. For the purposes of this
comparison, a low pressure fuel gas stream was assumed to
have been extracted from conduit 25 carrying the overhead
of the upper part 10u of column 10'. The boil of gas
stream is found in conduit 22.
The data calculated according to the modified line-up
of Figure 3 of US 2008/0066493 is shown in the Table
below under "Comp. 1", "Comp. 2" and "Comp. 3". "Comp. 1"
represents a comparison with the method according to
Figure 2 disclosed herein taken at the same natural gas
feed stream, low pressure fuel stream, high pressure fuel
stream, boil off gas stream and LNG stream production
rates. "Comp. 2" represents a comparison with the method
according to Figure 2 disclosed herein taken at the same
natural gas feed stream rates and low pressure and high
pressure fuel gas heating values. "Comp. 3" represents a
comparison with the method according to Figure 2
disclosed herein taken at the same natural gas feed
stream and LNG stream rates and low pressure fuel gas
heating value.
It is apparent from the Table below that the method
and apparatus disclosed herein provides nitrogen
rejection to the low pressure fuel gas stream 215, while
CA 02767369 2012-01-05
WO 2011/009832
PCT/EP2010/060409
- 32 -
producing an LNG stream 165 and a high pressure fuel gas
stream 107 having acceptably low nitrogen content.
Table
Invention Comp. 1 Comp. 2 Comp. 3
N2 mol. fraction 0.056 0.056 0.056 0.056
natural gas feed
stream
N2 mol. fraction HP 0.056 0.248 0.285 0.298
fuel gas stream
N2 mol. fraction LP 0.805 0.418 0.409 0.445
fuel gas stream
N2 mol. fraction 0.223 0.154 0.141 0.154
BOG stream
N2 mol. fraction 0.009 0.006 0.005 0.006
treated liquid
hydrocarbon stream
Heating value low 64 234 65 64
pressure fuel gas
stream
Specific power / 14.8 14.2 14.4 14.3
(kW/tpd LNG)
Net power / 14.6 13.9 14.1 14.1
(kW/tpd LNG)
Production 340 3.60 3.60 3.56 3.60
stream days /MTPA
The person skilled in the art will understand that
the present invention can be carried out in many various
ways without departing from the scope of the appended
claims.
