Note: Descriptions are shown in the official language in which they were submitted.
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A METHOD TO RECOVER AND PROCESS METHANE AND CONDENSA ________________ l'ES
FROM
FLARE GAS SYSTEMS
FIELD
[0001] This relates to a method that recovers and processes methane and
condensates from
flare gas systems and allows it to be transported economically. The method
recovers and
processes hydrocarbons from a gas flare system to produce natural gas liquids
(NGL), cold
compressed natural gas (CCNG), compressed natural gas (CNG) and liquid natural
gas
(LNG) in proportions dictated by economic considerations.
BACKGROUND
[0002] New drilling and fracking processes have substantially increased oil
production.
A by- product of oil production is associated gas. Where gas transmission
pipelines are
near these oil production wells, the volume and quality of the co-produced
associated gas
dictates whether to process and compress to these transmission gas pipelines
or simply to
flare it. In cases where transmission gas pipelines are not readily available
or do not have
additional capacity, oil producers simply flare it. Presently, due to
increased awareness
and concern about greenhouse gas (GHG) emissions and the impact in climate
change,
governments are implementing new regulations to limit the production and
release of
hydrocarbon derived GHG emissions. Oil producers who fail to comply are
penalized at a
cost per a tonne of GHG emissions produced over their allowable limit. The
purpose of
the penalty is to provide an incentive for oil producers to recover, use,
and/or sell these
flared hydrocarbon gases. There are various processes available that recover
hydrocarbon
flare gas, howeve:r the capital and operating costs of these processes arc
normally higher
than paying the penalty and hence the option of flaring continues. There is a
need for a
process that allows producers to profit more from the recovery of these
hydrocarbon gases
compared to the cost of simply flaring it.
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SUMMARY
[0003] According to an aspect, there is provided a method that permits the C2+
fractions
of co-produced gas from an oil production facility to be recovered and
processed, making
them available as value added products. In addition, the C2- fraction may be
recovered as
liquid natural gas (LNG), cold compressed natural gas (CCNG) and/or compressed
natural
gas (CNG). As will be discussed, the process may be used to achieve a higher
recovery of
associated gas co-produced from an oil production facility economically, both
in capital
and operating costs.
[0004] According to an aspect, there is provided a method to recover, process
and condense
hydrocarbons gases co-produced at oil production facilities. First, a
pressurized hydrocarbon
gaseous stream is treated with methanol to remove its water fraction. Second,
the
hydrocarbon gaseous stream is pre-cooled to condense and remove the heavier
hydrocarbon
fractions. Third, the gaseous fraction is split into two streams, a Natural
Gas Liquids (NGL)
recovery stream and a Liquified Natural Gas (LNG) feed stream. The NGL
recovery stream
is then partially depressurized through an expander, cooling and feeding the
gas into a
fractionation unit where the gas is stripped from its condensates to recover
the C2+ fractions
in the gas stream. The LNG feed stream is further cooled, and the produced
condensates
are separated and depressurized through a JT valve as a reflux stream into the
fractionation unit. The gaseous LNG feed stream is then processed in a
stripping column
to remove the CO2 fraction by contact in a countercurrent flow with
refrigerated methanol.
The CO2 stripped LNG feed stream is further cooled in a heat exchanger by a
cryogenic
gaseous stream from the LNG receiver. The LNG feed stream produced condensate
fraction is separated and streamed to the fractionator through a JT valve as a
reflux stream.
The gaseous processed LNG feed stream is depressurized through a gas expander
into a
receiver to produce LNG and a cryogenic gaseous stream. The produced LNG is
pumped
to storage. The cryogenic gaseous stream is warmed in counter current heat
exchangers,
compressed and cooled to produce Cold Compressed Natural Gas (CCNG). The lean
overhead gas from the fractionator is warmed up in counter-current heat
exchangers and
compressed to produce Compressed Natural Gas (CNG). The fractionator bottoms,
the
C2+ fractions (NGL's) are recovered and pumped to storage.
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[0005] A feature of the proposed method is the ability to process a gaseous
stream that
normally is being flared into valuable and transportable hydrocarbons. A
second feature
of the process is the use of methanol to remove water and CO2 fractions from
the feed gas
at two distinct operating conditions to meet LNG product specifications. To
strip and
remove the CO2 fraction from the feed gas in preparation to produce LNG, the
methanol
must be refrigerated. The refrigeration energy required in the process is
provided by heat
exchange and recovery of the coolth energy produced by the depressurization of
the
process gaseous streams. The process can meet various modes of operation to
produce;
Natural Gas Liquids (NGL's), Cold Compressed Natural Gas (CCNG), Liquid
Natural
Gas (LNG) and Compressed Natural Gas (CNG). A mixture of lean natural gas and
stripped CO2 rich gas provides fuel gas to a power plant to meet electrical
load demand of
the process rotating equipment (pumps and compressors), thus allowing for a
stand- alone
mode of operation.
[0006] In one aspect, the present method is a process that recovers and
processes
hydrocarbons gases co-produced at oil production facilities. One feature of
the method is
the ability to Operate under varying flow rates, feed compositions and
pressures. Fuel gas
streams co-produced at oil production facilities are variable since they arc
fed from
multiple wells. The inventive process can meet any process flow variations,
which are not
uncommon at oil production facilities gas systems. The process is not
dependent on a
refrigeration plant size and or equipment as employed in conventional LPG
recovery
processes.
[0007] The process refrigeration requirements are provided by controlling the
plant inlet
gas pressure and its subsequent heat exchange and pressure drops.
[0008] Another benefit of the inventive process is the use of methanol to
remove both the
water and carbon dioxide from the inlet gas feed stream at two different and
distinct methanol
operating conditions; warm and refrigerated methanol.
[0009] As will hereinafter be described, the above method can operate at any
oil production
facilities or wells where hydrocarbon gases are produced.
[0010] The above described method was developed with a view to recover and
process into
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various products hydrocarbon gases co-produced at oil production facilities.
[0011] According there is provided a process, which includes compressing and
cooling a
produced gas stream to ambient temperature, add and mix methanol at a
controlled dosage to
remove the feed gas water fraction. Pre-cool, separate and remove the water
fraction. Further
.. cool and separate hydrocarbon condensates, split the gaseous stream into a
fractionation
stream and LNG production stream. Expand and fractionate the fractionation
stream. Further
cool the LNG production stream and route produced hydrocarbon condensates to
fractionator.
Strip the CO2 from the gaseous LNG feed stream, cool it further, separate
produced
hydrocarbon condensates and route it to the fractionator, route the LNG
processed gaseous
feed stream to a gas expander to depressurize condense and produce LNG. The
cryogenic
gaseous stream from the LNG receiver is recovered to produce CCNG. The
fractionator
overhead stream (lean natural gas) is compressed to produce CNG. A portion of
the lean
gas is mixed with a CO2 rich gas to provide fuel to a power generation plant.
[0012] According to an aspect, there is provided a method to recover and
process
hydrocarbons from a gas flare system to produce natural gas liquids (NGLs),
cold compressed
natural gas (CCNG), compressed natural gas (CNG) and liquid natural gas (LNG),
the
method comprising the steps of: providing a compressor to meet the feed gas
pressure
requirements into the plant; providing heat exchangers to provide the thermal
energy required
for the regenerator and fractionator bottoms reboiler streams; providing a
heat exchanger to
provide the thermal energy required for a methanol regenerator bottoms
reboiler stream;
providing an in-line gas mixer for methanol addition; providing a heat
exchanger to provide
the thermal energy required for a fractionator bottoms reboiler stream;
providing a separator
to recover the methanol/water mixture; providing a solvent recovery membrane
system for
methanol recovery; providing heat exchangers in series to recover cold thermal
energy;
providing a separator to separate the gaseous hydrocarbon fraction from the
produced
condensates; providing a gas expander to generate shaft power and cryogenic
temperatures;
providing a gas fractionator column to produce a gaseous lean gas stream and a
liquid mixture
of hydrocarbons; providing heat exchangers to recover cold thermal energy from
a
fractionator overhead stream; providing a separator to separate the gaseous
hydrocarbon
.. fraction from the produced condensates; providing a secondary reflux stream
from produced
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and recovered condensates; providing a CO2 stripping column employing
refrigerated
methanol as the CO2 stripping agent; providing a CO2 regeneration unit;
providing an heat
exchangers by-pass control system to refrigerate methanol; providing a
separator to separate
the gaseous hydrocarbon fraction from the produced condensates; providing a
primary reflux
5 stream from produced and recovered condensates; providing a second gas
expander to
generate shaft power and cryogenic temperatures; providing a separator to
separate a
cryogenic gaseous stream from produced LNG; providing heat exchangers to
recover cold
thermal energy from a cryogenic overhead stream of an LNG separator; providing
an heat
exchangers by-pass control system to refrigerate methanol; providing heat
exchangers to
refrigerate methanol; providing heat exchangers to produce CCNG; providing
compressors to
produce CNG; and providing a fuel gas stream to power an auxiliary power
plant.
[0013] According to other aspects, the method may comprise one or more of the
following
aspects, alone or in combination: the heat requirements for the methanol
regenerator and gas
fractionator may be provided by heat generated in an input compressor; the
heat requirements
for the methanol regenerator and gas fractionator provided by heat generated
in an input
compressor may be temperature controlled by an air heat exchanger; methanol
may be used to
dry the feed gas; the methanol may be separated from the water in a solvent
membrane unit;
high pressure recovered condensate may be employed as a secondary reflux to
the
fractionator; methanol may be refrigerated by recovered cold thermal energy
and used to strip
CO2 from a cold, high pressure natural gas stream; the refrigerated methanol
operating
temperature may be provided and controlled from a cryogenic gaseous stream
from an LNG
separator; LNG may be processed and produced without an external source of
refrigeration
energy; CCNG may be produced by recovering its own cold thermal energy; and
the C2+
fractions in the gas feed stream may be recovered and fractionated.
[0014] According to another aspect, there is provided a method to recover and
process
hydrocarbons from a gas flare system to produce natural gas liquids (NGLs),
cold compressed
natural gas (CCNG), compressed natural gas (CNG) and liquid natural gas (LNG),
the
method comprising the steps of: capturing associated gas produced from a
wellhead, the
associated gas comprising at least methane and natural gas liquids (NGLs) in
vapor form;
compressing the associated gas to produce a pressurized natural gas stream;
passing the
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pressurized natural gas stream through a dewatering unit to remove at least a
portion of the
water; cooling the pressurized natural gas stream to produce a cooled rich
natural gas stream
in which at least a portion of the NGLs are condensed; separating the cooled
rich natural gas
stream into a lean natural gas stream and an NGL stream; processing the lean
natural gas
.. stream to produce a fuel gas stream, a compressed natural gas (CNG) stream,
a cold
compressed natural gas (CCNG) stream, and a liquid natural gas (LNG) stream,
wherein: the
fuel gas stream is produced by conditioning a portion of the lean natural gas
stream to a
pressure and temperature suitable for use by a power plant; the CNG stream is
produced by
compressing a portion of the lean natural gas stream to a pressure greater
than the fuel gas
stream; and the LNG stream and the CCNG stream are produced by: passing a
portion of the
lean natural gas stream through a carbon dioxide stripping unit to produce a
stripped gas
stream; expanding the stripped gas stream to achieve cryogenic temperatures
sufficient to
condense a portion of the stripped gas stream, and passing the cooled,
condensed stripped gas
stream to obtain the LNG stream and a cold natural gas stream; and compressing
the cold
natural gas stream to produce the CCNG stream.
[0015] According to other aspects, the method may comprise one or more of the
following
aspects, alone or in combination: the fuel gas stream and the compressed
natural gas stream
may each be generated from an overhead stream of a fractionation tower; the
fractionation
tower may comprise a reboiler stream heated by a heat exchanger; the
fractionation tower
.. may be fed by one or more reflux streams diverted from the LNG generation
process; at least
a portion of the NGLs may be recovered from a bottoms stream of the
fractionation tower; the
dewatering unit may comprise an inline mixer for mixing the pressurized
natural gas stream
with methanol as a dewatering agent; the methanol may pass through a methanol
regenerator
column; the methanol regenerator column may comprise a reboiler stream heated
in a heat
exchanger by the pressurized natural gas stream; the dewatering unit may
comprise an inline
mixer for mixing methanol with the pressurized natural gas stream, and a
separator
downstream of the inline mixer for removing a methanol/water mixture from the
pressurized
natural gas stream; expanding the stripped gas stream to achieve cryogenic
temperatures may
comprise using a gas expander to generate power; the carbon dioxide stripping
unit may mix
refrigerated methanol with the portion of the lean natural gas stream in a
countercurrent
vessel; the LNG stream may be produced exclusively by cold temperatures
obtained by
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expanding gas streams in the production of at least one of the CNG, CCNG, and
LNG
streams; the CCNG stream may be produced by recovering its own cold thermal
energy in a
heat exchanger.
BRIEF DESCRIPHON OF THE PROCESS DRAWING
[0016] These and other features will become more apparent from the following
description
in which reference is made to the appended drawing, the drawing is for the
purpose of
illustration only and is not intended to in any way limit the scope of the
invention to the
particular embodiment or embodiments shown, wherein:
FIG. 1A and 1B is a schematic diagram of a process used to recover and process
hydrocarbon gases co-produced at oil production facilities equipped with
compressors, heat exchangers, an in-line mixer, separators, pumps, a
fractionator, a
stripper and a regenerator.
FIG. 2A and 2B is a schematic diagram of an alternative to the process
depicted in
FIG. IA and 1B
FIG. 3 is a schematic diagram of a well site.
DEI __ AILED DESCRIPTION OF THE PREFERRED EMBODIMENT
[0017] The method will now be described with reference to FIG. 1A, 1B, and 3.
[0018] The method was developed with a view for recovery and processing of
hydrocarbon
gaseous fractions co-produced at oil production facilities. The description of
application of
the method should, therefore, be considered as an example and not limited to
oil production
facilities but also to where gaseous hydrocarbon streams are available.
Referring to FIG. 3, as
an example, there is shown a wellhead 300 that produces primarily liquid
hydrocarbons as
well as associated gas. The production fluids exiting the wellhead may include
liquid
hydrocarbons, water, sand, gas, etc., and the associated gas is separated from
the production
fluids using separation equipment 305. The associated gas is transferred to
the process
8
equipment 302 described below through line 301. Process equipment 302 is used
to produce
liquid natural gas (LNG) in stream 64, cold compressed natural gas (CCNG) in
stream 83,
natural gas liquids (NGLs) in stream 30, compressed natural gas (CNG) in
stream 42, and a
fuel gas stream 104 that is used as fuel for a power plant 303. Power plant
303 provides the
necessary power to equipment 302. The transfer of power is represented by line
304, and
may include elechical, mechanical, hydraulic, etc.
[0019] As will be understood from the description below, process equipment 302
may be
modified to adjust the relative amounts, as well as the pressure and
temperature conditions, of
each product listed above. When gas pipeline infrastructure is not available,
it is often not
economical to capture and transport associated gas to a sales facility. By
varying the
proportion and conditions of the products, the likelihood of the products
being able to be
transported economically is greatly increased. For example, if natural gas is
to be transported
by tank, the volume of the tank is fixed, however the mass of the natural gas,
which
determines the actual value, will vary depending on the density of the fluid.
By increasing
.. the pressure and decreasing the temperature, the density can be increased.
The additional
costs associated with transporting the gas greater distances can be offset by
increasing the
mass being transported by the tank.
[0020] Referring to FIG. lA and 1B, a hydrocarbon feed gas stream 1 is
compressed by
compressor 2 to a pressure greater than 500 psig. The compressed stream 3
cooled to a
temperature controlled fin-fan air heat exchanger 4. This temperature is
controlled to meet
the reboiler temperatures of heat exchangers 6 and 10. The
temperature controlled
hydrocarbon feed gas stream 5 flows through heat exchanger 6 where it gives up
some of its
heat to the methanol reboiler stream 106, the cooler hydrocarbon feed gas
stream 7 flows
through in-line mixer 8 where methanol stream 108 is added and mixed as
required to absorb
the water fraction in hydrocarbon gas stream 7. The mixed stream 9 is further
cooled in heat
exchanger 10 before discharging into separator 11, where condensates, mainly
water and
methanol are separated and removed through line 13. The condensed liquid
fraction stream
13 enters a membrane unit 112 where the water is separated from the methanol
and removed
through line 114. The dewatered hydrocarbon feed gas stream 12 is further
cooled in heat
exchanger 14 and stream 15 is further cooled in heat exchanger 16 before
entering liquids
Date Regue/Date Received 2022-12-02
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hydrocarbon separator 18. The hydrocarbon liquid fraction exits separator 18
through stream
19, and the pressure of stream 19 is reduced at JT valve 20 to meet the
operating pressure of
fractionator 27 operating pressure. As a result of this pressure reduction,
stream 21 is colder
and gives up its cold energy to stream 15 in heat exchanger 16. The now warmer
stream 22 is
routed to fractionator 27.
[0021] The hydrocarbon gaseous fraction exits separator 18 through stream 23
and is split
into two streams, fractionator stream 24 and LNG feed stream 43. The
fractionator stream 24
of gaseous hydrocarbons enters an expander 25 where the pressure is reduced to
the operating
pressure of fractionator 27. The cooled stream 26 exits expander 25 and enters
fractionator
27. The LNG feed stream 43 is further cooled in heat exchanger 44, and the
cooled stream 45
enters separator 46 to remove any condensed hydrocarbons. The condensed
fraction exits
separator 46 through line 47 and the pressure is reduced at a JT valve 48 to
the operating
pressure of fractionator 27 to produce a cooled stream 49 that enters the
fractionator 27 as a
secondary retlux stream.
[0022] The gaseous LNG feed stream exits separator 46 through line 50 into
carbon dioxide
stripper 51. The carbon dioxide stripped gaseous LNG feed stream 52 enters
line 53 and is
further cooled in heat exchanger 54 before entering separator 56 through line
55. The
condensed and separated liquid fraction is routed through line 57 and its
pressure is reduced at
JT valve 58 to the operating pressure of fractionator 27. The colder, de-
pressured stream 59
enters fractionator 27 as a primary reflux stream. The gaseous LNG feed stream
exits
separator 60 and is expanded through gas expander 61 to a separator 63
operating pressure,
which is preferably greater than 1 psig. The produced LNG exits separator 63
through line 64
and pumped to storage through pump 65. The gaseous cryogenic fraction exits
LNG
separator 63 through line 66 and enters heat exchanger 54 through valve 69. A
bypass stream
68 around heat exchanger 54 is controlled by valve 67, which allows the
temperature of the
methanol stream 94 to be controlled by heat exchanger 71. The cryogenic
gaseous stream 70
is further heated in heat exchanger 71 to a warmer gaseous stream 72 which is
further warmed
in heat exchanger 73. The warmed gas stream 74 is compressed in booster
compressor 75,
which is coupled to expander 61 by shaft B. The compressed gas stream 76 is
air cooled in
air cooled fan 77 and further compressed in compressor 79. The compressed gas
stream 80 is
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cooled by air in fin fan cooler 81 and line 82 is further cooled in heat
exchanger 73. The cold
compressed gas in line 82 can be sent to storage or distribution through valve
84 and/or
recycled through valve 85 to line 53.
[0023] The CO2 stripper is a major feature of the proposed process since it
uses
5 refrigerated methanol to remove CO2 from the LNG feed gas stream to meet
LNG product
CO2 spec of less than 50 ppmv. Regenerated methanol stream 91 is pressurized
by pump 92
to the operating pressure of CO2 stripper column 51. The pressurized methanol
stream 93 is
first cooled in heat exchanger 87, and the cooled stream 94 is further cooled
in heat exchanger
71 before entering CO2 stripper column 51. The temperature of the refrigerated
methanol in
10 line 95 as it enters stripping column 51 is controlled by controlling
the temperature of stream
70 into heat exchanger 71. In stripping column 51, the temperature controlled
refrigerated
methanol flows downwards in a counter-current flow relative to the LNG feed
gas stream that
enters stripper column 51 through line 50, such that the methanol strips and
absorbs the CO2
from the gaseous stream as it flows upwards through stripping column 51. The
CO2 rich
methanol stream 86 exits stripping column 51 via line 86 and enters heat
exchanger 87 where
it cools methanol stream 93. The heated, rich CO2 methanol stream 88 is
depressurized
through valve 89 and enters methanol regenerator column 90, where the CO2 is
separated
from the methanol.
[0024] A slipstream of the lean methanol stream 91 is routed to methanol pump
105, and
the pressurized methanol stream 106 is split into a reboiler stream and an
absorbent stream.
The reboiler stream flow is controlled through valve 109 and gains heat in
heat exchanger 6.
The temperature requirement for heat transfer in heat exchanger 6 is
controlled by controlling
the temperature of feed gas stream 5. The heated methanol stream 110 is mixed
with
recovered methanol stream 113 and is routed through line 111 to the methanol
regenerator to
control the column bottoms operations temperature in regenerator column 90.
[0025] The absorbent methanol stream is flow-controlled through valve 107 and
routed
through line 108 to feed gas mixer 8. The rate of methanol flow is controlled
to meet the
methanol required to absorb the water in the feed gas stream. The recovered
mixture of
methanol and water exits separator 11 through line 13 and is routed to a
solvent membrane
unit 112 to separate the water from the methanol and to recover the methanol.
The recovered
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methanol is routed through line 113 into reboiler stream 110. The separated
water fraction is
removed from solvent membrane unit 112 for disposal through line 114.
[0026] The overhead stream 96o1 methanol regeneration column 90 is cooled by
an air heat
exchanger 97, and the cooled stream 98 enters separator 99 where the condensed
liquid
fraction 100 is pressurized by pump 101 and routed through line 102 as a
reflux stream to
regenerator column 90. The gaseous fraction 103 exits separator 99 and flows
into fuel gas
line 104 where it is mixed with hydrocarbon gas supplied from valve 34 to meet
plant fuel gas
requirements.
[0027] The fractionated lean gas stream 31 exits fractionator 27 and is first
heated in heat
exchanger 44, and the heated lean gas stream 32 is further heated in heat
exchanger 14. The
heated lean gas stream 33 is split into two streams, a fuel gas stream 104 and
a compressed
natural gas stream 35. The fuel gas stream 104 is controlled by valve 34 to
meet the fuel
needs of the plant. The pressure of natural gas stream 35 is first boosted by
a compressor
coupled by shaft A to expander 25. The compressed lean gas stream 36 is cooled
by air heat
exchanger 37 and the cooled lean gas stream is further compressed by
compressor 39 and
discharged through line 40 into air cooled heat exchanger 41 and routed
through line 42 to
distribution and/or storage as compressed lean natural gas.
[0028] The objective of the described process is to recover and process
hydrocarbon gas
streams at oil production fields that are typically combusted in flares. The
many features of
the process are the processing and production of four or more distinct
products from a
resource typically wasted by combustion in a flare, the products of combustion
and its thermal
heat are released into the atmosphere.
[0029] The electrical and thermal energy needs required for the process are
provided by an
auxiliary power plant (not shown) fuelled from a recovered fuel gas stream,
such as fuel
stream 104 shown in FIG. 1A and 1B. The proposed process unlike other standard
processes
provides in a single plant the ability to produce LNG, CCNG, CNG, NGL's and
fuel gas for
an auxiliary power plant.
[0030] The definitions of LNG, CCNG, and CNG, which are primarily made from
methane
with a minimal amount of heavier hydrocarbons, are well known in the art. Each
of these
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products is conditioned to increase the density to different decrees in order
to allow a greater
mass to be transported in the same volume. Briefly, LNG is produced at
cryogenic
temperatures, or temperatures around 160 C, although the conditions necessary
to produce
LNG will depend on various factors, including the pressure, composition, etc.
CNG is
generally around ambient temperatures, and at pressures of up to 3,600 psi.
The pressure
range may vary depending on the intended use, or required level of density. In
some
circumstances, the pressure will vary based on the requirements of the sysem
for example the
pressure may be as low as 800 ¨ 1200 psi for a gas transmission pipeline,
around 80 psi for a
distribution pipeline, around 25 psi for a residential system, etc. CCNG is
achieved by
pressurising and cooling natural gas to temperatures that are less than 0 C,
and may be as low
as -100 C or lower, depending on the desired product characteristics and
limits based on
available equipment. CCNG may be pressurized and cooled to its critical point
(i.e. about -
83 C and 676 psi for methane).
[0031] One main feature of the method is the flexibility of the process to
meet various
process operating conditions to meet product demand. The proportion of
products and the
density of each product can be varied based on economic considerations, such
as the demand
for the product, the price of the product, the cost of transportation, the
distance to be travelled,
etc. The method also provides for a significant savings in GHG emissions when
compared to
the current practice of flaring. The proposed method can be applied at any
plant where
hydrocarbons gases require processing.
[0032] HG. 2A and 2B show a variation, in which gas expander 61 shown in FIG.
1A and
1B has been replaced by a JT valve 200, and expander 75 by a stand-alone
compressor 201.
The process configuration of FIG. 2A and 2B may be used when less LNG is
required to be
produced, while increasing CCNG production.
[0033] In this patent document, the word "comprising" is used in its non-
limiting sense to
mean that items following the word are included, but items not specifically
mentioned are not
excluded. A reference to an element by the indefinite article "a" does not
exclude the
possibility that more than one of the element is present, unless the context
clearly requires that
there be one and only one of the elements.
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[00341 The scope of the claims should not be limited by the preferred
embodiments set
forth in the examples, but should be given a broad purposive interpretation
consistent with the
description as a whole.
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