Note: Descriptions are shown in the official language in which they were submitted.
PRE-COOLING OF NATURAL GAS BY HIGH PRESSURE COMPRESSION AND
EXPANSION
[0001] (This paragraph is intentionally left blank.)
[0002] (This paragraph is intentionally left blank.)
to
FIELD OF THE INVENTION
[0003] The invention relates to the liquefaction of natural gas to
form liquefied natural gas
(LNG), and more specifically, to the production of LNG in remote or sensitive
areas where the
construction and/or maintenance of capital facilities, and/or the
environmental impact of a
conventional LNG plant may be detrimental.
BACKGROUND
[0004] LNG production is a rapidly growing means to supply natural gas
from locations
with an abundant supply of natural gas to distant locations with a strong
demand for natural
gas. The conventional LNG production cycle includes: a) initial treatments of
the natural gas
resource to remove contaminants such as water, sulfur compounds and carbon
dioxide; b) the
separation of some heavier hydrocarbon gases, such as propane, butane,
pentane, etc. by a
variety of possible methods including self-refrigeration, extern al
refrigeration, lean oil, etc.; c)
refrigeration of the natural gas substantially by external refrigeration to
form liquefied natural
gas at near atmospheric pressure and about -160 C; d) transport of the LNG
product in ships
or tankers designed for this purpose to a market location; e) re-
pressurization and regasification
of the LNG at a regasification plant to a pressurized natural gas that may
distributed to natural
gas consumers. Step (c) of the conventional LNG cycle usually requires the use
of large
refrigeration compressors often powered by large gas turbine drivers that emit
substantial
carbon and other emissions. Large capital investment in the billions of US
dollars and
extensive infrastructure are required as part of the liquefaction plant. Step
(e) of the
conventional LNG cycle generally includes re-pressurizing the LNG to the
required pressure
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using cryogenic pumps and then re-gasifying the LNG to pressurized natural gas
by exchanging
heat through an intermediate fluid but ultimately with seawater or by
combusting a portion of
the natural gas to heat and vaporize the LNG.
[0005] Although LNG production in general is well known, technology
improvements may
still provide LNG producers with significant opportunities to increase
efficiencies and expand
LNG production into additional geographic areas. For example, floating LNG
(FLNG) is a
relatively new technology option for producing LNG. The technology involves
the
construction of the gas treating and liquefaction facility on a floating
structure such as barge or
a ship. FLNG is a technology solution for monetizing offshore stranded gas
where it is not
to economically viable to construct a gas pipeline to shore. FLNG is also
increasingly being
considered for onshore and near-shore gas fields located in remote,
environmentally sensitive
and/or politically challenging regions. The technology has certain advantages
over
conventional onshore LNG in that it has a reduced environmental footprint at
the production
site. The technology may also deliver projects faster and at a lower cost
since the bulk of the
LNG facility is constructed in shipyards with lower labor rates and reduced
execution risk.
[0006] Although FLNG has several advantageous over conventional onshore
LNG,
significant technical challenges remain in the application of the technology.
For example, the
FLNG structure must provide the same level of gas treating and liquefaction in
an area or space
that is often less than one quarter of what would be available for an onshore
LNG plant. For
this reason, there is a need to develop technology that reduces the footprint
of the liquefaction
facility while maintaining its capacity to thereby reduce overall project
cost. Several
liquefaction technologies have been proposed for use on an FLNG project. The
leading
technologies include a single mixed refrigerant (SMR) process, a dual mixed
refrigerant
(DMR) process, and expander-based (or expansion) process.
[0007] In contrast to the DMR process, the SMR process has the advantage of
allowing all
the equipment and bulks associated with the complete liquefaction process to
fit within a single
FLNG module. The SMR liquefaction module is placed on the topside of the FLNG
structure
as a complete SMR train. This "LNG-in-a-Box" concept is favorable for FLNG
project
execution because it allows for the testing and commissioning of the SMR train
at a different
location from where the FLNG structure is constructed. It may also allow for
the reduction in
labor cost since it reduces labor hours at ship yards where labor rates tend
to be higher than
labor rates at conventional fabrication yards. The SMR process has the added
advantage of
being a relatively efficient, simple, and compact refrigerant process when
compared to other
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mixed refrigerant processes. Furthermore, the SMR liquefaction process is
typically 15% to
20% more efficient than expander-based liquefaction processes.
[0008] The choice of the SMR process for LNG liquefaction in an FLNG
project has its
advantages; however, there are several disadvantages to the SMR process. For
example, the
required use and storage of combustible refrigerants such as propane
significantly increases
loss prevention issues on the FLNG. The SMR process is also limited in
capacity, which
increases the number of trains needed to reach the desired LNG production. For
these reasons
and others, a significant amount of topside space and weight is required for
the SMR trains.
Since topside space and weight are significant drivers for FLNG project cost,
there remains a
to need to improve the SMR liquefaction process to further reduce topside
space, weight and
complexity to thereby improve project economics.
[0009] The expander-based process has several advantages that make it well
suited for
FLNG projects. The most significant advantage is that the technology offers
liquefaction
without the need for external hydrocarbon refrigerants. Removing liquid
hydrocarbon
refrigerant inventory, such as propane storage, significantly reduces safety
concerns on FLNG
projects. An additional advantage of the expander-based process compared to a
mixed
refrigerant process is that the expander-based process is less sensitive to
offshore motions since
the main refrigerant mostly remains in the gas phase. However, application of
the expander-
based process to an FLNG project with LNG production of greater than 2 million
tons per year
(MTA) has proven to be less appealing than the use of the mixed refrigerant
process. The
capacity of an expander-based process train is typically less than 1.5 MTA. In
contrast, a mixed
refrigerant process train, such as that of known dual mixed refrigerant
processes, can have a
train capacity of greater than 5 MTA. The size of the expander-based process
train is limited
since its refrigerant mostly remains in the vapor state throughout the entire
process and the
refrigerant absorbs energy through its sensible heat. For these reasons, the
refrigerant
volumetric flow rate is large throughout the process, and the size of the heat
exchangers and
piping are proportionately greater than those of a mixed refrigerant process.
Furthermore, the
limitations in compander horsepower size results in parallel rotating
machinery as the capacity
of the expander-based process train increases. The production rate of an FLNG
project using
an expander-based process can be made to be greater than 2 MTA if multiple
expander-based
trains are allowed. For example, for a 6 MTA FLNG project, six or more
parallel expander-
based process trains may be sufficient to achieve the required production.
However, the
equipment count, complexity and cost all increase with multiple expander
trains. Additionally,
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the assumed process simplicity of the expander-based process compared to a
mixed refrigerant
process begins to be questioned if multiple trains are required for the
expander-based process
while the mixed refrigerant process can obtain the required production rate
with one or two
trains. For these reasons, there is a need to develop a high LNG production
capacity FLNG
liquefaction process with the advantages of an expander-based process. There
is a further need
to develop an FLNG technology solution that is better able to handle the
challenges that vessel
motion has on gas processing.
[0010] United States Patent No. 6,412,302 describes a feed gas expander-
based process
where two independent closed refrigeration loops are used to cool the feed gas
to form LNG.
to In an embodiment, the first closed refrigeration loop uses the feed gas
or components of the
feed gas as the refrigerant. Nitrogen gas is used as the refrigerant for the
second closed
refrigeration loop. This technology requires smaller equipment and topside
space than a dual
loop nitrogen expander-based process. For example, the volumetric flow rate of
the refrigerant
into the low pressure compressor can be 20 to 50% smaller for this technology
compared to a
dual loop nitrogen expander-based process. The technology, however, is still
limited to a
capacity of less than 1.5 MTA.
[0011] United States Patent No. 8,616,012 describes a feed gas expander-
based process
where feed gas is used as the refrigerant in a closed refrigeration loop.
Within this closed
refrigeration loop, the refrigerant is compressed to a pressure greater than
or equal to 1,500
psia (10,340 kPa), or more preferably greater than 2,500 psia (17,240 kPa).
The refrigerant is
then cooled and expanded to achieve cryogenic temperatures. This cooled
refrigerant is used
in a heat exchanger to cool the feed gas from warm temperatures to cryogenic
temperatures. A
subcooling refrigeration loop is then employed to further cool the feed gas to
form LNG. In
one embodiment, the subcooling refrigeration loop is a closed loop with flash
gas used as the
refrigerant. This feed gas expander-based process has the advantage of not
being limited to a
train capacity range of less than 1 MTA. A train size of approximately 6 MTA
has been
considered. However, the technology has the disadvantage of a high equipment
count and
increased complexity due to its requirement for two independent refrigeration
loops and the
compression of the feed gas. Furthermore, the high pressure operation also
means that the
equipment and piping will be much heavier than that of other expander-based
processes.
[0012] GB 2,486,036 describes a feed gas expander-based process that is an
open loop
refrigeration cycle including a precooling expander loop and a liquefying
expander loop, where
the gas phase after expansion is used to liquefy the natural gas. According to
this document,
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including a liquefying expander in the process significantly reduces the
recycle gas rate and
the overall required refrigeration power. This technology has the advantage of
being simpler
than other technologies since only one type of refrigerant is used with a
single compression
string. However, the technology is still limited to capacity of less than 1.5
MTA and it requires
the use of liquefying expander, which is not standard equipment for LNG
production. The
technology has also been shown to be less efficient than other technologies
for the liquefaction
of lean natural gas.
[0013] United States Patent No. 7,386,996 describes an expander-based
process with a pre-
cooling refrigeration process preceding the main expander-based cooling
circuit. The pre-
cooling refrigeration process includes a carbon dioxide refrigeration circuit
in a cascade
arrangement. The carbon dioxide refrigeration circuit may cool the feed gas
and the refrigerant
gases of the main expander-based cooling circuit at three pressure levels: a
high pressure level
to provide the warm-end cooling; a medium pressure level to provide the
intermediate
temperature cooling; and a low pressure level to provide cold-end cooling for
the carbon
dioxide refrigeration circuit. This technology is more efficient and has a
higher production
capacity than expander-based processes lacking a pre-cooling step. The
technology has the
additional advantage for FLNG applications since the pre-cooling refrigeration
cycle uses
carbon dioxide as the refrigerant instead of hydrocarbon refrigerants. The
carbon dioxide
refrigeration circuit, however, comes at the cost of added complexity to the
liquefaction process
since an additional refrigerant and a substantial amount of extra equipment is
introduced. In
an FLNG application, the carbon dioxide refrigeration circuit may be in its
own module and
sized to provide the pre-cooling for multiple expander-based processes. This
arrangement has
the disadvantage of requiring a significant amount of pipe connections between
the pre-cooling
module and the main expander-based process modules. The "LNG-in-a-Box-
advantages
discussed above are no longer realized.
[0014] Thus, there remains a need to develop a pre-cooling process that
does not require
additional refrigerant and does not introduce a significant amount of extra
equipment to the
LNG liquefaction process. There is an additional need to develop a pre-cooling
process that
can be placed in the same module as the liquefaction module. Such a pre-
cooling process
combined with an SMR process or an expander-based process would be
particularly suitable
for FLNG applications where topside space and weight significantly impacts the
project
economics. There remains a specific need to develop an LNG production process
with the
advantages of an expander-based process and which, in addition, has a high LNG
production
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capacity without significantly increasing facility footprint. There is a
further need to develop
an LNG technology solution that is better able to handle the challenges that
vessel motion has
on gas processing. Such a high capacity expander-based liquefaction process
would be
particularly suitable for FLNG applications where the inherent safety and
simplicity of
expander-based liquefaction process are greatly valued.
SUMMARY OF THE INVENTION
[0015] The invention provides a method of producing liquefied natural gas
(LNG). A
natural gas stream is provided from a supply of natural gas. The natural gas
stream may be
compressed in at least two serially arranged compressors to a pressure of at
least 2,000 psia to
to .. form a compressed natural gas stream. The compressed natural gas stream
may be cooled by
indirect heat exchange with an ambient temperature air or water to form a
cooled compressed
natural gas stream. The cooled compressed natural gas stream may be
additionally cooled to a
temperature below the ambient temperature to form an additionally cooled
compressed natural
gas stream. The additionally cooled compressed natural gas stream may be
expanded in at least
one work producing natural gas expander to a pressure that is less than 3,000
psia and no greater
than the pressure to which the at least two serially arranged compressors
compress the natural
gas stream, to thereby form a chilled natural gas stream. The chilled natural
gas stream may
then be liquefied by indirect heat exchange with a refrigerant to form
liquefied natural gas and
a warm refrigerant. The cooled compressed natural gas stream is additionally
cooled using the
warm refrigerant.
[0016] The invention also provides an apparatus for the liquefaction of
natural gas. At
least two serially arranged compressors compress a natural gas stream to a
pressure greater
than 2,000 psia, thereby forming a compressed natural gas stream. A cooling
element cools
the compressed natural gas stream to form a cooled compressed natural gas
stream. A heat
exchanger further cools the cooled compressed natural gas stream to a
temperature below an
ambient temperature to thereby produce an additionally cooled compressed
natural gas stream.
At least one work-producing expander expands the additionally cooled
compressed natural gas
stream to a pressure less than 3,000 psia and no greater than the pressure to
which the at least
two serially arranged compressors compress the natural gas stream, to thereby
form a chilled
natural gas stream. A liquefaction train liquefies the chilled natural gas
stream. A warm
refrigerant used by the liquefaction train is directed to the heat exchanger
to further cool the
cooled compressed natural gas stream.
[0017] The invention further provides a floating LNG structure. At least
two serially
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arranged compressors compress a natural gas stream to a pressure greater than
2,000 psia,
thereby forming a compressed natural gas stream. A cooling element cools the
compressed
natural gas stream to form a cooled compressed natural gas stream. A heat
exchanger further
cools the cooled compressed natural gas stream to a temperature below an
ambient temperature
.. to thereby produce an additionally cooled compressed natural gas stream. At
least one work-
producing expander expands the additionally cooled compressed natural gas
stream to a
pressure less than 3,000 psia and no greater than the pressure to which the at
least two serially
arranged compressors compress the natural gas stream, to thereby form a
chilled natural gas
stream. A liquefaction train liquefies the chilled natural gas stream. A warm
refrigerant used
by the liquefaction train is directed to the heat exchanger to further cool
the cooled compressed
natural gas stream.
BRIEF DESCRIPTION OF THE FIGURES
[0018] Figure 1 is a schematic diagram of a high pressure compression and
expansion
(HPCE) module according to disclosed aspects.
[0019] Figure 2 is a graph shown a heating and cooling curve for an
expander-based
refrigeration process.
[0020] Figure 3 is a schematic diagram showing an arrangement of single-
mixed
refrigerant (SMR) liquefaction modules according to known principles.
[0021] Figure 4 is a schematic diagram showing an arrangement of SMR
liquefaction
modules according to disclosed aspects.
[0022] Figure 5 is a schematic diagram of an HPCE module according to
disclosed aspects.
[0023] Figure 6 is a schematic diagram of an HPCE module and a feed gas
expander-based
liquefaction module according to disclosed aspects.
[0024] Figure 7 is a flowchart of a method of liquefying natural gas to
form LNG
according to disclosed aspects.
[0025] Figure 8 is a schematic diagram of a high pressure compression and
expansion
(HPCE) module according to disclosed aspects.
[0026] Figure 9 is a schematic diagram of an HPCE module and a feed gas
expander-based
liquefaction module according to disclosed aspects.
[0027] Figure 10 is a schematic diagram of an HPCE module and a feed gas
expander-
based liquefaction module according to disclosed aspects.
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[0028] Figure 11 is a schematic diagram of an HPCE module and a feed gas
expander-
based liquefaction module according to disclosed aspects.
[0029] Figure 12 is a flowchart of a method of liquefying natural gas to
form LNG
according to disclosed aspects.
DETAILED DESCRIPTION
[0030] Various specific aspects, embodiments, and versions will now be
described,
including definitions adopted herein. Those skilled in the art will appreciate
that such aspects,
embodiments, and versions are exemplary only, and that the invention can be
practiced in other
ways. Any reference to the "invention" may refer to one or more, but not
necessarily all, of
to the embodiments defined by the claims. The use of headings is for
purposes of convenience
only and does not limit the scope of the present invention. For purposes of
clarity and brevity,
similar reference numbers in the several Figures represent similar items,
steps, or structures
and may not be described in detail in every Figure.
[0031] All numerical values within the detailed description and the claims
herein are
modified by -about" or "approximately" the indicated value, and take into
account
experimental error and variations that would be expected by a person having
ordinary skill in
the art.
[0032] As used herein, the term "compressor" means a machine that
increases the pressure
of a gas by the application of work. A "compressor" or "refrigerant
compressor" includes any
unit, device, or apparatus able to increase the pressure of a gas stream. This
includes
compressors having a single compression process or step, or compressors having
multi-stage
compressions or steps, or more particularly multi-stage compressors within a
single casing or
shell. Evaporated streams to be compressed can be provided to a compressor at
different
pressures. Some stages or steps of a cooling process may involve two or more
compressors in
parallel, series, or both. The present invention is not limited by the type or
arrangement or
layout of the compressor or compressors, particularly in any refrigerant
circuit.
[0033] As used herein, "cooling" broadly refers to lowering and/or
dropping a temperature
and/or internal energy of a substance by any suitable, desired, or required
amount. Cooling
may include a temperature drop of at least about 1 C, at least about 5 C, at
least about 10 C,
at least about 15 C, at least about 25 C, at least about 35 C, or least
about 50 C, or at least
about 75 C, or at least about 85 C, or at least about 95 C, or at least
about 100 C. The
cooling may use any suitable heat sink, such as steam generation, hot water
heating, cooling
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water, air, refrigerant, other process streams (integration), and combinations
thereof One or
more sources of cooling may be combined and/or cascaded to reach a desired
outlet
temperature. The cooling step may use a cooling unit with any suitable device
and/or
equipment. According to some embodiments, cooling may include indirect heat
exchange,
such as with one or more heat exchangers. In the alternative, the cooling may
use evaporative
(heat of vaporization) cooling and/or direct heat exchange, such as a liquid
sprayed directly
into a process stream.
[0034] As used herein, the term "expansion device" refers to one or more
devices suitable
for reducing the pressure of a fluid in a line (for example, a liquid stream,
a vapor stream, or a
multiphase stream containing both liquid and vapor). Unless a particular type
of expansion
device is specifically stated, the expansion device may be (1) at least
partially by isenthalpic
means, or (2) may be at least partially by isentropic means, or (3) may be a
combination of both
isentropic means and isenthalpic means. Suitable devices for isenthalpic
expansion of natural
gas are known in the art and generally include, but are not limited to,
manually or automatically,
actuated throttling devices such as, for example, valves, control valves,
Joule-Thomson (J-T)
valves, or venturi devices. Suitable devices for isentropic expansion of
natural gas are known
in the art and generally include equipment such as expanders or turbo
expanders that extract or
derive work from such expansion. Suitable devices for isentropic expansion of
liquid streams
are known in the art and generally include equipment such as expanders,
hydraulic expanders,
zo liquid turbines, or turbo expanders that extract or derive work from
such expansion. An
example of a combination of both isentropic means and isenthalpic means may be
a Joule-
Thomson valve and a turbo expander in parallel, which provides the capability
of using either
alone or using both the J-T valve and the turbo expander simultaneously.
Isenthalpic or
isentropic expansion can be conducted in the all-liquid phase, all-vapor
phase, or mixed phases,
and can be conducted to facilitate a phase change from a vapor stream or
liquid stream to a
multiphase stream (a stream having both vapor and liquid phases) or to a
single-phase stream
different from its initial phase. In the description of the drawings herein,
the reference to more
than one expansion device in any drawing does not necessarily mean that each
expansion
device is the same type or size.
[0035] The term "gas" is used interchangeably with "vapor," and is defined
as a substance
or mixture of substances in the gaseous state as distinguished from the liquid
or solid state.
Likewise, the term "liquid" means a substance or mixture of substances in the
liquid state as
distinguished from the gas or solid state.
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[0036] A "heat exchanger" broadly means any device capable of transferring
heat energy
or cold energy from one medium to another medium, such as between at least two
distinct
fluids. Heat exchangers include "direct heat exchangers" and "indirect heat
exchangers." Thus,
a heat exchanger may be of any suitable design, such as a co-current or
counter-current heat
exchanger, an indirect heat exchanger (e.g. a spiral wound heat exchanger or a
plate-fin heat
exchanger such as a brazed aluminum plate fin type), direct contact heat
exchanger, shell-and-
tube heat exchanger, spiral, hairpin, core, core-and-kettle, printed-circuit,
double-pipe or any
other type of known heat exchanger. "Heat exchanger" may also refer to any
column, tower,
unit or other arrangement adapted to allow the passage of one or more streams
therethrough,
1() and to affect direct or indirect heat exchange between one or more
lines of refrigerant, and one
or more feed streams.
[0037] As used herein, the term "indirect heat exchange" means the
bringing of two fluids
into heat exchange relation without any physical contact or intermixing of the
fluids with each
other. Core-in-kettle heat exchangers and brazed aluminum plate-fin heat
exchangers are
examples of equipment that facilitate indirect heat exchange.
[0038] As used herein, the term "natural gas" refers to a multi-component
gas obtained
from a crude oil well (associated gas) or from a subterranean gas-bearing
formation (non-
associated gas). The composition and pressure of natural gas can vary
significantly. A typical
natural gas stream contains methane (0) as a significant component. The
natural gas stream
may also contain ethane (C2), higher molecular weight hydrocarbons, and one or
more acid
gases. The natural gas may also contain minor amounts of contaminants such as
water,
nitrogen, iron sulfide, wax, and crude oil.
[0039] Certain embodiments and features have been described using a set of
numerical
upper limits and a set of numerical lower limits. It should be appreciated
that ranges from any
lower limit to any upper limit are contemplated unless otherwise indicated.
All numerical
values are "about" or "approximately" the indicated value, and take into
account experimental
error and variations that would be expected by a person having ordinary skill
in the art.
[0040] All patents, test procedures, and other documents cited in this
application are fully
incorporated by reference to the extent such disclosure is not inconsistent
with this application
and for all jurisdictions in which such incorporation is permitted.
[0041] Aspects disclosed herein describe a process for pre-cooling natural
gas to a
liquefaction process for the production of LNG by the addition of a high
pressure compression
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and high pressure expansion process to the feed gas. More specifically, the
invention describes
a process where a pretreated natural gas is compressed to pressure greater
than 2,000 psia
(13,790 kPa), or more preferably greater than 3,000 psia (20,680 kPa). The hot
compressed
gas is cooled by exchanging heat with the environment to form a compressed
pretreated gas.
The cooled compressed gas is additionally cooled to a temperature below the
ambient
temperature to form an additionally cooled compressed pretreated gas stream.
The additionally
cooled compressed pretreated gas stream is near-isentropically expanded to a
pressure less than
3,000 psia (20,680 kPa), or more preferably to a pressure less than 2,000 psia
(13,790 kPa) to
form a chilled pretreated gas, where the pressure of the chilled pretreated
gas is less than the
to pressure of the compressed pretreated gas. The chilled pretreated gas
may be directed to one
or more SMR liquefaction trains, or the chilled pretreated gas may be directed
to one or more
expander-based liquefaction trains where the gas is further cooled to form
LNG. Aspects
described herein may be related to and/or further described in one or more of
the following
patent applications: U.S. Patent Publication number 2017/0167788 titled
"Method and System
is for Separating Nitrogen from Liquefied Natural Gas Using Liquefied
Nitrogen;" U.S. Patent
Publication No. 2017/0167785 titled "Expander-Based LNG Production Processes
Enhanced
With Liquid Nitrogen;" U.S. Patent Publication No. 2017/0167787 titled "Method
of Natural
Gas Liquefaction on LNG Carriers Storing Liquid Nitrogen;" and U.S. Patent
Publication
2017/0167786, titled "Pre-cooling of Natural Gas by High Pressure Compression
and
20 Expansion;" all having a common assignee and filed on November 10,
2016.
[0042] Figure 1 is an illustration of an aspect of the pre-cooling
process. The pre-cooling
process is referred to herein as a high pressure compression and expansion
(HPCE) process
100. The HPCE process 100 may comprise a first compressor 102 which compresses
a
25 pretreated natural gas stream 104 to form an intermediate pressure gas
stream 106. The
intermediate pressure gas stream 106 may flow through a first heat exchanger
108 where the
intermediate pressure gas stream 106 is cooled by indirectly exchanging heat
with the
environment to form a cooled intermediate pressure gas stream 110. The first
heat exchanger
108 may be an air cooled heat exchanger or a water cooled heat exchanger. The
cooled
30 intermediate pressure gas stream 110 may then be compressed within a
second compressor 112
to form a high pressure gas stream 114. The pressure of the high pressure gas
stream 114 may
be greater than 2,000 psia (13,790 kPa), or more preferably greater than 3,000
psia (20,680
kPa). The high pressure gas stream 114 may flow through a second heat
exchanger 116 where
the high pressure gas stream 114 is cooled by indirectly exchanging heat with
the environment
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to form a cooled high pressure gas stream 118. The second heat exchanger 116
may be an air
cooled heat exchanger or a water cooled heat exchanger. The cooled high
pressure gas stream
118 may then be expanded within an expander 120 to form a chilled pretreated
gas stream 122.
The pressure of the chilled pretreated gas stream 122 may be less than 3,000
psia (20,680 kPa),
or more preferably less than 2,000 psia (13,790 kPa), and the pressure of the
chilled pretreated
gas stream 122 is less than the pressure of the cooled high pressure gas
stream 118. In a
preferred aspect, the second compressor 112 may be driven solely by the shaft
power produced
by the expander 120, as indicated by the dashed line 124.
[0043] In an aspect, the SMR liquefaction process may be enhanced by the
addition of the
to HPCE process upstream of the SMR liquefaction process. More
specifically, in this aspect,
pretreated natural gas may be compressed to a pressure greater than 2,000 psia
(13,790 kPa),
or more preferably greater than 3,000 psia (20,680 kPa). The hot compressed
gas is then cooled
by exchanging heat with the environment to form a compressed pretreated gas.
The
compressed pretreated gas is then near-isentropically expanded to pressure
less than 3,000 psia
(20,680 kPa), or more preferably to a pressure less than 2,000 psia (13,790
kPa) to form a
chilled pretreated gas, where the pressure of the chilled pretreated gas is
less than the pressure
of the compressed pretreated gas. The chilled pretreated gas is then directed
to multiple SMR
liquefaction trains where the chilled pretreated gas is further cooled to form
LNG.
[0044] The combination of the HPCE process with SMR trains has several
advantages over
the conventional SMR process where pretreated natural gas is sent directly to
the SMR
liquefaction trains. For example, the precooling of the natural gas using the
HPCE process
allows for an increase in LNG production rate within the SMR trains for a
given horsepower
within the SMR trains. As described with respect to Figures 3 and 4, SMR
trains that are each
powered by a gas turbine having an output of about 50 megawatts (MW) can be
reduced from
five trains producing LNG at 1.5 MTA each to four trains with an increased
capacity of 1.9
MTA each. For this given example, the HPCE module has effectively replaced one
of the SMR
modules. The replacement of one SMR module for an HPCE module is advantageous
since
the HPCE module is expected to be smaller, of less weight, and having
significantly lower cost
than the SMR module. Like the SMR module, the HPCE module may have an
equivalent size
gas turbine to provide compression power, and it will also have an equivalent
amount of air or
water coolers. Unlike the SMR module, however, the HPCE module does not have
an
expensive main cryogenic heat exchanger. The vessels and pipes associated with
the
refrigerant flow within an SMR module are eliminated in the HPCE module.
Furthermore,
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there are no expensive cryogenic pipes in the HPCE module and all the fluid
streams remain
in a single phase in the HPCE module.
[0045] Another advantage is that the required storage of refrigerant is
reduced since the
number of SMR trains has been reduced by one. Also, since a large fraction of
the warm
temperature cooling of the gas occurs in the HPCE module, the heavier
hydrocarbon
components of the mixed refrigerant can be reduced. For example, the propane
component of
the mixed refrigerant may be eliminated without any significant reduction in
efficiency of the
SMR process.
[0046] Another advantage is that for the SMR process which receives
chilled pretreated
gas from the HPCE process, the volumetric flow rate of the vaporized
refrigerant of the SMR
process can be more than 25% less than that of a conventional SMR process
receiving warm
pretreated gas. The lower volumetric flow of refrigerant may reduce the size
of the main
cryogenic heat exchanger and the size of the low pressure mixed refrigerant
compressor. The
lower volumetric flow rate of the refrigerant is due to its higher vaporizing
pressure compared
to that of a conventional SMR process.
[0047] Known propane-precooled mixed refrigeration processes and dual
mixed
refrigeration (DMR) processes may be viewed as versions of an SMR process
combined with
a pre-cooling refrigeration circuit, but there are significant differences
between such processes
and aspects of the present disclosure. For example, the known processes use a
cascading
propane refrigeration circuit or a warm-end mixed refrigerant to pre-cool the
gas. Both these
known processes have the advantage of providing 5% to 15% higher efficiency
than the SMR
process. Furthermore, the capacity of a single liquefaction train using these
known processes
can be significantly greater than that of a single SMR train. The pre-cooling
refrigeration
circuit of these technologies, however, comes at the cost of added complexity
to the
liquefaction process since additional refrigerants and a substantial amount of
extra equipment
is introduced. For example, the DMR's disadvantage of higher complexity and
weight may
outweigh its advantages of higher efficiency and capacity when deciding
between and DMR
process and SMR process for an FLNG application. The known processes have
considered the
addition of a pre-cooling process upstream of the SMR process as being driven
principally by
the need for higher thermal efficiencies and higher LNG production capacity
for a single train.
The HPCE process combined with the SMR process has not been realized
previously because
it does not provide the higher thermal efficiencies that the refrigerant-based
precooling process
provides. As described above, the thermal efficiency of the HPCE process with
SMR is about
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the same as a standalone SMR process. The disclosed aspects are believed to be
novel based
at least in part on its description of a pre-cooling process that aims to
reduce the weight and
complexity of the liquefaction process rather than increase thermal
efficiency, which in the past
has been the biggest driver for the addition of a pre-cooling process for
onshore LNG
applications. For the newer applications of FLNG, footprint, weight, and
complexity of the
liquefaction process may be a bigger driver of project cost. Therefore the
disclosed aspects are
of particular value.
[0048] In an aspect, an expander-based liquefaction process may be
enhanced by the
addition of an HPCE process upstream of the expander-based process. More
specifically, in
this aspect, a pretreated natural gas stream may be compressed to pressure
greater than 2,000
psia (13,790 kPa), or more preferably greater than 3,000 psia (20,680 kPa).
The hot
compressed gas may then be cooled by exchanging heat with the environment to
form a
compressed pretreated gas. The compressed pretreated gas may be near-
isentropically
expanded to a pressure less than 3,000 psia (20,680 kPa), or more preferably
to a pressure less
than 2,000 psia (13,790 kPa) to form a chilled pretreated gas, where the
pressure of the chilled
pretreated gas is less than the pressure of the compressed pretreated gas. The
chilled pretreated
gas is directed to an expander-based process where the gas is further cooled
to form LNG. In
a preferred aspect, the chilled pretreated gas may be directed to a feed gas
expander-based
process.
[0049] Figure 2 shows a typical temperature cooling curve 200 for an
expander-based
liquefaction process. The higher temperature curve 202 is the temperature
curve for the natural
gas stream. The lower temperature curve 204 is the composite temperature curve
of a cold
cooling stream and a warm cooling stream. As illustrated, the cooling curve is
marked by three
temperature pinch-points 206, 208, and 210. Each pinch point is a location
within the heat
.. exchanger where the combined heat capacity of the cooling streams is less
than that of the
natural gas stream. This imbalance in heat capacity between the streams
results in reduction
in the temperature difference between the cooling streams to the minimally
acceptable
temperature difference which provides effective heat transfer rate. The lowest
temperature
pinch-point 206 occurs where the colder of the two cooling streams, typically
the cold cooling
stream, enters the heat exchanger. The intermediate temperature pinch-point
208 occurs where
the second cooling stream, typically the warm cooling stream, enters the heat
exchanger. The
warm temperature pinch-point 210 occurs where the cold and warm cooling
streams exit the
heat exchanger. The warm temperature pinch-point 210 causes a need for a high
mass flow
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rate for the warmer cooling stream, which subsequently increases the power
demand of the
expander-based process.
[0050] One proposed method to eliminate the warm temperature pinch-point
210 is to
precool the feed gas with an external refrigeration system such as a propane
cooling system or
a carbon dioxide cooling system. For example, United States Patent No.
7,386,996 eliminates
the warm temperature pinch-point by using a pre-cooling refrigeration process
comprising a
carbon dioxide refrigeration circuit in a cascade arrangement. This external
pre-cooling
refrigeration system has the disadvantage of significantly increasing the
complexity of the
liquefaction process since an additional refrigerant system with all its
associated equipment is
io introduced. Aspects disclosed herein reduce the impact of the warm
temperature pinch-point
210 by precooling the feed gas stream by compressing the feed gas to a
pressure greater than
2,000 psia (12,790 kPa), cooling the compressed feed gas stream, and expanding
the
compressed gas stream to a pressure less than 3,000 psia (20,690 kPa), where
the expanded
pressure of the feed gas stream is less than the compressed pressure of the
feed gas stream.
This process of cooling the feed gas stream results in a significant reduction
in the in the
required mass flow rate of the expander-based process cooling streams. It also
improves the
thermodynamic efficiency of the expander-based process without significantly
increasing the
equipment count and without the addition of an external refrigerant.
[0051] In a preferred aspect, the expander-based process may be a feed gas
expander-based
process. The feed gas expander-based process may be an open loop feed gas
process where
the recycling loop comprises a warm-end expander loop and a cold-end expander
loop. The
warm-end expander may discharge a first cooling stream and the cold-end
expander may
discharge the second cooling stream. The temperature of the first cooling
stream is higher than
the temperature of the second cooling stream. In an aspect, the pressure of
the first cooling
stream is higher than the pressure of the second cooling stream. In another
aspect, the cold-end
expander discharges a two-phase stream that is separated into a second cooling
stream and a
second pressurize LNG stream. Specifically, a produced natural gas stream may
be treated to
remove impurities, if present, such as water, heavy hydrocarbons, and sour
gases, to make the
natural gas suitable for liquefaction. The treated natural gas may be directed
to the HPCE
process where it is compressed to a pressure greater than 2,000 psia (12,790
kPa), or more
preferably greater than 3,000 psia (20,680 kPa). The hot compressed gas may
then be cooled
by exchanging heat with the environment to form a compressed treated natural
gas. The
compressed treated natural gas may be near-isentropically expanded to a
pressure less than
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3,000 psia (20,680 kPa), or more preferably to a pressure less than 2,000 psia
(12,790 kPa) to
form a chilled treated natural gas, where the pressure of the chilled treated
natural gas is less
than the pressure of the compressed treated natural gas. The chilled treated
natural gas may be
completely liquefied by indirect exchange of heat with the first cooling
stream and the second
cooling stream to produce a first pressurized LNG stream. The first
pressurized LNG stream
may be mixed with the second pressurized LNG stream to form a pressurized LNG
stream.
The pressurized LNG stream may be directed to at least one two-phase
separation stage where
the pressure of the pressurized LNG stream is reduced and the resulting two-
phase stream is
separated into a flash gas stream and an LNG product stream. The flash gas
stream may
exchange heat with the pressurized LNG stream and the chilled treated natural
gas stream prior
to being compressed for fuel gas and/or compressed to mix with the recycling
second cooling
stream.
[0052] The combination of the HPCE process with the feed gas expander-
based process
has several advantages over a conventional feed gas expander-based process.
Including the
HPCE process therewith may increase the efficiency of the of the feed gas
expander-based
process by 20 to 25%. Thus, the feed-gas expander process of this invention
has an efficiency
approaching that of an SMR process while still providing the advantages of no
external
refrigerant use, ease of operation, and reduced equipment count. Furthermore,
the refrigerant
flow rates and the size of the recycle compressors are expected to be
significantly lower for the
expander-base process combined with the HPCE process. For these reasons, the
production
capacity of a single liquefaction train according to disclosed aspects may be
greater than 50%
above the production capacity of a similarly sized conventional expander-based
liquefaction
process.
[0053] Figure 3 is an illustration of an arrangement of SMR liquefaction
modules on a
FLNG 300. Natural gas 302 that is pretreated or otherwise suitable for
liquefaction may be
distributed evenly between five identical or near identical SMR liquefaction
modules or trains
304, 306, 308, 310, 312. As an example, each SMR liquefaction module may
receive
approximately 50 MW of compression power from either a gas turbine or an
electric motor
(not shown) to drive the compressors of the SMR liquefaction modules. Each SMR
liquefaction module may produce approximately 1.5 MTA of LNG for a total
stream day
production of approximately 7.5 MTA of LNG for the FLNG application.
[0054] Figure 4 is an illustration of an arrangement of an HPCE module 404
with the SMR
liquefaction modules or trains 406, 408, 410, 412 on a FLNG 400 according to
disclosed
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aspects. Natural gas 402 that is pretreated or otherwise suitable for
liquefaction may be directed
to the HPCE module 404 to produce a chilled pretreated gas stream 405. The
HPCE module
404 may receive approximately 50 MW of compression power, for example, from
either a gas
turbine or an electric motor (not shown) to drive one or more compressors
within the HPCE
module 404. The chilled pretreated gas may be distributed evenly between the
four identical
or near identical SMR liquefaction modules 406, 408, 410, 412. Each SMR
liquefaction
module may receive approximately 50 MW of compression power from either a gas
turbine or
an electric motor (not shown) to drive the compressors of the respective SMR
liquefaction
modules. Each SMR liquefaction module may produce approximately 1.9 MTA of LNG
for a
to total stream day production of approximately 7.6 MTA of LNG for the FLNG
application.
[0055] Figure 5 is an illustration of an aspect of the HPCE module 500
referenced in
Figure 4. A natural gas stream 502 that has been pretreated to remove
impurities, or is
otherwise suitable for liquefaction, is fed into a first compressor 504 to
form a first intermediate
pressure gas stream 506. The first intermediate pressure gas stream 506 may
flow through a
first heat exchanger 508 where the first intermediate pressure gas stream 506
is cooled by
indirectly exchanging heat with the environment to form a cooled first
intermediate pressure
gas stream 510. The first heat exchanger 508 may be an air cooled heat
exchanger or a water
cooled heat exchanger. The cooled first intermediate pressure gas stream 510
may then be
compressed within a second compressor 512 to form a second intermediate
pressure gas stream
zo 514. The second intermediate pressure gas stream 514 may flow through a
second heat
exchanger 516 where the second intermediate pressure gas stream 514 is cooled
by indirectly
exchanging heat with the environment to form a cooled second intermediate
pressure gas
stream 518. The second heat exchanger 516 may be an air cooled heat exchanger
or a water
cooled heat exchanger. The cooled second intermediate pressure gas stream 518
may then be
compressed within a third compressor 520 to form a high pressure gas stream
522. The
pressure of the high pressure gas stream 522 may be greater than 2,000 psia
(13,790 kPa), or
more preferably greater than 3,000 psia (20,680 kPa). The high pressure gas
stream 522 may
flow through a third heat exchanger 524 where the high pressure gas stream 522
is cooled by
indirectly exchanging heat with the environment to form a cooled high pressure
gas stream
526. The third heat exchanger 524 may be an air cooled heat exchanger or a
water cooled heat
exchanger. The cooled high pressure gas stream 526 may then be expanded within
an expander
528 to form a chilled pretreated gas stream 530. The pressure of the chilled
pretreated gas
stream 530 may be less than 3,000 psia (20,680 kPa), or more preferably less
than 2,000 psia
(13,790 kPa), and the pressure of the chilled pretreated gas stream 530 may be
less than the
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pressure of the cooled high pressure gas stream 526. In an aspect, the third
compressor 520
may be driven solely by the shaft power produced by the expander 528, as
illustrated by line
532.
[0056] Figure 6 is an illustration of an HPCE process 601 combined with a
feed gas
expander-based LNG liquefaction process 600. Natural gas may be treated to
remove
impurities, if present, such as water, heavy hydrocarbons, and sour gases, to
produce a treated
natural gas stream 602 that is suitable for liquefaction. The treated natural
gas stream 602 may
be mixed with a recycled refrigerant gas stream 604 to form a combined stream
606. The
combined stream 606 may be directed to the HPCE process 601 where the combined
streams
to 606 are compressed within a first compressor 608 to form an intermediate
pressure gas stream
610. The intermediate pressure gas stream 610 may flow through a first heat
exchanger 612
where the intermediate pressure gas stream 610 is cooled by indirectly
exchanging heat with
the environment to form a cooled intermediate pressure gas stream 614. The
first heat
exchanger 612 may be an air cooled heat exchanger or a water cooled heat
exchanger. The
cooled intermediate pressure gas stream 614 may then be compressed within a
second
compressor 616 to form a high pressure gas stream 618. The pressure of the
high pressure gas
stream 618 may be greater than 2,000 psia (13,790 kPa), or more preferably
greater than 3,000
psia (20,680 kPa). The high pressure gas stream 618 may flow through a second
heat exchanger
620 where the high pressure gas stream 618 is cooled by indirectly exchanging
heat with the
zo environment to form a cooled high pressure gas stream 622. The second
heat exchanger 620
may be an air cooled heat exchanger or a water cooled heat exchanger. The
cooled high
pressure gas stream 622 may then be expanded within an HPCE expander 624 to
form a chilled
pretreated gas stream 626. The pressure of the chilled pretreated gas stream
626 is less than
3,000 psia (20,680 kPa), or more preferably less than 2,000 psia (13,790 kPa),
and where the
pressure of the chilled pretreated gas stream 626 is less than the pressure of
the cooled high
pressure gas stream 622. In an aspect, the second compressor 616 may be driven
solely by the
shaft power produced by the expander 624, as represented by the dashed line
628.
[0057] As illustrated in Figure 6, the chilled pretreated gas stream 626
leaves the HPCE
process 601 and is directed to a feed gas expander-based process 600. The
chilled pretreated
gas stream 626 may be separated into a second chilled pretreated gas stream
630, a first
refrigerant stream 632, and a second refrigerant stream 634. The first
refrigerant stream 632
may be expanded in a first expander 636 to produce a first cooling stream 638.
The first cooling
stream 638 enters at least one cryogenic heat exchanger 640 where it exchanges
heat with the
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second chilled pretreated gas stream 630 and the second refrigerant stream 634
to cool said
streams. The first cooling stream 638 exits the at least one cryogenic heat
exchanger 640 as a
first warm stream 642. The second refrigerant stream 634, after being cooled
in the at least
one cryogenic heat exchanger 640, may be expanded in a second expander 644 to
produce a
two-phase stream 646. The pressure of the two-phase stream 646 may be the same
or may be
lower than the pressure of the first cooling stream 638. The two-phase stream
646 may be
separated into its vapor component and its liquid component in a first two-
phase separator 648
to form a second cooling stream 650 and a second pressurized LNG stream 652.
The
temperature of the first cooling stream 638 is higher than the temperature of
the second cooling
II) stream 650. The second cooling stream 650 enters the at least one
cryogenic heat exchanger
640 where it exchanges heat with the second chilled pretreated gas stream 630
and the second
refrigerant stream 634 to cool said streams. The second cooling stream 650
exits the at least
one heat exchanger 640 as a second warm stream 654. The second chilled
pretreated natural
gas stream 630 exchanges heat with the first cooling stream 638 and the second
cooling stream
650 to produce a first pressurized LNG stream 656. The first pressurized LNG
stream 656 may
be reduced in pressure in a hydraulic turbine 658 after exiting the at least
one heat exchanger
640. The first pressurized LNG stream 656 may be mixed with the second
pressurized LNG
stream 652 to form a combined pressurized LNG stream 660. The combined
pressurized LNG
stream 660 may be directed to a second two-phase separator 662 where the
pressure of the
combined pressurized LNG stream 660 is reduced, and the resulting two-phase
stream is
separated into an end flash gas stream 664 and a product LNG stream 667. The
end flash gas
stream 664 may exchange heat with the first pressurized LNG stream 656 within
an end flash
gas heat exchanger 668 prior to directing the first pressurized LNG stream 656
to the hydraulic
turbine 658. Additionally, the end flash gas stream 664 may enter the at least
one cryogenic
heat exchanger 640 to exchange heat with the second chilled pretreated gas
stream 630 and the
second refrigerant stream 634 to cool said streams. The end flash gas stream
664 exits the at
least one heat exchanger 640 as a third warm stream 670. The third warm stream
670 may be
compressed in a first recycle gas compressor 672 and may exchange heat with
the environment
in a first recycle heat exchanger 674 to form a first recycle gas stream 676.
The first recycle
gas stream 676 may be combined with the second warm stream 654 and, together,
may be
compressed in a second recycle gas compressor 678, and may exchange heat with
the
environment in a second recycle heat exchanger 680 to form a second recycle
gas stream 682.
The second recycle gas stream 682 may be combined with the first warm stream
642 and,
together, may be compressed in third and fourth recycle gas compressors 684,
686 and may
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exchange heat with the environment in a third recycle heat exchanger 688 to
form the recycle
refrigerant gas stream 604. The third recycle gas compressor 684 may be driven
solely by the
shaft power produced by the first expander 636, as shown by the dashed line
690. The fourth
recycle gas compressor 686 may be driven solely by the shaft power produced by
the second
expander 644, as shown by the dashed line 692.
[0058] Figure 7 illustrates a method 700 of producing LNG according to
disclosed aspects.
At block 702 a natural gas stream may be provided from a supply of natural
gas. At block 704
the natural gas stream may be compressed in at least two serially arranged
compressors to a
pressure of at least 2,000 psia to form a compressed natural gas stream. At
block 706 the
1() compressed natural gas stream may be cooled to form a cooled compressed
natural gas stream.
At block 708 the cooled compressed natural gas stream may be expanded in at
least one work
producing natural gas expander to a pressure that is less than 3,000 psia and
no greater than the
pressure to which the at least two serially arranged compressors compress the
natural gas
stream, to thereby form a chilled natural gas stream. At block 710 the chilled
natural gas stream
may be liquefied.
[0059] Figure 8 is an illustration of another HPCE process 800 according
to disclosed
aspects. As with HPCE process 100 shown in Figure 1, HPCE process 800 may
comprise a
first compressor 802 which compresses a pretreated natural gas stream 804 to
form an
intermediate pressure gas stream 806. The intermediate pressure gas stream 806
may flow
through a first heat exchanger 808 where the intermediate pressure gas stream
806 is cooled by
indirectly exchanging heat with the environment to form a cooled intermediate
pressure gas
stream 810. The first heat exchanger 808 may be an air cooled heat exchanger
or a water cooled
heat exchanger. The cooled intermediate pressure gas stream 810 may then be
compressed
within a second compressor 812 to form a high pressure gas stream 814. The
pressure of the
high pressure gas stream 814 may be greater than 2,000 psia (13,790 kPa), or
more preferably
greater than 3,000 psia (20,680 kPa). The high pressure gas stream 814 may
flow through a
second heat exchanger 816 where the high pressure gas stream 814 is cooled by
indirectly
exchanging heat with the environment to form a cooled high pressure gas stream
818. The
second heat exchanger 816 may be an air cooled heat exchanger or a water
cooled heat
exchanger. The cooled high pressure gas stream 818 may then be directed to a
high pressure
heat exchanger 826, where it is further cooled to a temperature below the
ambient temperature
by exchanging heat with one or more refrigerant streams 828 from a process
external to the
HPCE process 800. In one aspect, the one or more refrigerant streams are
refrigerant streams
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that have cryogenically cooled, chilled, and/or liquefied the chilled,
pretreated natural gas
stream 822 after it has exited the HPCE process 800. These refrigerant streams
may still be
cold enough, even after liquefying natural gas, to cool the cooled high
pressure gas stream 818.
The cooled high pressure gas stream 818 exits the high pressure heat exchanger
826 at a
temperature below 30 degrees C or below 20 degrees C or below 15 degrees C and
is expanded
within an expander 820 to form the chilled pretreated gas stream 822. The
pressure of the
chilled pretreated gas stream 122 may be less than 3,000 psia (20,680 kPa), or
more preferably
less than 2,000 psia (13,790 kPa), and the pressure of the chilled pretreated
gas stream 822 is
less than the pressure of the cooled high pressure gas stream 818. In a
preferred aspect, the
io second compressor 812 may be driven solely by the shaft power produced
by the expander 820,
as indicated by the dashed line 824.
[0060] Figure 9 depicts an implementation of an HPCE process 901, similar
to HPCE
process 601, and combined with a feed gas expander-based LNG liquefaction
process 900.
Those elements in Figure 9 identified by reference numbers found in Figure 6
(e.g., 636, 644,
668) perform identical or similar functions to the previously described
elements and for the
sake of brevity will not be further described. HPCE process 901 includes a
high pressure heat
exchanger 905 that exchanges heat between the cooled high pressure gas stream
622 and the
first warm stream 642 that has exited the at least one cryogenic heat
exchanger 640. After
passing through the high pressure heat exchanger 905, the first warm stream
642 is combined
with the second recycle gas stream 682 and compressed in the third and fourth
recycle gas
compressors 684, 686 as previously described.
[0061] Figure 10 depicts another implementation of an HPCE process 1001,
similar to
HPCE process 601, and combined with a feed gas expander-based LNG liquefaction
process
1000. Those elements in Figure 10 identified by reference numbers found in
Figure 6 (e.g.,
636, 644, 668) perform identical or similar functions to the previously
described elements and
for the sake of brevity will not be further described. HPCE process 1001
includes a high
pressure heat exchanger 1005 that exchanges heat between the cooled high
pressure gas stream
622 and the second warm stream 654 that has exited the at least one cryogenic
heat exchanger
640. After passing through the high pressure heat exchanger 1005, the second
warm stream
654 is combined with the first recycle gas stream 676 and compressed in the
second recycle
gas compressor 678 as previously described.
[0062] Figure 11 depicts another implementation of an HPCE process 1101,
similar to
HPCE process 601, and combined with a feed gas expander-based LNG liquefaction
process
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1100. Those elements in Figure 11 identified by reference numbers found in
Figure 6 (e.g.,
636, 644, 668) perform identical or similar functions to the previously
described elements and
for the sake of brevity will not be further described. HPCE process 1101
includes a high
pressure heat exchanger 1105 that exchanges heat between the cooled high
pressure gas stream
622 and both the first warm stream 642 and the second warm stream 654 that
have exited the
at least one cryogenic heat exchanger 640. After passing through the high
pressure heat
exchanger 1105, the first warm stream 642 is combined with the second recycle
gas stream 682
and compressed in the third and fourth recycle gas compressors 684, 686 as
previously
described. After passing through the high pressure heat exchanger 1105, the
second warm
to .. stream 654 is combined with the first recycle gas stream 676 and
compressed in the second
recycle gas compressor 678 as previously described.
[0063] The disclosed aspects that include a high pressure heat exchanger
in the HPCE
module (i.e., Figures 8-11) take advantage of refrigerant streams are still
cold enough, after an
initial use, to increase the pre-cooling of a natural gas stream in the HPCE
module. An
advantage of using such a high pressure heat exchanger in the HPCE module is
that the
efficiency of the overall liquefaction process shown in Figure 9, for example,
may improve as
much as approximately 3% compared to the efficiency of the liquefaction
process shown in
Figure 6.
[0064] Figure 12 is a method 1200 of producing LNG according to disclosed
aspects. At
block 1202 a natural gas stream may be provided from a supply of natural gas.
At block 1204
the natural gas stream may be compressed in at least two serially arranged
compressors to a
pressure of at least 2,000 psia to form a compressed natural gas stream. At
block 1206 the
compressed natural gas stream may be cooled to form a cooled compressed
natural gas stream.
At block 1208 the cooled compressed natural gas stream is additionally cooled
to a temperature
below the ambient temperature to form an additionally cooled compressed
natural gas stream.
At block 1210 the cooled compressed natural gas stream may be expanded in at
least one work
producing natural gas expander to a pressure that is less than 3,000 psia and
no greater than the
pressure to which the at least two serially arranged compressors compress the
natural gas
stream, to thereby form a chilled natural gas stream. At block 1212 the
chilled natural gas
stream may be liquefied.
[0065] Disclosed aspects may include any combinations of the methods and
systems shown
in the following numbered paragraphs. This is not to be considered a complete
listing of all
possible aspects, as any number of variations can be envisioned from the
description above.
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A method of producing liquefied natural gas (LNG), the method comprising:
providing a natural gas stream from a supply of natural gas;
compressing the natural gas stream in at least two serially arranged
compressors to a
pressure of at least 2,000 psia to form a compressed natural gas stream;
cooling the compressed natural gas stream by indirect heat exchange with an
ambient
temperature air or water to form a cooled compressed natural gas stream;
additionally cooling the cooled compressed natural gas stream to a temperature
below
the ambient temperature to form an additionally cooled compressed natural gas
stream;
expanding, in at least one work producing natural gas expander, the
additionally cooled
to compressed
natural gas stream to a pressure that is less than 3,000 psia and no greater
than the
pressure to which the at least two serially arranged compressors compress the
natural gas
stream, to thereby form a chilled natural gas stream; and
liquefying the chilled natural gas stream by indirect heat exchange with a
refrigerant to
form liquefied natural gas and a warm refrigerant;
wherein the cooled compressed natural gas stream is additionally cooled using
the
warm refrigerant.
2. The method of paragraph 1, wherein liquefying the chilled natural gas
stream is
performed in one or more single mixed refrigerant (SMR) liquefaction trains.
3. The method of paragraph 1, wherein liquefying the chilled natural gas
stream is
zo performed in
one or more expander-based liquefaction modules, and wherein the expander-
based liquefaction module is one of a nitrogen gas expander-based liquefaction
module and a
feed gas expander-based liquefaction module.
4. The method of paragraph 3, wherein the feed gas expander-based
liquefaction
module is an open loop feed gas expander-based liquefaction module, and
wherein a recycle
refrigerant stream of the open loop feed gas expander-based process is
combined with the
natural gas stream prior to the compressing step.
5. The method of paragraph 4, wherein the chilled natural gas stream is a
first
chilled natural gas stream, and further comprising:
separating the first chilled natural gas stream into a second chilled natural
gas stream,
a first refrigerant stream, and a second refrigerant stream:
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discharging a first cooling stream from a warm-end expander forming part of
the feed
gas expander-based liquefaction module, the first cooling stream haying a
first temperature;
and
discharging a second cooling stream from a cold-end expander forming part of
the feed
gas expander-based liquefaction module, the second cooling stream having a
second
temperature;
wherein the first temperature is higher than the second temperature.
6. The method of paragraph 5, further comprising:
expanding the first refrigerant stream in the warm-end expander to produce the
first
cooling stream; and
expanding the second refrigerant stream in the cold-end expander to produce
the second
cooling stream.
7. The method of paragraph 4, further comprising:
discharging a first cooling stream from a warm-end expander forming part of
the feed
gas expander-based liquefaction module, the first cooling stream haying a
first temperature;
discharging a two-phase stream from a cold-end expander forming part of the
feed gas
expander-based liquefaction module, the two-phase stream having a second
temperature,
wherein the first temperature is higher than the second temperature;
expanding the first refrigerant stream in the warm-end expander to produce the
first
cooling stream;
expanding the second refrigerant stream in the cold-end expander to produce
the two-
phase stream; and
separating the two-phase stream into a second cooling stream and a first
pressurized
LNG stream.
8. The method of any of paragraphs 5-7, wherein a pressure of the first
cooling
stream is one of
the same or similar to a pressure of the second cooling stream, or
higher than a pressure of the second cooling stream.
9. The method of any of paragraphs 5-7, wherein the liquefying step
comprises
cooling the second chilled natural gas stream to form a second pressurized LNG
stream by
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exchanging heat with the first cooling stream and the second cooling stream to
form a first
warm cooling stream and a second warm cooling stream.
10. The method of paragraph 9, wherein the second pressurized LNG stream is
mixed with the first pressurized LNG stream prior to expanding the second
pressurized LNG
stream.
11. The method of paragraph 9, further comprising:
reducing a pressure of the second pressurized LNG stream such that the second
pressurized LNG stream undergoes at least one stage of pressure reduction;
separating the reduced-pressure second pressurized LNG stream into an end-
flash gas
stream and an LNG stream; and
cooling the second pressurized LNG stream and the second chilled natural gas
stream
using the end-flash gas stream.
12. The method of paragraph 11, further comprising:
after cooling the second pressurized LNG stream and the second chilled natural
gas
stream using the end-flash gas stream, compressing the end-flash gas stream
and mixing the
compressed end-flash gas stream with one or more recycling refrigerant
streams.
13. The method of paragraph 11, further comprising:
after cooling the second pressurized LNG stream and the second chilled natural
gas
stream using the end-flash gas stream, compressing the end-flash gas stream
and using the
compressed end-flash gas stream as fuel.
14. The method of paragraph 9, wherein the first warm cooling stream is
used as
the warm refrigerant to additionally cool the cooled compressed natural gas
stream to form the
additionally cooled compressed natural gas stream.
15. The method of paragraph 9, wherein the second warm cooling stream is
used as
the warm refrigerant to additionally cool the cooled compressed natural gas
stream to form the
additionally cooled compressed natural gas stream.
16. The method of paragraph 3, wherein the expander-based liquefaction
module
comprises:
a first expanded refrigerant within a first gas phase refrigeration cycle; and
a second expanded refrigerant within a second gas phase refrigeration cycle.
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17. The method of paragraph 16, wherein the first expanded refrigerant is
feed gas.
18. The method of paragraph 16 or paragraph 17, wherein the first gas phase
refrigeration cycle is a closed loop refrigeration cycle.
19. The method of any of paragraphs 16-18, wherein the second expanded
refrigerant is nitrogen.
20. The method of any of paragraphs 16-19, wherein the second gas phase
refrigeration cycle is a closed loop refrigeration cycle.
21. The method of any of paragraphs 1-20 wherein the at least two
compressors
compress the natural gas stream to a pressure greater than 3,000 psia.
22. The method of any of paragraphs 1-21, wherein the natural gas expander
is a
work producing expander that expands the additionally cooled compressed
natural gas stream
to a pressure less than 2,000 psia.
23. The method of any of paragraphs 1-22, further comprising:
performing the compressing, cooling, additionally cooling, expanding, and
liquefying
steps on a topside of a floating LNG structure.
24. The method of any of paragraphs 1-23, wherein the temperature of the
additionally cooled compressed natural gas stream is less than 30 C.
25. The method of any of paragraphs 1-24, wherein the temperature of the
additionally cooled compressed natural gas stream is less than 15 C.
26. An apparatus for the liquefaction of natural gas, comprising:
at least two serially arranged compressors configured to compress a natural
gas stream
to a pressure greater than 2,000 psia, thereby forming a compressed natural
gas stream;
a cooling element configured to cool the compressed natural gas stream,
thereby
forming a cooled compressed natural gas stream;
a heat exchanger configured to further cool the cooled compressed natural gas
stream
to a temperature below an ambient temperature to thereby produce an
additionally cooled
compressed natural gas stream;
at least one work-producing expander configured to expand the additionally
cooled
compressed natural gas stream to a pressure less than 3,000 psia and no
greater than the
pressure to which the at least two serially arranged compressors compress the
natural gas
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stream, to thereby form a chilled natural gas stream; and
a liquefaction train configured to liquefy the chilled natural gas stream;
wherein a warm refrigerant used by the liquefaction train is directed to the
heat
exchanger to further cool the cooled compressed natural gas stream.
27. The apparatus of
paragraph 26, wherein the liquefaction train comprises one of
a nitrogen gas expander-based liquefaction module and an open loop feed gas
expander-based
liquefaction module, and further comprising, when the liquefaction train
comprises an open
loop feed gas expander-based module, a recycle refrigerant stream of the open
loop feed gas
expander-based module that is combined with the natural gas stream prior to
the natural gas
to stream being
compressed by the two or more serially-arranged compressors, wherein the
chilled natural gas stream is a first chilled natural gas stream that is
separated into a second
chilled natural gas stream, a first refrigerant stream, and a second
refrigerant stream.
28. The apparatus of paragraph 27, wherein the feed gas expander-based
liquefaction module comprises:
a warm-end expander configured to expand the first refrigerant stream to form
a first
cooling stream discharged therefrom, the first cooling stream haying a first
temperature; and
a cold-end expander configured to expand the second refrigerant stream to form
one of
a second cooling stream and a two-phase stream discharged therefrom, the
second cooling
stream haying a second temperature;
wherein the first temperature is higher than the second temperature.
29. The apparatus of any of paragraphs 26-28, wherein the natural gas
expander is
a work producing expander configured to expand the cooled compressed natural
gas stream to
a pressure less than 2,000 psia.
30. The apparatus of any of paragraphs 26-29, wherein the at least two
serially
arranged compressors, the cooling element, the heat exchanger, the at least
one work-producing
expander, and the liquefaction train are disposed on a floating LNG structure.
31. The apparatus of paragraph 30, wherein the at least two serially
arranged
compressors, the cooling element, the heat exchanger, and the at least one
work-producing
expander are disposed within a single module on a topside of the floating LNG
structure.
32. A floating LNG structure, comprising:
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at least two serially arranged compressors configured to compress a natural
gas stream
to a pressure greater than 2,000 psia, thereby forming a compressed natural
gas stream;
a cooling element configured to cool the compressed natural gas stream,
thereby
forming a cooled compressed natural gas stream;
a heat exchanger configured to further cool the cooled compressed natural gas
stream
to a temperature below an ambient temperature to thereby produce an
additionally cooled
compressed natural gas stream;
at least one work-producing expander configured to expand the additionally
cooled
compressed natural gas stream to a pressure less than 3,000 psia and no
greater than the
pressure to which the at least two serially arranged compressors compress the
natural gas
stream, to thereby form a chilled natural gas stream; and
a liquefaction train configured to liquefy the chilled natural gas stream;
wherein a warm refrigerant used by the liquefaction train is directed to the
heat
exchanger to further cool the cooled compressed natural gas stream.
[0066] While the foregoing is directed to aspects of the present
disclosure, other and further
aspects of the disclosure may be devised without departing from the basic
scope thereof, and
the scope thereof is determined by the claims that follow.
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