U.S. patent application number 13/375639 was filed with the patent office on 2012-07-26 for process and apparatus for sweetening and liquefying a gas stream.
Invention is credited to Nimalan Gnanendran, Martin Wilkes.
Application Number | 20120186296 13/375639 |
Document ID | / |
Family ID | 43308320 |
Filed Date | 2012-07-26 |
United States Patent
Application |
20120186296 |
Kind Code |
A1 |
Gnanendran; Nimalan ; et
al. |
July 26, 2012 |
PROCESS AND APPARATUS FOR SWEETENING AND LIQUEFYING A GAS
STREAM
Abstract
A process and apparatus for liquefying a gas stream comprising
hydrocarbons and sour species is provided in which the sour species
are removed in liquefied form as the sweetened gas stream is
progressively cooled to liquefaction temperatures. The process
involves cooling the gas stream in a manner to produce a cooled gas
stream comprising gaseous hydrocarbons and residual sour species.
The cooled gas stream is then treated with a cold solvent to
deplete the cooled gas stream of residual sour species. The
resulting cooled sweetened gas stream is then further cooled to
produce liquid hydrocarbons.
Inventors: |
Gnanendran; Nimalan;
(Thornlie, AU) ; Wilkes; Martin; (Dudley Park,
AU) |
Family ID: |
43308320 |
Appl. No.: |
13/375639 |
Filed: |
June 11, 2010 |
PCT Filed: |
June 11, 2010 |
PCT NO: |
PCT/AU2010/000722 |
371 Date: |
April 12, 2012 |
Current U.S.
Class: |
62/637 ;
62/618 |
Current CPC
Class: |
B01D 2252/30 20130101;
F25J 2270/12 20130101; C10L 3/10 20130101; F25J 2220/68 20130101;
B01D 2257/306 20130101; B01D 2257/308 20130101; F25J 2210/66
20130101; F25J 1/0207 20130101; F25J 3/0233 20130101; F25J 2220/64
20130101; F25J 3/0257 20130101; B01D 2257/304 20130101; F25J
2270/14 20130101; Y02C 10/12 20130101; F25J 1/005 20130101; B01D
2257/302 20130101; B01D 2252/2021 20130101; F25J 1/0292 20130101;
F25J 3/0209 20130101; F25J 1/0085 20130101; F25J 2210/40 20130101;
B01D 2257/504 20130101; F25J 1/0265 20130101; F25J 3/0247 20130101;
Y02C 20/40 20200801; B01D 53/1475 20130101; F25J 1/0052 20130101;
F25J 2235/80 20130101; C10L 3/102 20130101; B01D 53/002 20130101;
B01D 2252/205 20130101; F25J 1/0055 20130101; F25J 3/0266 20130101;
F25J 2220/66 20130101; Y02C 10/04 20130101; B01D 2258/06 20130101;
F25J 1/0087 20130101; F25J 1/0288 20130101; Y02C 10/06 20130101;
F25J 1/0022 20130101; F25J 2220/62 20130101; F25J 1/0045 20130101;
B01D 53/1456 20130101; C10L 3/104 20130101; F25J 1/0214 20130101;
B01D 2252/202 20130101; F25J 2205/50 20130101; F25J 2220/60
20130101; F25J 1/0082 20130101 |
Class at
Publication: |
62/637 ;
62/618 |
International
Class: |
F25J 3/00 20060101
F25J003/00 |
Foreign Application Data
Date |
Code |
Application Number |
Jun 12, 2009 |
AU |
2009902752 |
Claims
1. A process for liquefying a gas stream comprising hydrocarbons
and sour species, the process comprising the steps of: a) cooling
the gas stream in a manner to produce a cooled gas stream
comprising gaseous hydrocarbons and residual sour species; b)
treating the cooled gas stream with a solvent to deplete the cooled
gas stream of residual sour species, thereby producing a cooled
sweetened gas stream; and c) cooling the cooled sweetened gas
stream to produce liquid hydrocarbons.
2. The process according to claim 1, wherein in step a), cooling is
conducted in a manner whereby the gas stream is cooled to a first
temperature to produce a mixture of solid and/or liquid sour
species and a vapour containing gaseous hydrocarbons and residual
sour species, and the solid and/or liquid sour species are
separated from the mixture, thereby producing the cooled gas
stream.
3. The process according to claim 2, wherein cooling is conducted
under a first set of temperature and pressure conditions at which
the sour species solidifies and/or a liquid condensate of sour
species forms.
4. The process according to claim 2, wherein the first temperature
is at or just below the temperature at which the sour species
solidifies and/or condenses.
5. The process according to claim 2, wherein the first temperature
is a temperature at which freezable hydrocarbon species
condense.
6. The process according to claim 2, wherein the first temperature
is a temperature at which solubility of the residual sour species
in the solvent used in step b) is optimized.
7. The process according to claim 1 wherein treating the cooled gas
stream with a solvent comprises contacting the cooled gas stream
with a solvent in which the sour species is more soluble than the
gaseous hydrocarbons.
8. The process according to any claim 2, wherein step b) is
performed under temperature conditions close to or at the first
temperature.
9. The process according to claim 1 wherein in step c), cooling is
conducted under a second set of temperature and pressure conditions
at which hydrocarbons in the cooled gas stream condense.
10. The process according to claim 1 wherein in at least one of
step a) and step c), cooling the gas stream comprises a heat
exchange step selected from the group consisting of expanding the
gas stream in one or more expansion steps, effecting an indirect
heat exchange with one or more cooling streams, effecting a direct
heat exchange with a cooling stream, one or more heat exchange
and/or expansion steps.
11. (canceled)
12. (canceled)
13. (canceled)
14. The process according to claim 2 wherein the solid and/or
liquid sour species are separated from the mixture under gravity,
centrifugal force, or with other suitable separation means.
15. The process according to claim 2, wherein the process further
comprises the step of removing the solid sour species, preferably
by heating and melting the solid sour species, thereby forming a
liquid rich in sour species.
16. The process according to claim 15, wherein the process further
comprises heating the solid sour species to a temperature at or
just above the melting point of the solid sour species.
17. The process according to claim 1 wherein prior to performing
step a) the gas stream is cooled in a manner arranged to produce a
liquid stream of carbon dioxide, ethane and C3+ hydrocarbons and a
gas stream having a reduced carbon dioxide concentration.
18. The process according to claim 1 wherein prior to performing
step a), the gas stream is cooled in a manner to produce a C3+
hydrocarbon liquid and a C3+ hydrocarbon-depleted gas stream.
19. A gas liquefaction apparatus for liquefying a gas stream
comprising hydrocarbons and sour species, the gas liquefaction
apparatus comprising: a first cooling zone for cooling the gas
stream in a manner to produce a cooled gas stream comprising
gaseous hydrocarbons and residual sour species, the first cooling
zone being in fluid communication with a source of gas comprising
hydrocarbons and sour species; a separator to separate solids
and/or liquids from the cooled gas stream; a vessel arranged, in
use, to treat the cooled gas stream with a solvent to deplete the
cooled gas stream of residual sour species, thereby producing a
cooled sweetened gas stream; and a second cooling zone in fluid
communication with the vessel, the second cooling zone being
configured to receive and cool the cooled sweetened gas stream to a
second temperature to produce liquid hydrocarbons.
20. A process for recovering liquid carbon dioxide from a gas
stream comprising hydrocarbons and carbon dioxide during
liquefaction, the process comprising the steps of: a) cooling the
gas stream to a first temperature to produce a mixture of solid
and/or liquid carbon dioxide and a vapour containing gaseous
hydrocarbons; b) separating the solid and/or liquid carbon dioxide
from the mixture, thereby producing a cooled gas stream comprising
gaseous hydrocarbons and residual carbon dioxide; c) heating the
separated solid carbon dioxide and producing liquid carbon dioxide
d) treating the cooled gas stream with a solvent to deplete the
cooled gas stream of residual carbon dioxide, thereby producing a
cooled sweetened gas stream; and e) cooling the cooled gas stream
to a second temperature to produce liquefied hydrocarbons.
21. A method of creating a financial instrument tradable under a
greenhouse gas Emissions Trading Scheme (ETS), the method
comprising the step of exploiting a process for liquefying a gas
stream defined by claim 1.
22. A method of creating a financial instrument tradable under a
greenhouse gas Emissions Trading Scheme (ETS), the method
comprising the step of exploiting a gas liquefaction apparatus
defined by claim 19.
23. A method of creating a financial instrument tradable under a
greenhouse gas Emissions Trading Scheme (ETS), the method
comprising the step of exploiting a process for recovering carbon
dioxide from a gas stream comprising hydrocarbons and carbon
dioxide during liquefaction defined by claim 20.
24. A method according to claim 1 wherein the financial instrument
comprises one of either a carbon credit, carbon offset or renewable
energy certificate.
Description
FIELD
[0001] The present invention relates to a process and apparatus for
sweetening and liquefying a gas stream. In particular, the present
invention relates to a process and apparatus for removing sour
species in a liquefied form from the gas stream as the sweetened
gas stream is progressively cooled to liquefaction
temperatures.
BACKGROUND
[0002] Global energy demand is projected to increase by almost 3%
annually over the next twenty-five years. The increasing demand for
the usage of light hydrocarbon gas, such as methane, as a primary
energy source is driving the development of natural gas fields that
had previously been considered sub-economic, including those
containing significant concentrations of carbon dioxide.
Additionally, hydrocarbon gas is increasingly being sourced from
coal bed and coal seam mining operations, associated gas stream
sources, and anthropogenic sources such as landfill gas and
biogas.
[0003] Although hydrocarbon gas combustion produces significantly
lower carbon dioxide emissions than oil or coal, for sources
containing high concentrations of carbon dioxide the advantage is
lessened or even negated if the carbon dioxide removed in
pre-combustion gas processing plants is vented to the atmosphere
instead of being captured and stored, for example in sub-surface
geological formation.
[0004] Additionally, the presence of water and other compounds such
as hydrogen sulphide, mercaptans, and mercury which are also
referred to as "sour" species or contaminants found in hydrocarbon
gas, regardless of the sources listed above, is also problematic.
Water and sour contaminants promote corrosion and form solids under
conditions commonly found in process operations and distribution
networks.
[0005] The formation of solids in pipe work or equipment is
generally undesirable, as the accumulation of such solids
eventually results in decreased operating performance and can
quickly lead to total blockage, breakdown or other damage. For
safety and operational reasons it is necessary to reduce
concentrations of water and sour contaminants down to acceptable
levels.
[0006] Additionally, it is necessary to comply with legal or
commercial requirements concerning maximum allowable concentrations
of sour contaminants within a hydrocarbon gas product stream.
[0007] Accordingly, in the processes currently employed to liquefy
hydrocarbon gas, a feed gas is initially pre-treated to deplete
carbon dioxide to about 50-200 ppm and remove other sour species.
The pre-treatment process is typically a chemical solvent process
(amine), but may also be a physical solvent or a hybrid
membrane/solvent process.
[0008] The pre-treated gas is then dehydrated, typically with
molecular sieves, before feeding it to a liquefaction plant where
the dehydrated sweetened gas is cooled to temperatures at which
light hydrocarbons, in particular methane, condense, typically to
temperatures of about -160.degree. C. For feed gases with
relatively high carbon dioxide content, the capital and energy
expenditure to remove carbon dioxide to about 50-200 ppm by means
of the aforementioned conventional techniques is expensive and
requires significant utility infrastructure, thereby increasing the
environmental footprint of the liquefaction plant.
[0009] U.S. Pat. No. 5,956,971 describes a process for producing
pressurized liquefied natural gas (PLNG) in which the natural gas
feed stream comprises sour species such as CO.sub.2, H.sub.2S or
any other compound that has the potential to form solids at
cryogenic temperatures required to condense methane. In this
process, a separation system containing a controlled freezing zone
("CF2") produces a vapour stream rich in methane and a liquid
stream rich in the freezable component. The vapour stream is then
cooled to a temperature above about -112.degree. C. at a pressure
sufficient to produce a pressurised liquefied natural gas stream.
Under the warmer operating temperature of this process it is
possible to provide PLNG with CO.sub.2 levels as high as about 1.4
mol % CO.sub.2 at temperatures of -112.degree. C. and about 4.2%;
at -95.degree. C. without causing freezing problems in the
liquefaction process.
[0010] There is a continuing need for an improved process for
liquefying natural gas that contains sour species in concentrations
that would freeze during the liquefaction process which can be
integrated with conventional operating conditions of existing
natural gas liquefaction plants, and which reduces the
concentration of sour species such as CO.sub.2 to less than 50
ppm.
[0011] The present invention seeks to overcome at least some of the
aforementioned disadvantages.
SUMMARY
[0012] In its broadest aspect, the invention provides a process and
apparatus for liquefying a gas stream contaminated by sour species
in which the sour species are removed from the gas stream in a
liquefied form as the gas stream is progressively cooled to
liquefaction temperatures.
[0013] Accordingly, in a first aspect of the present invention
there is provided a process for liquefying a gas stream comprising
hydrocarbons and sour species, the process comprising the steps of:
[0014] a) cooling the gas stream in a manner to produce a cooled
gas stream comprising gaseous hydrocarbons and residual sour
species; [0015] b) treating the cooled gas stream with a solvent to
deplete the cooled gas stream of residual sour species, thereby
producing a cooled sweetened gas stream; and [0016] c) cooling the
cooled sweetened gas stream to produce liquid hydrocarbons.
[0017] The term "residual sour species" as used herein refers to a
residual concentration of sour species remaining in a vapour phase,
whereby further cooling under process operating conditions is
unable to appreciably convert the sour species to a solid and/or
liquid phase. For example, where the sour species is carbon
dioxide, a residual concentration of carbon dioxide may be about
2-4%.
[0018] It will be appreciated that the gas stream should be
dehydrated sufficiently to reduce water content to very low
concentrations suitable for LNG production, in particular to a
concentration of 1 ppmv or less, and preferably less than 0.1 ppmv.
An example of a suitable dehydration process includes the
adsorption of water from the gas stream with dessicants, such as
for example, molecular sieves or silica gel. Alternatively,
dehydration by adsorption using glycol or methanol may be possible,
or other suitable dehydration processes known in the art.
[0019] In one embodiment of the invention, in step a), cooling is
conducted in a manner whereby the gas stream is cooled to a first
temperature to produce a mixture of solid and/or liquid sour
species and a vapour containing gaseous hydrocarbons and residual
sour species. The solid and/or liquid sour species are separated
from the mixture, thereby producing the cooled gas stream.
[0020] In one form of the invention, in step a) cooling is
conducted under a first set of temperature and pressure conditions
at which the sour species solidifies and/or a condensate containing
sour species forms. It will be appreciated that said first set of
temperature and pressure conditions will vary in accordance with
the composition of the gas stream. In one embodiment of the
invention, the first temperature is at or just below the
temperature at which the sour species solidifies and/or
condenses.
[0021] In an alternative embodiment of the invention, in particular
where the concentration of sour species in the gas stream can be
regarded as already substantially residual, such as for instance,
pipeline gas, the gas stream is cooled in step a) to a first
temperature at which freezable hydrocarbon species may condense. In
one form of the invention, the condensed hydrocarbon species are
separated from the mixture, thereby producing the cooled gas
stream.
[0022] Additionally and/or alternatively, the gas stream may be
cooled in step a) to a first temperature at which solubility of the
residual sour species in the solvent used in step b) is
optimized.
[0023] In one embodiment of the invention, in step b) treating the
cooled gas stream with a solvent comprises contacting the cooled
gas stream with a solvent in which the sour species is more soluble
than the gaseous hydrocarbons.
[0024] In one embodiment of the invention, step b) is performed
under temperature conditions close to or at the first temperature.
Advantageously, the inventors have found that treating the cooled
gas stream with solvent at temperatures close to or at the first
temperature increases the absorption of sour species in the solvent
thereby resulting in very low concentrations of sour species, such
as for example <50 ppm CO.sub.2, in the cooled sweetened gas
stream.
[0025] Thus, although the first temperature in step a) is primarily
determined by the temperature at which sour species condense, in
instances where the concentration of sour species in the gas stream
can be regarded as already substantially residual, it will be
appreciated that the first temperature to which the gas stream is
cooled is also determined by a balance of considerations between
solubility of sour species in the solvent used in step b), degree
of co-absorption of hydrocarbons in the solvent used in step b),
and the overall refrigeration requirements of the process.
[0026] In one embodiment, in step c), cooling is conducted under a
second set of temperature and pressure conditions at which
hydrocarbons in the cooled gas stream, in particular methane,
condense. It will be appreciated that said second set of
temperature and pressure conditions will vary in accordance with
the composition of the remaining gaseous hydrocarbons in the cooled
gas stream.
[0027] In one form of the invention, in step a) and/or step c)
cooling the gas stream comprises expanding the gas stream in one or
more expansion steps. In an alternative form of the invention, in
step a) and/or step c) cooling the gas stream comprises effecting
an indirect heat exchange with one or more cooling streams.
Suitable cooling streams may be a process stream at a lower
temperature than the gas stream or an external refrigerant stream.
In another alternative form in step a) and/or step c) cooling the
gas stream comprises effecting a direct heat exchange with a
cooling stream. In a preferred form of the invention, in step a)
and/or step c) cooling the gas stream comprises one or more heat
exchange and/or expansion steps.
[0028] In another embodiment of the invention, the solid and/or
liquid sour species are separated from the mixture under gravity,
centrifugal force, or with other suitable separation means.
[0029] In some embodiments the process further comprises the step
of removing the solid sour species, preferably by heating and
melting the solid sour species, thereby forming a liquid rich in
sour species. Such an arrangement is described in WO 2007/030888.
The resultant liquid sour species may be subsequently removed and
diverted to other parts of the plant. For example, a cool liquid
carbon dioxide stream may be used as one of the process streams to
cool the gas stream in step a) by indirect heat exchange.
[0030] In one embodiment, the process comprises heating the solid
sour species to a temperature at or just above the melting point of
the solid sour species.
[0031] In a further embodiment of the invention, prior to
performing step a) the process further comprises the step of
cooling the gas stream in a manner arranged to produce a liquid
stream of carbon dioxide, ethane and C3+ hydrocarbons and a gas
stream having a reduced carbon dioxide concentration. In a still
further embodiment of the invention, prior to performing step a)
the process further comprises the step of cooling the gas stream
under a set of temperature and pressure conditions arranged to
produce a C3+ hydrocarbon liquid and a C3+ hydrocarbon-depleted gas
stream, and separating the C3+ hydrocarbon liquid and the C3+
hydrocarbon-depleted gas stream, for example as described in
WO2008/095258. The gas stream having a reduced carbon dioxide
concentration or the C3+ hydrocarbon-depleted gas stream is then
cooled to a first temperature to produce a mixture of solid and/or
liquid sour species and a vapour containing gaseous hydrocarbons
and residual sour species as described above.
[0032] In a second aspect of the present invention there is
provided a gas liquefaction apparatus for liquefying a gas stream
comprising hydrocarbons and sour species, the gas liquefaction
apparatus being provided with:
a first cooling zone for cooling the gas stream in a manner to
produce a cooled gas stream comprising gaseous hydrocarbons and
residual sour species, the first cooling zone being in fluid
communication with a source of gas comprising hydrocarbons and sour
species; a separator to separate solids and/or liquids from the
cooled gas stream; a vessel arranged, in use, to treat the cooled
gas stream with a solvent to deplete the cooled gas stream of
residual sour species, thereby producing a cooled sweetened gas
stream; and a second cooling zone in fluid communication with the
vessel, the second cooling zone being configured to receive and
cool the cooled sweetened gas stream to a second temperature to
produce liquid hydrocarbons.
[0033] In one embodiment, the first cooling zone and the second
cooling zone, respectively comprise one or more means for cooling
the gas stream. In one form of the invention said cooling means is
a gas expander. Suitable examples of gas expanders include but are
not limited to a Joule-Thomson valve, an orifice or venturi, a
turbo expander, or a turbo expander in sequential combination with
a Joule-Thomson valve. It will be appreciated that the gas expander
can define an inlet of a vessel for cooling the gas stream or an
inlet of the separator. Similarly, it will be understood that the
separator may additionally function as a cooling vessel in which
the gas stream is cooled to a first temperature.
[0034] In another form of the invention said cooling means is a
heat exchanger configured to facilitate indirect heat exchange with
one or more cooling streams. Suitable examples of said heat
exchangers include but are not limited to plate and fin type heat
exchanger, tube-in-shell type heat exchanger, cooling coil, or
coiled bundle. It will be appreciated that the cooling streams may
be a process stream produced upstream or downstream of the heat
exchanger, or an external refrigerant stream in fluid communication
with an external refrigeration system. Exemplary examples of
external refrigeration systems include cascading refrigeration
systems, single mixed refrigerant systems, double mixed refrigerant
systems, ammonia absorption chillers, and so forth.
[0035] In another form of the invention said cooling means is
configured to facilitate direct heat exchange with a cooling
stream.
[0036] In a preferred form of the invention, the first and second
cooling zones respectively comprise one or more heat exchangers
and/or gas expanders.
[0037] In one embodiment of the invention, the vessel arranged to
treat the cooled gas stream with a solvent is an absorber
column.
[0038] In a subsequent embodiment of the invention the apparatus
still further comprises a means for heating the solid sour species
to a temperature at or just above the melting point of the solid
sour species. In one form of the invention, said heating means is a
heater, in particular an immersion heater.
[0039] Depending on gas composition, the first cooling zone may
additionally comprise a fractionating column arranged in use to
operate under a third set of temperature and pressure conditions to
produce a liquid stream of carbon dioxide, ethane and C3+
hydrocarbons and a gas stream having a reduced carbon dioxide
concentration. In another form of the invention, the fractionating
column may be operated under a further set of temperature and
pressure conditions arranged to produce a C3+ hydrocarbon liquid
and a C3+ hydrocarbon-depleted gas stream. The fractionating column
is therefore arranged to perform bulk removal of carbon dioxide
and/or recover valuable C3+ hydrocarbon liquids (i.e. NGLs).
[0040] In a further form of the invention the liquid produced from
the fractionating column may be fed to further fractionating
columns operated under temperature and pressure conditions to
produce LPG components, heavier C5+ hydrocarbon liquids and/or a
carbon dioxide rich stream, as described in WO 2009/095258.
[0041] In prior art systems, carbon dioxide is typically removed
from the gas stream prior to liquefaction by passing it through an
amine absorption unit, and then stripping the carbon dioxide from
the amine absorption unit and venting to atmosphere. Alternatively,
the gaseous carbon dioxide can be liquefied with costly compression
processes. A substantial number of potential gas fields are not
regarded as economically viable as the carbon dioxide content of
the natural gas feed stream at the well head is regarded as too
high to be processed, and disposed of, economically.
[0042] The present invention is based on the realisation that it is
possible to recover liquid carbon dioxide from a gas stream
comprising hydrocarbons and sour species during a gas liquefaction
process. The liquid carbon dioxide can then be pumped and
sequestered with relatively little additional energy requirements,
as opposed to releasing carbon dioxide emissions.
[0043] Thus, in a third aspect of the present invention there is
provided a process for recovering liquid carbon dioxide from a gas
stream comprising hydrocarbons and carbon dioxide during
hydrocarbon liquefaction, the process comprising the steps of:
a) cooling the gas stream to a first temperature to produce a
mixture of solid and/or liquid carbon dioxide and a vapour
containing gaseous hydrocarbons; b) separating the solid and/or
liquid carbon dioxide from the mixture, thereby producing a cooled
gas stream comprising gaseous hydrocarbons and residual carbon
dioxide; c) heating the separated solid carbon dioxide and
producing liquid carbon dioxide; d) treating the cooled gas stream
with a solvent to deplete the cooled gas stream of residual carbon
dioxide, thereby producing a cooled sweetened gas stream; and e)
cooling the cooled gas stream to a second temperature to produce
liquefied hydrocarbons.
[0044] The recovery of liquid carbon dioxide in a form suitable to
store and/or sequester by the process defined above facilitates a
relative reduction in greenhouse gas emissions in comparison to
prior art liquefaction processes in which the carbon dioxide
content of the gas stream would be vented to the atmosphere.
[0045] According to a fourth aspect of the invention there is
provided a method of creating a financial instrument tradable under
a greenhouse gas Emissions Trading Scheme (ETS), the method
comprising the step of exploiting a process for liquefying a gas
stream defined by the first aspect of the invention.
[0046] In a fifth aspect of the invention there provided a method
of creating a financial instrument tradable under a greenhouse gas
Emissions Trading Scheme (ETS), the method comprising the step of
exploiting a gas liquefaction plant defined by the second aspect of
the invention.
[0047] In a sixth aspect of the invention there is provided a
method of creating a financial instrument tradable under a
greenhouse gas Emissions Trading Scheme (ETS), the method
comprising the step of exploiting a process for recovering carbon
dioxide from a gas stream comprising hydrocarbons and carbon
dioxide during liquefaction defined by the third aspect of the
invention.
[0048] In one embodiment of the invention, the financial instrument
comprises one of either a carbon credit, carbon offset or renewable
energy certificate.
BRIEF DESCRIPTION OF THE FIGURES
[0049] Preferred embodiments of the present invention will now be
described, by way of example only, with reference to the
accompanying figures, in which:
[0050] FIG. 1 shows a process flow diagram in accordance with one
embodiment of the present invention whereby a cascade refrigeration
system for liquefying natural gas is integrated with removal of
sour species from a gas stream; and
[0051] FIG. 2 shows a process flow diagram in accordance with
another embodiment of the present invention whereby a dual-mixed
refrigerant system for liquefying natural gas is integrated with
removal of sour species from a gas stream.
DESCRIPTION OF A PREFERRED EMBODIMENT
[0052] In the description of the Figures reference is made to a
natural gas stream as an example of the gas stream that may be
treated in the process according to the present invention. It will
be appreciated, however, that the gas stream may be any stream of
gas that comprises hydrocarbons and sour species. Illustrative
examples of such gas streams include, but are not limited to,
natural gas, coal seam gas, associated gas, landfill gas, and
biogas. The composition of the gas stream may vary significantly
but the gas stream will generally contain methane, ethane, higher
hydrocarbons (C3+), water, and sour species. The term "sour
species" means any one or more of carbon dioxide, hydrogen
sulphide, carbon disulfide, carbonyl sulphide, mercaptans (R--SH,
where R is an alkyl group having one to 20 carbon atoms), sulphur
dioxide, aromatic sulphur-containing compounds, and aromatic
hydrocarbons such as benzene, toluene, xylene, naphthalenes, and so
forth.
[0053] Referring to FIG. 1, in accordance with various aspects of
the present invention, there is shown a gas liquefaction apparatus
10 for performing the process of the present invention, whereby a
cascaded refrigeration system is utilized for cooling. In this
particular embodiment, the cascaded refrigeration system comprises
a first refrigeration circuit 200, a second refrigeration circuit
300 and a third refrigeration circuit 400. The preferred
refrigerant in the first refrigeration circuit 200 is propane. The
preferred refrigerant in the second refrigeration circuit 300 is
ethylene or ethane, most preferably ethylene. The preferred
refrigerant for the third refrigeration circuit 400 is methane, but
may contain small concentrations of nitrogen and other light
hydrocarbons.
[0054] A feed gas stream is introduced to the apparatus 10 via a
line 1 to a heat exchanger 14 where the gas stream is cooled to a
temperature just above the temperature at which hydrocarbon
hydrates form (typically around 20.degree. C.). Water will
condense, and, depending on the composition of the feed gas stream,
heavy hydrocarbon condensates may also form in heat exchanger 14.
Cooling is effected in the heat exchanger 14 by indirect heat
exchange with a propane refrigerant from the first refrigeration
circuit 200. The gas stream is passed via a line 2 to a separator
16 to remove any condensed liquid hydrocarbons, for example C5+,
and water which may have formed, and subsequently forwarded via a
line 3 to a dehydrating unit 18 where it is dehydrated.
[0055] The gas stream may be dehydrated by any suitable dehydration
process that will reduce the water content to very low
concentrations suitable for LNG production, in particular to a
concentration of 1 ppmv or less, and preferably less than 0.1 ppmv.
A suitable dehydration process includes the adsorption of water
from the gas stream with molecular sieves or silica gel.
[0056] Following dehydration, the gas stream is passed from the
dehydrating unit 18 via line 4 to a heat exchanger 20 where the gas
stream is further cooled. Cooling is effected by indirect heat
exchange with a cooled stream of liquid sour species and propane
refrigerant from the first refrigeration circuit 200.
[0057] The gas stream is then passed via line 5 to a heat exchange
tube bundle 22 in indirect heat exchange with a slurry of sour
species solids in liquid sour species where it is further cooled.
The gas stream is passed via line 6 to valve 24 where it is flashed
to a pressure below the critical pressure of the gas, and passed to
a fractionation column 26 in which a condensate mainly comprising
C3 and C4 hydrocarbons and heavier hydrocarbons is separated from
the gas stream. The resultant condensate stream may also contain
carbon dioxide and ethane. The condensate is then directed through
a line 7 to a condensate stabilizer or other fractionators (not
shown) for further treatment to recover other saleable higher
hydrocarbon product(s).
[0058] The operating conditions of the fractionation column 26 are
determined according to the composition of the gas stream, in
particular the content of sour species therein. For example, in a
gas stream containing less than about 15% carbon dioxide, the
operating conditions of the fractionation column 20 are selected to
ensure condensation of substantially all hydrocarbon compounds that
could solidify under temperatures and pressures at which methane
condenses, so that said hydrocarbon compounds are removed from the
gas stream. Generally, the temperature conditions under these
requirements are around -15.degree. C. at the inlet to the
fractionation column 26 and about -30.degree. C.--40.degree. C. at
the outlet of a reflux condenser at a top of the fractionation
column 26, at operating pressures of around 55-60 barg.
[0059] Alternatively, in a gas stream containing greater than about
15% carbon dioxide, the operating conditions of the fractionation
column 26 are selected, primarily, to deplete the gas stream of
carbon dioxide to concentrations less than 15%. Additionally, the
operating conditions are selected to ensure that there is minimal
methane condensation. Generally, the temperature conditions under
these requirements are about -35.degree. C.--45.degree. C. at the
inlet to the fractionation column 20 and about -55.degree.
C.--60.degree. C. at the outlet of a reflux condenser at a top of
the fractionation column 26, at operating pressures of around 55-60
barg. It will be appreciated that under these operating conditions
there is also concomitant condensation of substantially all
hydrocarbon compounds that could solidify under typical methane
liquefaction temperatures.
[0060] The gas stream from the top of the fractionation column 26
is directed through a line 8 to heat exchanger 28 to cool the gas
stream to a temperature marginally greater than a temperature at
which solidification of the sour species in the gas stream occurs.
Generally, the gas stream is cooled to a temperature in a range of
about -65.degree. C. to -70.degree. C. Cooling in heat exchanger 28
may be obtained from indirect heat exchange with process streams
derived downstream of the apparatus 10, such as for instance,
liquefied hydrocarbon or refrigerant streams from an external
refrigeration system. In this particular embodiment, the cooling
stream is ethylene refrigerant from the second refrigeration
circuit 300.
[0061] The gas stream is then fed via line 9 to an inlet 30 of
separation vessel 32. The gas stream is expanded using a
Joule-Thomson valve or other suitable expansion means such as a
turbo expander to further cool the stream as it enters the vessel
32. In one embodiment, the gas stream is expanded using a turbo
expander in sequential combination with the Joule-Thomson valve. In
another form of the invention, the Joule-Thomson valve can define
the inlet 30 of the vessel 32.
[0062] The process of expanding the gas stream upon introduction to
the vessel 32 is arranged to afford temperature and pressure
conditions within the vessel 32 at which the sour species contained
in the gas stream solidify and/or liquefy. The process of expansion
typically cools the gas stream entering the vessel 32 at inlet 30
to about -80 to -95.degree. C. at a typical pressure range of 15 to
25 bar.
[0063] Upon cooling the gas stream, as described above, a small
amount of liquid condensate of NGL may also form under the
temperature and pressure conditions in the cooling vessel 32.
[0064] The solid sour species and the liquid condensate migrate to
a lower portion of the vessel 32 under gravity separation, thereby
forming a slurry of natural gas liquids and solid and/or liquid
sour species. In other embodiments, separation may be achieved or
enhanced by the use centrifugal force or inlet devices designed to
coalesce droplets or agglomerate solid particles.
[0065] The slurry of solid sour species is then heated to a
temperature at least marginally greater than the solidification
temperature of the solid sour species to convert the solid sour
species to a liquid phase in the lower portion of the vessel 32 and
afford a liquid stream rich in the sour species. The nature and
concentration of the sour species in the liquid phase is highly
dependant on the composition, of the gas stream. For example,
typically concentrations of carbon dioxide in the liquid phase are
>70%. Typically, the vessel 32 is provided with an immersion
heater which heats the slurry up to a temperature marginally
greater than the melting point temperature of the solid sour
species. In this particular embodiment, the immersion heater
comprises the heat exchanger tube bundle 22 which cools the gas
stream while heating the slurry. In small applications, the
immersion heater may comprise an electric immersion heater.
[0066] The liquid stream rich in the sour species is removed from
the vessel 32 through conduit 11. Under processing conditions where
the liquid stream is rich in liquid carbon dioxide, the liquid
stream may be directly pumped to a liquid carbon dioxide
sequestration site, or disposed of for retail sale. Prior to
sequestration or storage, the liquid stream rich in sour species
may be used as a cooling stream in any one or more of the heat
exchangers of the apparatus 10 to conserve energy within the
apparatus 10. In this particular embodiment, the liquid stream rich
in sour species is used as a cooling stream in heat exchanger
20.
[0067] The gas stream leaving vessel 32 contains residual sour
species and is directed to a solvation zone 38. The solvation zone
38 may be disposed in an upper portion of the cooling vessel 32, as
shown in FIG. 1. The cooled partially sweetened gas stream may be
directed to the solvation zone 38 of the vessel 32 through a
chimney tray 40 or a non-return valve.
[0068] In an alternative embodiment (not shown), the solvation zone
38 is located externally of the vessel 38 and a line is arranged in
fluid communication between the vessel 32 and the solvation zone 38
to direct the cooled partially sweetened gas stream therebetween.
In the alternative embodiment, the solvation zone 38 may comprise
an absorber column.
[0069] The solvation zone 38, whether it is located internally or
externally of the separating vessel 32, is configured to operate
under temperature conditions close to or at the temperature to
which the gas stream is cooled in separating vessel 32. As will be
appreciated, the absorption of sour species, in particular carbon
dioxide, in the solvent typically increases with a decrease in
operating temperature.
[0070] This factor is thus a driver for minimizing the operating
temperature of the solvation zone as it leads to a reduced solvent
circulation and regeneration requirements. Accordingly, where an
absorber column is employed as the solvation zone 38, the absorber
column is connected directly to the separating vessel 32 and
operated at a temperature at or close to the first temperature in
the separating vessel 32.
[0071] The operating temperature of the solvation zone 38 is also
selected on a consideration of a counter balance with the
co-absorption of methane in the solvent and overall refrigeration
requirements, both of which increase with reducing temperature.
Accordingly, the operating temperature of the solvation zone 38 is
selected to ensure that sufficient sour species, in particular
carbon dioxide, is absorbed in order to meet the required
specification for liquefaction of methane (e.g. <50 ppm
CO.sub.2) whilst minimizing the co-absorption of methane, solvent
circulation, and refrigeration and power requirements.
[0072] The solvation zone 38 is configured to optimize the contact
area between the cooled liquid solvent and the cooled partially
sweetened gas stream. In one embodiment of the invention, the
solvation zone 38 is provided with liquid-gas intermixing means 42.
Suitable examples of liquid-gas intermixing means 42 include, but
are not limited to, a plurality of trays or structured packing
disposed in the solvation zone 38 of the vessel 32.
[0073] The cooled liquid solvent is introduced into the solvation
zone 38 of the vessel 32 through inlet 44 disposed above the
liquid-gas intermixing means 42. In this particular embodiment, the
inlet 44 is a distributor designed to deliver liquid solvent evenly
to the liquid-gas intermixing means 42, such as a parting box and
trough arrangements, drip tubes and/or lateral pipe
distributors.
[0074] The cooled liquid solvent is selected to mix with and
solvate the gaseous sour species in the partially sweetened gas
stream and form a liquid solution of the gaseous sour species.
Suitable examples of cooled liquid solvents in accordance with the
present invention include but are not limited to NGL condensate
comprising a mixture of C2, liquefied petroleum gas components, C3
and C4 and C5+ hydrocarbon components, or one or more other
solvents including methanol, ethanol, dimethyl sulfoxide, ionic
liquids including imidazolium, quaternary ammonium, pyrrolidinium,
pyridinium, or tetra alkylphosphonium. For example, the cooled gas
stream may be treated with methanol cooled to about -90.degree. C.
to absorb any residual sour species.
[0075] In this way, the cooled partially sweetened gas stream is
sweetened to concentrations of 50-200 ppm CO.sub.2, thereby making
the cooled sweetened gas stream suitable to undergo further cooling
to condense the light hydrocarbons, in particular methane. The
cooled sweetened gas stream is removed from the solvation zone 38
at outlet 46 via line 11, and directed to a second cooling zone 48
comprising one or more heat exchangers where the cooled sweetened
gas stream is cooled to a temperature at or below the temperature
at which the hydrocarbons in the gas stream condense. Preferably,
the cooled sweetened gas stream is cooled to a temperature below
the methane boiling point, for example to a temperature between
about -140.degree. C. to -150.degree. C. In this particular
embodiment the second solvation zone 48 comprises a heat exchanger
where cooling is provided by a methane refrigerant stream from the
third refrigeration circuit 400.
[0076] The liquefied stream may be further expanded in expander 50
and cooled to about -162.degree. C. and atmospheric pressure for
storage purposes. In an alternative embodiment, the liquefied
stream may be stored under slightly elevated pressure (e.g. about 5
Bara) and temperatures for storage as pressurized LNG (or
PLNG).
[0077] It will be appreciated that if the process of the present
invention is modified to produce pressurized liquid hydrocarbons,
such as PLNG, the acceptable content of impurities in the gas
stream (and indeed the CO.sub.2 content) may be higher as
pressurized LNG can hold more sour species, in particular CO.sub.2,
without freezing of these compounds occurring at temperatures and
pressures where methane liquefaction takes place.
[0078] Rich solvent, in other words, spent solvent laden with
absorbed sour species, is recovered from the solvation zone 38 and
regenerated in a stripper column 52 to produce lean solvent along
with make-up solvent. The lean solvent combined with make-up
solvent is cooled in heat exchanger 54 and pumped to the inlet 44
of the liquid-gas intermixing means 42. The vapour sour species
produced in the stripper column can be compressed and cooled to
produce a sour liquid to be combined with sour liquid produced in
column 32 to be then disposed (not shown).
[0079] Referring to FIG. 1, the configuration and operation of the
first refrigeration circuit 200, having the highest boiling point
among the three refrigeration circuits 200, 300, 400 employed in
the present invention, such as propane, is described.
[0080] Propane refrigerant vapour stream 202 is cooled and
condensed in an air-cooled condenser 204 and is directed via stream
202 to a pressure reduction device 206, for example a Joule-Thomson
valve, and expanded to a lower pressure, thereby flashing a portion
of the propane refrigerant stream and lowering its temperature. The
resulting two-phase stream is separated in separator 208.
[0081] The top vapour product is passed via line 210 to an inlet of
a propane compressor 212. Propane vapour is compressed in the
propane compressor 212 and returned via line 214 to the propane
condenser 204.
[0082] The bottom liquid product 216 is split and each resultant
stream is expanded to a lower pressure in a pressure expansion
device, further lowering its temperature and then used as
respective cooling streams in indirect heat exchange with the
following: [0083] a) feed gas in heat exchanger 14 via conduit 218;
[0084] b) dehydrated feed gas in heat exchanger 20 via conduit 220;
[0085] c) second refrigerant stream, eg. ethylene in heat exchanger
304 via conduit 222; and [0086] d) third refrigerant stream, eg.
methane in heat exchanger 404 via conduit 224.
[0087] The respective refrigerant streams from conduits 226, 228,
230, and 232 are combined and directed to the inlet of propane
compressor 212, where the combined stream is compressed in the
propane compressor 212 and returned via line 214 to the propane
condenser 204.
[0088] The configuration and operation of the second refrigeration
circuit 300, eg. ethylene, is now described. As illustrated in FIG.
1, the ethylene refrigerant stream 302 is condensed in heat
exchanger 304. It is then split and each stream directed to a
pressure reduction device 306 and expanded to a lower pressure,
thereby flashing a portion of the ethylene refrigerant stream and
lowering its temperature, making it suitable for use as respective
cooling streams in indirect heat exchange with the following:
[0089] a) cooled dehydrated gas stream in heat exchanger 28 via
conduit 312; and [0090] b) third refrigerant stream, eg. methane in
heat exchanger 404 via conduit 314.
[0091] The respective ethylene refrigerant streams from conduits
316 and 318 are combined and directed to the inlet of an ethylene
compressor 320, where the combined stream is compressed and
returned via line 302 to the heat exchanger 304.
[0092] The configuration and operation of the third refrigeration
circuit 400, eg. methane, is now described. As illustrated in FIG.
1, the methane refrigerant stream chilled in heat exchanger 404 is
directed to a turbo expander 406 via line 408 and expanded to a
lower pressure, thereby lowering its temperature.
[0093] The resulting methane refrigerant stream 410 is used as a
cooling stream in indirect heat exchange with the sweetened gas
stream in heat exchanger 48. The methane refrigerant stream is
directed to a dual coupled compressor 412a, 412b via line 414,
before being passed to an air cooled heat exchanger 416, and
returned via line 402 to the heat exchanger 404.
[0094] It will be appreciated that the process of the present
invention may be integrated with any light hydrocarbon liquefaction
process, independent of the type of refrigeration circuit or number
of circuits used.
[0095] In addition to the cascaded refrigeration system represented
in FIG. 1, other refrigeration circuits for liquefying light
hydrocarbon, in particular methane, known to the art can also be
integrated with the present invention. The systems described herein
merely provide exemplary illustrations of the use of the present
invention with other refrigeration systems for liquefying feed gas
and should not be considered as limiting the methods of the present
invention to the specific refrigeration systems described.
[0096] Another example representing a typical arrangement of a
dual-mixed refrigeration circuit is described below with reference
to FIG. 2. In this particular embodiment, the dual-mixed
refrigerant circuit comprises a first mixed refrigerant circuit 500
and a second mixed refrigerant circuit 600. The preferred
refrigerant in the first mixed refrigerant circuit 500 comprises
about 40%-60% ethane and about 40%-60% propane. The preferred
refrigerant in the second mixed refrigerant circuit 600 comprises
about 0-10% nitrogen, about 40-50% methane, about 40%-50% ethane,
and about 0-10% propane.
[0097] The application and operation of the present invention shown
in FIG. 2 in this example is essentially similar to the previous
example described with reference to FIG. 1 and is briefly described
here where like numerals refer to like parts throughout. The
differences mainly concern the integration of the first and second
mixed refrigerant circuits 500, 600.
[0098] A feed gas stream is introduced to the apparatus 10' via a
line 1 to a heat exchanger 14 where the gas stream is cooled to
ambient conditions, preferably to a temperature just above the
temperature at which hydrocarbon hydrates form (typically around
20.degree. C.). Depending on the composition of the feed gas
stream, heavy hydrocarbon condensates may also form in heat
exchanger 14. Cooling is effected in the heat exchanger 14 by
indirect heat exchange with the second mixed refrigerant from the
first second mixed refrigerant circuit 600. The gas stream is
passed via a line 2 to a separator 16 and subsequently forwarded
via a line 3 to a dehydrating unit 18 where it may be dehydrated as
described previously.
[0099] Following dehydration, the gas stream is passed from the
dehydrating unit 18 via line 4 to a heat exchanger 20 where the gas
stream is cooled by indirect heat exchange with a cooled stream of
liquid sour species, and subsequently via line 4a to a multi-pass
heat exchanger 20a where the gas stream is further cooled by
indirect heat exchange with the first mixed refrigerant.
[0100] The gas stream is then passed via line 5 to a heat exchange
tube bundle 22 in indirect heat exchange with a slurry of sour
species solids in liquid sour species where it is further cooled.
The gas stream is passed via line 6 to valve where it is flashed to
a pressure below the critical pressure of the gas, and passed to a
fractionation column 26 in which a condensate of liquid petroleum
gas (mainly comprising C3 and C4 hydrocarbons) and heavier
hydrocarbons is separated from the gas stream. The resultant
condensate is then directed through a line 7 to a condensate
stabilizer or other fractionators (not shown) for further treatment
to recover other saleable higher hydrocarbon product(s).
[0101] The operating conditions of the fractionation column 26 may
be as described previously.
[0102] The gas stream from the top of the fractionation column 26
is directed through a line 8 to a multi-pass heat exchanger 28a to
cool the gas stream to a temperature marginally greater than a
temperature at which solidification of the sour species in the gas
stream occurs. Generally, the gas stream is cooled to a temperature
in a range of about -65.degree. C.--70.degree. C. In this
particular embodiment, cooling in heat exchanger 28a may be
obtained from indirect heat exchange with the secondary refrigerant
stream.
[0103] The cooled gas stream is then fed via line 9 to an inlet 30
of separation vessel 32. The gas stream is expanded using a
Joule-Thomson valve or other suitable expansion means such as a
turbo expander to further cool the stream as it enters the vessel
32. The gas stream entering the vessel 32 at inlet 30 to about -50
to -90.degree. C. at a typical pressure range of 20 to 30 bar.
[0104] Upon cooling the gas stream, as described above, in addition
to solid and/or liquid sour species, a small amount of liquid
condensate of NGL may also form under the temperature and pressure
conditions in the cooling vessel 32. The solid sour species and the
liquid condensate migrate to a lower portion of the vessel 32 under
gravity separation, thereby forming a slurry of natural gas liquids
and solid and/or liquid sour species, as described previously.
[0105] The slurry of solid sour species is then heated to a
temperature at which the solids melt by indirect heat exchange with
tube bundle 22. The liquid stream rich in the sour species is
removed from the vessel 32 through conduit 11, and may be further
dealt with as described with reference to FIG. 1.
[0106] The cooled partially sweetened gas stream with residual sour
species may be treated with liquid solvent to deplete it of
residual sour species by directing the cooled partially sweetened
gas stream to a solvation zone 38 in an upper portion of the
cooling vessel 32, as shown in FIG. 2 through a chimney tray 40. As
previously described with reference to FIG. 1, cooled liquid
solvent, preferably methanol, is introduced into the solvation zone
38 of the vessel 32 through inlet 44 disposed above a liquid-gas
intermixing means 42.
[0107] The resulting cooled sweetened gas stream is removed from
the solvation zone 38 at outlet 46 via line 13, and is directed to
a second cooling zone 48a comprising a multi pass heat exchanger
where the cooled sweetened gas stream is cooled to a temperature at
or below the temperature at which the hydrocarbons in the gas
stream condense. Preferably, the cooled sweetened gas stream is
cooled to a temperature below the methane boiling point, for
example to a temperature between about -140.degree. C. to
-150.degree. C. by indirect heat exchange with the second mixed
refrigerant.
[0108] The liquefied stream may be further expanded in expander 50
and cooled to about -162.degree. C. and atmospheric pressure for
storage purposes.
[0109] Rich solvent from the solvation zone 38 may be regenerated
as described previously with reference to FIG. 1. Similarly, the
liquid stream recovered from the fractionator 26 may be further
processed as described previously with reference to FIG. 1. The
sour vapour stream produced in column 52 can be compressed and
liquefied to be combined with the sour liquid stream produced in
column 32 to be then disposed (not shown).
[0110] Referring to FIG. 2, the configuration and operation of the
first mixed refrigerant circuit 500 is described.
[0111] First mixed refrigerant stream 502 is withdrawn from the
first mixed refrigerant cooler 504 and is directed to a heat
exchanger 506 and further cooled. The cooled first mixed
refrigerant stream is split. A first portion of the split stream is
directed via line 508 to a pressure reduction device 510 and
expanded to a lower pressure, thereby lowering its temperature. The
cooled first portion of the split stream is passed through heat
exchanger 506 in countercurrent indirect heat exchange with the
first mixed refrigerant stream and the second mixed refrigerant
stream, then directed via line 512 to an inlet of a compressor 514
where it is compressed and returned via line 516 to the first mixed
refrigerant cooler 504.
[0112] A second portion of the split stream is passed through heat
exchanger 20a via line 518, then directed to a pressure reduction
device 520 and expanded to lower its temperature. The cooled second
portion of the split stream is then redirected through heat
exchanger 20a in countercurrent indirect heat exchange with the
first mixed refrigerant stream, the second mixed refrigerant stream
and the dehydrated gas stream.
[0113] The second portion of the split stream is then passed via
line 522 to an inlet of the compressor 514 where it is compressed
and returned via line 516 to the first mixed refrigerant cooler
504.
[0114] Referring to FIG. 2, the configuration and operation of the
second mixed refrigerant circuit 600 is now described.
[0115] Second mixed refrigerant stream 602 is withdrawn from the
second mixed refrigerant cooler 604 and is directed to a heat
exchanger 506 and further cooled.
[0116] The cooled second mixed refrigerant stream is directed via
line 606 to heat exchanger 20a, and subsequently passed to
separator 608 via line 610.
[0117] The top product from the separator 608 is passed to heat
exchanger 28a via line 612 and subsequently to heat exchanger 48a
via line 614. The resulting second refrigerant stream is expanded
in pressure reduction device 616 and the temperature of said stream
is lowered. The expanded stream is re-directed to heat exchanger
48a via line 618 where it is used to cool the sweetened gas from
the solvation zone 38 to temperatures at which hydrocarbons
condense as described previously. The expanded stream is also used
to cool the second refrigerant stream in heat exchanger 48a.
[0118] After passing through heat exchanger 48a, the stream is
directed to heat exchanger 28a via line 620 where it is used to
cool the dehydrated gas stream and the second refrigerant
stream.
[0119] Subsequent to pass through heat exchanger 28a, the stream is
directed to heat exchanger 14 via line 622 where it is used to cool
the feed gas stream. The stream is then passed to an inlet of
compressor 624 via line 626.
[0120] The bottoms product of separator 608 is passed to heat
exchanger 28a via line 628. The resulting cooled stream is directed
to a pressure reduction device 630 and re-directed to heat
exchanger 28a via line 620.
[0121] It will be readily appreciated that the various embodiments
of the process and apparatus of the present invention may be
employed to liquefy gas streams with varying composition. In
particular, the components comprising the first cooling zone for
cooling the gas stream in a manner to produce a cooled gas stream
comprising gaseous hydrocarbons and residual sour species, may vary
depending on the composition of the feed gas. For example, for gas
streams rich in methane and lean in sour species, such as pipeline
specification gas where the concentration of sour species therein
can be described as residual, the first cooling zone may comprise
one or more cooling means as previously discussed to merely cool
the gas stream to the desired temperature. Alternatively, for gas
streams rich in carbon dioxide, the first cooling zone may comprise
one or more cooling means configured to deplete the gas stream of
sour species to residual concentrations, including fractionating
columns configured for bulk removal of carbon dioxide for carbon
dioxide concentrations greater than about 20-25%. In a further
alternative, for gas streams rich in carbon dioxide and NGL
components, the first cooling zone may comprise one or more cooling
means configured to deplete the gas stream of sour species to
residual concentrations and one or more fractionators to deplete
the gas stream of C3+ hydrocarbons, and so forth.
[0122] As will be evident from the foregoing description, the
process and apparatus of the present invention facilitates a
reduction of greenhouse gas emissions in comparison with
conventional technologies for liquefaction of a gas stream
contaminated by sour species.
[0123] A financial instrument tradable under a greenhouse gas
Emissions Trading Scheme (ETS) may be created by exploitation of
the apparatus 10 of the present invention or a gas liquefaction
plant employing the processes of the present invention. The
instrument may be, for example, one of either a carbon credit,
carbon offset or renewable energy certificate. Generally, such
instruments are tradable on a market that is arranged to discourage
greenhouse gas emission through a cap and trade approach, in which
total emissions are `capped`, permits are allocated up to the cap,
and trading is allowed to let the market find the cheapest way to
meet any necessary emission reductions. The Kyoto Protocol and the
European Union ETS are both based on this approach. One example of
how credits may be generated by using the gas liquefaction plant
follows. A person in an industrialised country wishes to get
credits from a Clean Development Mechanism (CDM) project, under the
European ETS. The person contributes to the establishment of a gas
liquefaction plant comprising one or more gas liquefaction
apparatuses according to the present invention or a gas
liquefaction plant employing the processes of the present
invention. Credits (or Certified Emission Reduction Units where
each unit is equivalent to the reduction of one metric tonne of
CO.sub.2 or its equivalent) may then be issued to the person. The
number of CERs issued is based on the monitored difference between
the baseline and the actual emissions. It is expected by the
applicant that offsets or credits of a similar nature to CERs will
be soon available to persons investing in low carbon emission
energy generation in industrialised nations, and these could be
similarly generated.
[0124] Now that embodiments have been described, it will be
appreciated that some embodiments have some of the following
advantages: [0125] the gas liquefaction processes and apparatus is
suitable for treatment of gas streams with high carbon dioxide
content, in particular gas streams from gas fields which were
previously economically unviable to develop because of the high
capital and operation expenditure associated with carbon dioxide
separation; [0126] the gas liquefaction apparatus of the present
invention occupies a relatively small footprint and thus can be
scaled for production of LNG from small to medium scale gas stream
sources which were previously economically unviable to develop
because production values did not justify capital expenditure, such
as for example high CO.sub.2 content small to medium scale stranded
gas fields, small to medium scale high CO.sub.2 coal bed methane,
biogas, and landfill gas sites. [0127] a "front-end" gas
pre-treatment unit to remove carbon dioxide as used in conventional
LNG plants is no longer required and thus there will be a
significant reduction in capital expenditure estimated to be
between 10-300 of the total cost of an LNG process unit; [0128] the
redundancy of the "front-end" gas pre-treatment unit simplifies the
operation of the liquefaction plant, and removes associated utility
requirements such as water treatment and heating systems, thereby
reducing fuel usage, energy consumption, and operational and
maintenance costs; [0129] carbon dioxide is separated in liquid
form suitable for sequestration as opposed to being vented into the
atmosphere as with conventional solvent extraction and/or membrane
separation techniques; [0130] carbon credits may be generated; and
[0131] the gas liquefaction apparatus occupies a relatively small
footprint and thus can be scaled for production of LNG for use as
vehicle fuel in remote locations, such as for example, remote mine
sites.
[0132] In the description of the invention, except where the
context requires otherwise due to express language or necessary
implication, the words "comprise" or variations such as "comprises"
or "comprising" are used in an inclusive sense, i.e. to specify the
presence of the stated features, but not to preclude the presence
or addition of further features in various embodiments of the
invention.
[0133] It is to be understood that, although prior art use and
publications may be referred to herein, such reference does not
constitute an admission that any of these form a part of the common
general knowledge in the art, in Australia or any other
country.
[0134] Numerous variations and modifications will suggest
themselves to persons skilled in the relevant art, in addition to
those already described, without departing from the basic inventive
concepts. All such variations and modifications are to be
considered within the scope of the present invention, the nature of
which is to be determined from the foregoing description.
* * * * *