Note: Descriptions are shown in the official language in which they were submitted.
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COMPACT SYSTEM AND METHOD FOR THE PRODUCTION OF LIQUEFIED
NATURAL GAS
FIELD OF THE INVENTION
The present invention is directed to a system and a method for the production
of liquefied natural gas (LNG).
BACKGROUND TO THE INVENTION
Natural gas (NG) is routinely transported from one location to another
location
in its liquid state as Liquefied Natural Gas (LNG). Liquefaction of the
natural gas
makes it more economical to transport as LNG occupies only about 1/600 of the
volume that the same amount of natural gas does in its gaseous state. After
liquefaction, LNG is typically stored in cryogenic containers, typically
either at or
slightly above atmospheric pressure. LNG can be regasified before distribution
to
end users through a pipeline or other distribution network at a temperature
and
pressure that meets the delivery requirements of the end users.
Wellhead gas is subjected to gas pre-treatment to remove contaminants prior to
liquefaction. The hydrogen sulphide and carbon dioxide can be removed using a
suitable process such as amine absorption. Removal of water can be achieved
using
conventional methods, for example, a molecular sieve. Depending on the
composition of contaminants present in the inlet gas stream, the inlet gas
stream may
be subjected to further pre-treatment to remove other contaminants, such as
mercury
and heavy hydrocarbons prior to liquefaction.
Liquefaction is achieved using processes which typically involve compression,
expansion and cooling. Such processes are applied in technologies such as
C3/MR
process, the APXTM process, the Cascade Process, the Mixed Fluid Cascade
process
or the Double Mixed Refrigerant or Parallel Mixed Refrigerant process.
Refrigerants are cycled in one or more refrigeration loops to reduce the
temperature of the treated gas to a temperature of around -160 C to form LNG.
This
results in warming of the respective refrigerant which must be compressed for
recycle to the liquefaction process and subsequent expansion. Compressors used
for
this duty may be centrifugal compressors driven by gas turbines or electric
motors.
The refrigeration loop may comprise coolers to remove heat added due to
cooling
1
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and liquefying of the natural gas and due to the compression of the respective
refrigerants.
Over the last 10 to 15 years, the LNG industry has seen a shift from
traditional
stick-built LNG facilities to modular built projects. Examples are available
in, for
instance, Australia, the Russian arctic, and Canada. A main driver to change
to
modular built LNG trains is to move much of the site construction work to an
offsite
fabrication yard. At the yard, process units can be built in modular form in a
controlled, predictable environment. Remote fabrication of modules may result
in
increased productivity and lower labor rates, better quality, reduced chance
of safety
incidents, and improved predictability with respect to cost and schedule.
US-2014/053599-A1 discloses a liquefied natural gas production facility
comprising a plurality of spaced-apart modules for installation at a
production
location to form a production train having a major axis and a minor axis, each
module having a module base for mounting a plurality of plant equipment
associated
with a selected function assigned to said module, the module base having a
major
axis and a minor axis; and a plurality of heat exchangers arranged to run
parallel to
the major axis of the production train to form a heat exchanger bank having a
major
axis and a minor axis
US-2016/0010916-A1 discloses a liquefied natural gas production process for
producing a product stream of liquefied natural gas at a production location,
said
process comprising: a) designing a plurality of modules for installation at
the
production location to form an installed production train; (b) designing an
air-cooled
heat exchanger bank including: a first row of air-cooled heat exchanger bays,
and, an
adjacent parallel second row of air-cooled heat exchanger bays; (c) arranging
a first
sub-section of the first row of heat exchanger bays at an elevated level
vertically
offset from and towards a first edge of a first module base to form a covered
section
of the first module base, the first module base being designed and sized to
include an
uncovered section for mounting a selected piece of process equipment, wherein
the
first module includes the first subsection of the first row of heat exchanger
bays
without including a sub-section of the second row of heat exchanger bays; (d)
arranging a first sub-section of the second row of heat exchanger bays at an
elevated
level vertically offset from and towards a first edge of a second module base
to
provide a covered section of the second module base, wherein the second module
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includes the first sub-section of the second row of heat exchanger bays
without
including a sub-section of the first row of heat exchanger bays; and (e)
positioning
the first edge of the second module base at the production location towards
the first
edge of the first module base.
Modularization, which for instance aimed to circumvent high labor costs by
constructing modules of facilities at a location having reduced costs of labor
and
subsequently move the preconstructed modules to the LNG production location,
has
disappointed in practice. Production costs remained relatively high compared
to
conventional stick-built facilities. The general view is that, unless local
labor costs
are particularly high and/or productivity is particularly low, a plant with
stick-built
LNG production trains result in the lowest costs, albeit with an extended
construction
schedule, increased exposure to local influences and potential quality issues.
The
conventional modular approach generally is seen to lead to a better quality of
the
LNG production train, yet at the expense of higher capital expenditure.
Historically, the choice to use onshore modular built instead of stick-built
for
LNG production trains is generally taken after the basic (process) layout of
the plant
is fixed. Conversion of the plant design to a modular setup typically results
in
relatively large modules requiring a lot of structural steel and relatively
few
equipment items per module. The large number of modules required to span the
still
relatively large plant layout results in a relatively large residual in-field
hook-up
scope as there are many piping connections. As a result, the full system must
be leak
tested on site. Additionally, most of the cabling has to be installed and
tested on site.
The latter are both relatively time consuming and costly.
W02019110769 in the name of applicant provides a modular liquefaction train
for LNG production, with reduced capital expenditure and footprint. Footprint
herein
refers to the area of the liquefaction train. Area herein refers to the
surface included
within the boundaries of the liquefaction train.
Despite the advantages and cost savings provided by the modular designed
liquefaction systems as for instance disclosed in the references above, there
remains
a need to explore alternative designs to further reduce capital expenditure
and
footprint.
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SUMMARY OF THE INVENTION
In one aspect, a facility for the production of liquefied natural is provided.
The
facility comprises an inside battery limit (ISBL) comprising a liquefaction
train. The
liquefaction train comprises a plurality of modules with each module being
adapted
to perform at least one process step associated with liquefied natural gas
production.
The plurality of modules comprise
a first module for acid gas removal;
a second module comprising a dehydration unit;
a third module, being the liquefaction module; and
a fourth module comprising equipment for processing of natural gas
liquids.
The train further comprises a first mixed refrigerant cycle comprising a first
mixed
refrigerant and a second mixed refrigerant cycle comprising a second mixed
refrigerant connected to the liquefaction module for cooling a gas stream to
produce
the liquefied natural gas. The train further comprises a primary cooling loop
to cool
at least a process stream from each module and the first mixed refrigerant and
the
second mixed refrigerant against a first coolant comprising clean water. The
primary
cooling loop is a closed clean water cooling loop and the cooling is against
an
ambient temperature. The train further comprises a first plurality of heat
exchangers
through which the primary cooling loop extends, and the cooling by the primary
cooling loop is via heat exchange in at least the first plurality of heat
exchangers with
respect to the first coolant. More than 50% of the first plurality of heat
exchangers
are printed circuit heat exchangers which are adapted to provide at least 80%
of the
cooling against the ambient temperature.
Optionally, the liquefaction train further comprises a second plurality of
heat exchangers through which the primary cooling loop extends to cool the
first
coolant by heat exchange with a second coolant, and the facility further
comprises
- an outside battery limit (OSBL) comprising a cooler for cooling against the
ambient temperature; and
- a secondary cooling loop extending through the second plurality of heat
exchangers and the cooler to cool the second coolant against ambient
temperature,
thereby enabling moving of thermal energy from the ISBL to the OSBL for
dissipation against the ambient temperature in the OSBL.
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Optionally, the second coolant comprises water from a cooling tower system,
sea water, or air.
Optionally, each of the plurality of modules of the liquefaction train has a
predetermined maximum weight threshold, which can be 6000 tonnes.
Optionally, for the liquefaction train, the first module having a first side
engaging a first side of the second module, and the second module having a
second
side opposite the first side engaging a first side of the fourth module. The
liquefaction train further comprises a first module series comprising the
first module
engaging the second module engaging the fourth module, the first module series
being aligned with and arranged adjacent to a second module series comprising
the
third module arranged between the first compressor on one side and the second
compressor on the opposite side.
Optionally, the liquefaction train further comprises:
- a first compressor arranged on a first side of the liquefaction module
and
connected to the first mixed refrigerant cycle for compressing the first mixed
refrigerant; and
- a second compressor arranged on a second side of the liquefaction module,
the second side being opposite to the first side, and connected to the second
mixed
refrigerant cycle for compressing the second mixed refrigerant.
Optionally, the liquefaction train further comprises:
- a pre-cool heat exchanger arranged on the first side of the third module
and
connected to the first mixed refrigerant cycle for pre-cooling the gas stream
in heat
exchange with respect to the first mixed refrigerant; and
- a main heat exchanger arranged on the second side of the third module,
the
second side being opposite to the first side, and connected to the second
mixed
refrigerant cycle for at least partially liquefying the pre-cooled gas stream
in heat
exchange with respect to the second mixed refrigerant.
Optionally, the liquefaction train further comprises a pipe-rack for
supporting
conduits, the pipe-rack extending through at least the first module, the
second
module and the fourth module.
Optionally, the first mixed refrigerant cycle comprises a single precool heat
exchanger. The first mixed refrigerant cycle can further comprise a compressor
intercooler adapted to cool first mixed refrigerant compressed by the first
compressor
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without condensing the first mixed refrigerant, an outlet of the compressor
intercooler being connected to a subsequent stage of the first compressor.
Optionally, the liquefaction train has a capacity of production of liquefied
natural gas in the range of about 2 to 4 MTPA.
According to another aspect, the disclosure provides a method of producing
liquefied natural gas using a system as described above.
The system and method described above have been designed with
modularization in mind. The result provides a significant cost saving and
footprint
reduction with respect to convention systems, including modular built systems.
Details are provided in the detailed description section below.
BRIEF DESCRIPTION OF THE DRAWINGS
The drawing figures depict one or more implementations in accord with the
present teachings, by way of example only, not by way of limitation. In the
figures,
like reference numerals refer to the same or similar elements.
Figure 1 shows a diagram of a liquefaction system suitable for a system of the
disclosure;
Figure 2A shows a diagram of another embodiment of a liquefaction system
suitable for a system of the present disclosure;
Figure 2B shows a diagram of yet another embodiment of a liquefaction system
suitable for a system of the present disclosure;
Figure 3 shows a perspective view of an embodiment of a system according to
the disclosure;
Figure 4 shows a plan view of an embodiment of a system according to the
disclosure;
Figure 5A shows a plan view of another embodiment of a system according to
the disclosure;
Figure 5B shows a plan view of an embodiment of the system of the disclosure,
including a diagrammatical example of a flow of feed gas from gaseous feed to
liquefied product;
Figure 5C shows a plan view of an embodiment of the system of the disclosure,
including a diagrammatical example of a flow of cooling water through the
modules;
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Figure 6 shows a diagram indicating dependence of total equipment weight (in
tonnes) for a liquefaction system of a selected total capacity on size of each
liquefaction train (in million tonne per annum [mtpa]);
Figure 7 schematically shows a perspective view of a shell-and-tube heat
exchanger and a printed circuit heat exchanger for use in a system of the
present
disclosure;
Figure 8 shows a diagram indicating rationale of designing a system of the
present disclosure;
Figure 9 shows a diagram indicating a relation between a ratio of module
weight to equipment weight (vertical axis) and (mechanical) equipment weight
(in
tonnes) for modules of embodiments of the disclosures and modules of
conventional
projects as reference;
Figure 10 shows a diagram indicating an exemplary relation between
fabrication time (in months) and module weight (in tonnes);
Figure 11 shows a diagram of an exemplary cooling water loop for a system of
the present disclosure;
Figures 12A, 12B and 12C respectively show, on the same scale and for the
same liquefaction capacity (in mtpa), schematic representations in plan view
of an
exemplary conventional stick-built liquefaction train, an exemplary state of
the art
modular liquefaction train, and an embodiment of a liquefaction system
according to
the present disclosure;
Figure 13 shows a plan view of an exemplary site layout of a facility for the
production of liquefied natural gas, comprising a number of liquefaction
trains,
including state-of-the-art modular liquefaction trains and liquefaction
systems
according to the present disclosure.
Figure 14 shows a plan view of a comparison of a footprint of an embodiment
of a liquefaction system according to the present disclosure and a state-of-
the-art
modular built liquefaction facility, for the same production capacity
(typically
expressed in mtpa);
Figure 15 shows a diagram indicating an area or plot space per unit of
production (in mtpa) of a number of conventional (stick built and modular
built)
liquefaction facilities and of embodiments of a system according to the
disclosure;
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Figure 16 shows a diagram indicating green-house gas (GHG) intensity of a
number of conventional liquefaction facilities (stick built and modular built)
and of
embodiments of a system according to the disclosure;
Figure 17 shows a diagram indicating an estimate of pieces of equipment per
unit of production (in mtpa) of a number of conventional liquefaction
facilities and of
embodiments of a system according to the disclosure; and
Figure 18 shows a diagram indicating module weight per unit of production (in
mtpa) of a number of conventional modular built liquefaction facilities and of
embodiments of a system according to the disclosure.
DETAILED DESCRIPTION OF THE INVENTION
Certain terms used herein are defined as follows:
The term "LNG" refers to liquefied natural gas.
"Natural Gas Liquids" or "NGLs" are hydrocarbon components of natural gas
that are separated from the gas state in the form of liquids. NGLs may also be
referred to as condensate.
"LPG" relates to Liquid Petroleum Gases. LPG is a subset of NGL. LPG are
C3 to C4s with high vapor pressure. LPG typically includes propane and butane.
Trace amounts of C5 can be found in LPG due to the fractionation process.
"Heavy Hydrocarbons" or "HiHC" are hydrocarbon components comprising
five carbon atoms or more (C5+ components), including aromatics.
The term "LNG production train" refers to an assembly comprising process
units used for the pre-treatment of a natural gas feed stream to remove
contaminants
and provided treated gas, and process units used for receiving the treated gas
and
subjecting the treated gas to cooling to form liquefied natural gas.
The term "plant" may refer to the LNG production plant including one or more
LNG production trains.
The term "facility" may refer to an LNG production plant, but may
alternatively refer to an assembly in general.
The term "stick-built" refers to an LNG production train which has sections
built in subsequent order at the production location. Herein, stick-built is
similar to
conventional construction. Both refer to construction of a production train or
another
section of a plant predominantly at a production location. Herein, production
location
is the location of the plant itself
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In contrast, the term "module" refers to a section of a plant that may be
preassembled at a construction or assembly location remote from the production
location. Each module is typically designed to be transported from the
construction
or assembly location to the production location. Modules may be transported by
towing or on floating barges, or by land using, for instance, rail or truck.
After each
module is moved from the construction or assembly location to the production
location, the module is positioned in a suitable pre-determined orientation to
suit the
needs of a given LNG production facility.
As used herein, ISBL has its ordinary meaning known by one of ordinary skill
in the art, including being defined as comprising all equipment and associated
components (piping, etc.) that act upon the primary feed stream of a process,
which
is the process for the production of the liquefied natural gas in this
instance
(including removing contaminants from a natural gas feed stream to provide
treated
gas and cooling the treated gas to form liquefied natural gas). ISBL is
functional-
based and refers to equipment and other components that are solely dedicated
to a
particular process (e.g., process for the production of the liquefied natural
gas). Such
equipment may be referred to as the ISBL equipment or ISBL units.
Correspondingly, Outside Battery Limits (OSBL) as used herein also has its
ordinary meaning known to one of ordinary skill in the art, including being
defined
as utilities, common facilities, and other equipment and components not
included in
the ISBL definition. OSBL refers to systems (equipment pieces and associated
components) that support several units, including ISBL units. Typical OSBL
equipment includes cooling towers, water treatment facilities, tanks farms,
LNG
loading equipment, etc.
"Metric Tons" or "Tonnes" is a unit of weight equal to 1,000 kilograms.
LNG plant capacity is usually specified in million metric tonnes per year
(mt/y
or mtpa).
The capital expenditure to fabricate and build an LNG facility comprising
modular built LNG trains is typically driven by a few key levers, such as:
1) the compactness of each module individually;
2) the footprint of all modules of a liquefaction train together;
3) the equipment costs (for all equipment of all liquefaction trains);
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4) weight of respective modules, and the ratio of total weight of a
module to the weight of equipment in the respective module;
5) number of construction hours at the fabrication yard (for the entire
plant, including all modules); and
6) number of construction hours at the LNG production site (for the
entire plant, including all modules and including connections ['hook
ups'] between respective modules in a liquefaction train).
Weight of respective modules is relevant to capital expenditure due to
transportation costs, and the costs of steel to construct the respective
modules.
Module weight is an indicator for estimating costs. Module weight is typically
linked
to the number of fabrication hours in the yard as well as site hours and civil
scope to
support the modules on site.
Conventional modular liquefaction facilities typically improve on one or two
of
the levers listed above. As explained herein below, embodiments of the system
of the
disclosure target and improve on at least a majority of, or even all of, the
levers listed
above. As a result, capital expenditure to construct the system of the present
disclosure is significantly reduced with respect to conventional liquefaction
facilities,
including existing modular liquefaction facilities. Herein, a system according
to the
disclosure is compared to conventional plants, wherein the system of the
disclosure
has at least a similar production capacity and a similar energy efficiency. In
addition
to efficiency and capacity, the system of the present disclosure also enables
to
achieve close to best in class green-house gas (GHG) performance. The LNG
production system of the disclosure can be built faster and at lower cost.
This is done
by combining one or more, preferably all, of the features described below. A
description of each item respectively follows herein below, with reference to
the
drawings.
1. Selection of DMR technology as liquefaction process.
2. Liquefaction capacity per liquefaction train between 2 to 4 MTPA.
3. Selection of light-weight equipment.
4. A closed loop for water cooling.
5. Limited weight per module.
6. A full process unit in a module.
7. A pipe rack integrated in the module(s).
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8. Installing long lead items outside modules.
9. Minimization of installed spares and valves.
10. Arrangement of equipment to minimize distance and piping.
A first step involves a selection of a liquefaction process. Various
liquefaction
processes are available. A comparison is for instance provided in the article
"Analysis of Process Efficiency for Baseload LNG Production" by T.J. Edwards
et
al. [1984] of Air Products and Chemicals Inc. According to the article, the
C3MR
and DMR have similar thermodynamic efficiencies. Both are more efficient than
the
cascade liquefaction process. According to the article, C3MR "has distinct
advantages over the other process cycles, e.g. by way of simpler control, less
costly
and more reliable equipment, and ease of startup." Consequently, the most
commonly used liquefaction process for existing plants is the C3MR process.
Relatively small LNG plants can use SMR (a process using a single mixed
refrigerant cycle) or a nitrogen (N2) cooling cycle as liquefaction
technology, but
these technologies provide relatively poor liquefaction efficiency and
increased
specific green-house gas (GHG) emissions.
Despite the general preference in the industry for the C3MR process, Applicant
has found that the DMR process provides certain benefits in combination with
the
modular setup. For instance, the Dual Mixed Refrigerant (DMR) process has a
lower
equipment count than C3MR and optimized cascade. Also, DMR enables to use
lighter equipment.
The pre-cool cycle of the DMR process can be based on single stage (single
heat exchanger) or dual stage (two heat exchangers), as explained below.
Figures 1
and 2 show embodiments of a liquefaction process suitable for the system of
the
disclosure.
Figure 1 shows a DMR process with a dual stage precool loop. Dual stage
herein refers to two or more separate heat exchangers in the precool cycle,
each
consecutive heat exchanger operating at a lower internal pressure than the
previous
heat exchanger. Fig. 1 schematically depicts a system 1 and associated method
for
liquefying a gas 2, such as natural gas. Please note that various
modifications to the
scheme of Figure 1 are conceivable. For instance, the gas 2 in its associated
conduit
may have been pre-treated. Several types of gas treatment can precede the
scheme of
Fig. 1. Various other types of equipment can be added downstream of the system
to
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further process the at least partly condensed or fully liquefied gas 30
provided by the
system of Fig. 1. Such equipment may include a nitrogen removal section or
addition
of an end-flash section. Also, there may be differences between respective
liquefaction systems, for instance with respect to thermodynamics, pressure
ranges,
temperature ranges, and flow rates at various locations in the system during
operation, equipment sizes, maximum capacity, etc.
At a generic level, the liquefaction system 1 comprises two consecutive
cooling
cycles 4 and 6. The pre-cool cycle 4 may comprise at least one, for instance
two heat
exchangers 10 and 12 and at least one pre-cool refrigerant compressor 14. The
cycle
4 may also include at least one cooler 15. Pre-cool refrigerant conduits 16
guide pre-
cool refrigerant from the compressor 14 through the two heat exchangers 10 and
12
and back. Refrigerant conduits 16 may comprise conduits 16a to 16f. Together,
conduits 16 constitute a loop to circulate a refrigerant. The refrigerant
circulated in
loop 4 may be referred to as, for instance, precool refrigerant, precool mixed
refrigerant (PMR) or first refrigerant.
The first pre-cool heat exchanger 10 may operate at a first pressure and the
second pre-cool heat exchanger 12 may operate at a second pressure. Herein,
the first
pressure typically exceeds the second pressure. As a result, the first heat
exchanger
10 may be referred to as high-pressure (HP) pre-cool heat exchanger. The
second
heat exchanger 12 may be referred to as low-pressure (LP) pre-cool heat
exchanger.
The main cooling cycle 6 comprises at least one main heat exchanger 20 and at
least one main refrigerant compressor 22. The cycle 6 may include one of more
coolers 23, 25. Main refrigerant conduits 24 extend from the compressor 22
through
the two heat exchangers 10 and 12, subsequently through the at least one main
heat
exchanger 20, and back to the compressor 22. The cycle 6 may comprise a
separator
26 to split the mixed refrigerant of the main cycle 6 in a heavy mixed
refrigerant 27
and a light mixed refrigerant 28. Refrigerant conduits 24 may comprise
conduits 24a
to 24f. Together, conduits 24 constitute a loop to circulate a refrigerant.
The
refrigerant circulated in loop 6 via conduits 24 may be referred to as, for
instance,
main refrigerant, mixed refrigerant or second refrigerant.
The gaseous feed stream 2 is routed via conduits extending through the two
heat pre-cool exchangers 10 and 12, and subsequently through the at least one
main
heat exchanger 20, to provide at least partially condensed or liquefied gas
30.
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Both the pre-cooling cycle 4 and the main cooling cycle 6 may use a mixed or
multi-component refrigerant to pre-cool and subsequently condense or liquefy
the
gaseous feed stream 2. Expanded pre-cool mixed refrigerant 50, 52 provides
cooling
duty to the pre-cool heat exchangers 10, 12 respectively and to all streams
routed
through the inside of said heat exchangers. Expanded heavy mixed refrigerant
29 and
expanded light mixed refrigerant 31 provide cooling duty to the main cryogenic
heat
exchanger 20 and to all streams routed through the inside of the MCHE 20.
For further details of the cooling cycles and the operation thereof, reference
is
made to, for instance, US6370910 or US6658891.
The system 1 typically also includes a system 40 to remove natural gas
liquids.
The embodiment of system 1 shown in Figure 1 is provided with a liquids
removal
section 40 comprising, for instance, a first separator 140, and a second
separator 142.
First and second separator 140, 142 may be flash vessels. Alternatively, the
first
separator may be a scrub column. Herein, a vertical scrub column for removing
hydrocarbon liquids from natural gas may refers to a piece of equipment having
multiple (for instance more than five, up to about ten) layers of stages with
packing
or trays as internals.
A conduit 150 may connect an outlet of the first pre-cool heat exchanger 10
with an inlet of the first separator 140. A second conduit 152 connects an
upper
outlet 154 of the first separator 140 with an inlet 156 of the second pre-cool
heat
exchanger 12. A third conduit 158 connects an outlet 160 of the second pre-
cool heat
exchanger 12 with an inlet 162 of the second separator 142. A fourth conduit
164
connects an upper outlet 166 of the second separator 142 with an inlet 168 of
the
main heat exchanger 20.
An optional bypass conduit 60 may be provided, connecting the inlet of the
bundle 80 of the first heat exchanger 10 to an outlet of said bundle 80. The
conduit
60 may be provided with a valve 62. The valve 62 may be controllable within a
range
between a closed position and an open position, allowing to adjust a flow of
gas
through the bypass conduit 60. The latter allows at least a section or part of
the gas 2
to bypass the bundle 80 in the heat exchanger 10.
A fifth conduit 170 is connected to a lower outlet 172 of the first separator.
Liquids can be removed from the first separator 140 via the conduit 170. A
sixth
conduit 176 is connected to a lower outlet 178 of the second separator 142.
Liquids
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can be removed from the second separator 142 via the conduit 176. Optionally,
the
liquids from the second separator 142 can be recycled back to the first
separator via
line 173, either by gravity or optionally aided with a pump (not shown).
Liquids may
be removed, bypassing the first separator 140 via line 179. The conduits 173
and/or
179 may be provided with valves 63 and 65 respectively, allowing to control
the flow
in each conduit.
Figure 2A shows a system 101, wherein the pre-cool cycle 4 includes a single
heat exchanger 10 provided with two bundles 80, 82 for guiding and cooling the
natural gas feed stream 2. The first bundle 80 is connected to a second outlet
84 of
the heat exchanger 10 which in turn is connected to conduit 150. The conduit
152 is
connected to a second inlet 86 of the heat exchanger 10 connected to the
second
bundle 82. The conduit 158 may be connected directly to the inlet 168 of the
main
heat exchanger.
The pre-cool cycle 4 may include two or more coolers 15, 17. Thereof, the
cooler 15 may be referred to as precool condenser. The cooler 15 may provide
an at
least partly condensed refrigerant stream 182. The precool cycle 4 may include
a
knock-out vessel or other gas-liquid separator 180. A lower outlet for liquids
184 of
the vessel 180 is connected to the conduit 16d. The outlet 184 provides a
condensed
(liquid) refrigerant stream 186 to the precool heat exchanger 10.
The embodiment of Fig. 2B shows system 111, comprising interstage cooler 17
for cooling precool mixed refrigerant as compressed in a first stage of the
compressor
14 before entering a subsequent stage of said compressor 14. The intercooler
17 of
the precool refrigerant compressor 14 allows to reduce the compressor power.
In a
practical embodiment, the output of the intercooler 17 is a cooled vapor
stream.
Liquids in the output of the intercooler 17 are preferably prevented.
The system 111 may comprise a knock-out drum 300 to ensure only vaporous
precool refrigerant is provided to the precool compressor 14. the compressor
14 may
be provided with a first feedback conduit 302 with valve 304 to loop
refrigerant back
to the inlet of the compressor, via the knock-out drum 300. The cooler 15 of
the
liquefaction system 111 may be a de-superheater. The cooler 15 may be
succeeded
by another cooler 310, referred to as condenser. The cooler 310 may at least
partially
condense the compressed refrigerant. A second feedback conduit 312, provided
with
valve 314, may connect the refrigerant flow between the cooler 15 and the
condenser
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310 with a middle inlet 316 of the compressor 14. An outlet of the condenser
310
may be connected to PMR accumulator 180. A lower outlet 184 of the accumulator
may be connected to a lower inlet 320 of tube bundle 322 for precool
refrigerant in
the heat exchanger 10. An outlet of the tube bundle 322 is connected to an
expansion
device 324, such as a JT valve. An outlet of the expansion device is connected
to
inlet 98. The system 111 may comprise a single heat exchanger 10 included in
the
precool cycle 4.
The gas tube bundle 84 may extend though the entire heat exchanger 10. Exit
84 of the gas tube bundle may be connected to the separator 140. The gas
outlet 154
of the separator 140 may be connected to inlet 168 of the main heat exchanger
20.
In use, the single heat exchanger 10 of Figs. 2A and 2B is set to operate at a
predetermined internal pressure. Precool refrigerant is passed through conduit
16d.
Main refrigerant is passed through conduit 24b. The natural gas 2 is passed
through
the bundles 80 and 82. Cooled precool refrigerant in conduit 16f is expanded.
The
expanded precool refrigerant 98 is diffused into the heat exchanger 10 near
the top of
the heat exchanger 10. The expanded refrigerant cools the conduits 16d, 24b
and 80,
82 inside the heat exchanger 10.
In the embodiment of Fig. 2B, natural gas from the mercury-removal bed may
be pre-cooled using pre-cooled Mixed Refrigerant (PMR) in a Single stage Coil
Wound Heat Exchanger (CWHE). The PMR is compressed in a single stage
compressor 14 with interstage water-cooling in cooler 17. At normal operating
conditions, a minimum of 10 C superheat is maintained at the inlet 316 of the
compressor 2nd stage (outlet of interstage cooler 17) to prevent risk of
condensation
at the PMR circuit. A knock-out drum has been obviated at the outlet of the
interstage cooler 17 in order to reduce capital expenditure. The PMR
compressor 14
with interstage cooling offers an additional advantage, because it offers less
scope at
the target production and reduces specific power and specific GHG emissions.
The embodiments of Figure 2A and 2B are particularly advantageous for a
modular LNG facility. The single heat exchanger 10 in the precool loop 4
limits both
equipment count, equipment weight, and piping. The NGL removal is relatively
simple, requiring only a single separator 140. Separator 140 may be a scrub
column
separator if the feed gas is relatively rich, i.e. comprises relatively a lot
of natural gas
liquids. The liquefaction scheme of Fig. 2B is relatively low on equipment
count.
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These advantages may be better appreciated in the light of the description
herein
below.
In a practical embodiment, the heat exchangers in the precool loop 4 and main
liquefaction loop 6 are based on coil wound heat exchangers (CWHE).
Alternatively,
one or more of the heat exchangers 10, 12, 20 may be replaced with Plate Fin
heat
exchangers (PFHE).
The refrigerant compressors (PMR compressor 22 and MR compressor(s) 14)
can be driven by an efficient aeroderivative gas turbine or alternatively by
an electric
motor. The driver selection, however, does not change the overall layout of
the MML
train.
A particularly beneficial layout for a system 200 according to the present
disclosure is shown in Figures 3, 4 and 5. The system 200 is a liquefaction
train
having a modular setup. The system comprises four modules 210, 220, 230, 240
for
treating and liquefying the feed gas. Modules or sections 250 and 260 comprise
the
respective refrigerant compressors and associated drivers. Figure 4 shows the
system
200 wherein the drivers of the compressors are gas turbines. In Figure 5,
drivers of
the compressors are (variable speed) electrical motors.
An inside battery limit (ISBL) scope 202 of the system 200 comprises a
number of modules. The modules include, for instance, four process modules.
First
module 210 is, for instance, an acid gas removal unit (AGRU). The AGRU
typically
comprises an absorber for flushing the gas with a liquid solvent. For details,
reference is made to, for instance, W02016150827. The absorber 212 may
comprise
a column type absorber placed next to and connected to the first module 210.
Other
process units, such as a unit 214 comprising a solvent drain drum and/or pump,
may
also be arranged next to and connected to the first module. These latter
equipment
components can also be placed inside the respective module.
A second module 220 may comprise a dehydration unit 222 and/or a mercury
removal unit 224. The dehydration unit typically comprises a number of, for
instance
three, molecular sieve units (molsieves) 226. Alternatively, the Mercury
removal unit
(single vessel) may be arranged in the AGRU module 210. For details, see for
instance US20180311609 or US8521310.
Third module 230 may comprise a liquefaction unit. Compressors 14 and 22
for the precool cycle and the main cooling cycle respectively may be
positioned on
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opposite sides of the third module. See Figures 4 and 5. The precool
compressor 14
may be provided with a first waste heat recovery unit 232. The main compressor
22
may be provided with a second waste heat recovery unit 234.
The first precool heat exchanger 10 may be positioned on the same side of the
third module as the pre-cool compressor unit 14. The optional second precool
heat
exchanger 12 may be arranged next to the first precool heat exchanger 10. The
main
heat exchanger 20 may be arranged on the opposite side of the third module,
typically on the same side as the main refrigerant compressor 22.
Substantially all
other equipment relating to the liquefaction system (such as the exemplary
systems
shown in Figures 1 and 2) is included in the third module 230. The precool
heat
exchanger 10, 12 and the main heat exchanger 20 are connected to the
liquefaction
module 230 and the respective compressors 14, 22 via piping (not shown in
Figures
3-5, but indicated in Figures 1-2).
As shown in Fig. 4, the first and second compressor 14, 22 may be connected
to a motor. The motor may be a gas turbine 232, 234.
As shown in Fig. 5A, the first and second compressor 14, 22 may be connected
to respective first and second electric motors 260, 262. The electric motors
may,
respectively, be connected to a first and second variable speed drive unit
(VSD) 264,
266. The variable speed drive units 264, 266 may be connected to respective
first and
second harmonic filters 268, 270. Each electric motor unit may be provided
with a
dedicated first and second transformer unit 272, 274 respectively.
A fourth module 240 may comprise equipment for condensate stabilization,
heat transfer fluid (HTF) and at least one closed cooling water unit
(explained in
more detail below). Condensate stabilization herein refers to equipment for
processing NGLs removed from the feed gas. Some of the NGLs may for instance
in
part be used as refrigerant make-up. In part the NGLs may be prepared for sale
as
product.
Additional equipment shown in Figures 3, 4 and 5A includes, for instance,
transformers 250 for control of electricity provided to the system 200. An
incinerator
252 may be provided to consume remaining hydrocarbons in the CO2 rich gas from
the AGRU regenerator column. The latter includes, for instance, overflow of
hydrocarbons in case of equipment failure or flash gas.
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The modules 210, 220 and 240 may be arranged adjacent to one another, the
respective sides of one module engaging the side of the respective adjacent
module.
The liquefaction module or third module 230 with the respective compressors
14, 22
on opposite sides may be arranged longitudinally aligned with the modules 210,
220,
240. In a preferred embodiment, the conduits and the pipe rack 280 extend
through
the modules 210, 220, 230 and 240. The integrated pipe rack is included in the
module weights (as referenced herein, for instance herein below).
The system 200 may comprise a pipe rack 280. The pipe rack supports and
guides pipes or conduits 282, for instance for feeding and removing process
streams
to and from the respective modules 210 to 240.
In a practical embodiment, the pipe rack guides the pipes 282 to one of the
modules, for instance to the fourth module 240, and extends through the inside
of
said module. The pipe rack 280 and the associated conduits 282 may extend
through
the inside of the modules, for instance through the modules 240, 220 and 210
respectively. See for instance Figure 3, which shows conduits 282 extending
into the
fourth module 240.
The module 230 may be arranged adjacent to the modules 240, 220 and 210.
The latter modules together form a first series of interconnected modules. The
third
module, with the first compressor 14 and the second compressor 22 on opposite
sides, may form a second series. The compressors may be modularized.
Alternatively, the compressors 14 and 22 may be 'stick-built' (i.e. arranged
and
provided with cabling and piping onsite). Conduits for respective process
streams
may extend from the first series of modules to the third module 230 of the
second
series. Also, the heat exchangers 10, 12 and 20, which typically are coil
wound heat
exchangers, may be included in a dedicated module. Alternatively, these heat
exchangers may be stick built.
Traditionally, LNG trains have a dedicated pipe-rack extending on the side and
along the length of the LNG train and its equipment. The latter generally
holds for
both stick-built and modular built LNG trains. All individual process units
are
typically connected to the pipe rack. The system 200 applies an integrated
pipe rack
280 which runs through at least two or the modules, preferably through at
least three
modules. This will enable the majority of the hookups between process units
and
piperack to be completed in the fabrication yard (i.e. remotely) and reduces
the
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number of hookups required at the production location which in turn reduces
the
number of construction hours at the production site.
Figure 5B shows a practical embodiment of a water cycle 360 for cooling
water. The cooling water is supplied and routed through the system 200 via
associated conduits. At least part of the water conduits is arranged on the
pipe rack
280. The number of hook ups 362 for cooling water required on site between
parts of
the conduits pre-arranged in the modules and other conduits is relatively
limited. Pre-
arranged herein means conduits included in the respective modules. Other
conduits
herein may refer to conduits in another module or conduits external to the
respective
module. In the example of Fig. 5B, the number of hook-ups or interconnections
362
is limited to about five to seven. For comparison, a comparable modular
facility
having a pipe rack extending along the side of the modules would at least
require 18
hookups.
Figure 5C shows a practical embodiment of a gas cycle 370 for feed gas up to
the rundown of LNG. Along the cycle, the gas is supplied and routed through
the
system 200 via associated conduits. At least part of the gas conduits is
arranged on
the pipe rack 280. The number of hook ups 372 for feed gas required on site
between
parts of the conduits pre-arranged in the modules and other conduits is
relatively
limited. In the example of Fig. 5C, the number of hook-ups or interconnections
372
is limited to about 10 to 11. For comparison, a comparable modular facility
having a
pipe rack extending along the side of the modules would at least require 16
hookups.
Similar reductions of required hook ups are achieved for other process
streams.
The latter may include, for instance, a cycle for so-called heat transfer
fluid, for
which the number of interconnections on site between the modules and other
conduits is limited from about 13 to less than seven. Thus, the layout and
composition of the system of the present disclosure reduced hookups and
consequently the time required onsite to connect respective prefabricated
modules
and construct the system 200.
Each module comprises one or more full process units. In other words, all
equipment associated with a respective process unit is only comprised in one
of the
modules, with caveat that selected equipment may be arranged on the side of,
i.e.
outside, the respective module (see, for instance, Figures 3-5). For instance,
the Acid
Gas Removal Unit (AGRU) is in a single module 210, the Dehydration Unit (DHU)
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and Hg removal bed may be a single module 220, the Liquefaction unit
(including
precool cycle 4 and main cooling cycle 6) is in a single module 230. And the
condensate stabilization unit (or fractionation unit) is in a single unit 240,
potentially
combined with some utilities (such as closed cooling water expansion vessel
and
associated pumps, and Heat Transfer fluid expansion vessel and associated
pumps).
This minimizes interconnections and hookups between respective modules, which
in
turn minimizes site work at the construction site to construct the facility.
It also
enables maximum pre-commissioning and commissioning at the fabrication yard
again with the objective to minimize the hours at site. The latter may
basically
include preparing all equipment and instrumentation for the operations phase.
Commissioning means making systems ready for production of LNG.
As an alternative to the layout shown in Figures 3 to 5A, it is for instance
possible to combine two modules into one. For instance, the AGRU module 210
and
the dehydration unit 220 may be combined in a larger single module (not
shown).
This will further reduce the number of hookups on site. The weight of the
single
module however will exceed the weight of each module 210, 220 individually.
Base
case is that a single process unit is included in one module and is not split
over two
or more modules.
In a practical embodiment, predetermined equipment is arranged outside the
modules. For instance, long lead items will be arranged outside modules. Long-
lead
herein refers to items which take relatively long to construct and/or to get
delivered.
For instance, the main liquefaction heat exchangers 10, 12, 20 and the carbon-
dioxide (CO2) absorber column 212 are typically the heaviest pieces of process
equipment and are arranged outside the respective process modules to maintain
the
optimum module weight. In addition, the main liquefaction heat exchangers 10,
20
and CO2 absorber column 212 are long lead items that would determine the
critical
path of the process modules, so installing them separately reduces the module
delivery schedule.
In a practical embodiment, the liquefaction capacity per train or system 200
is
between 2 to 4 MTPA. Although larger train sizes do have the advantage of a
relatively low equipment count for a given capacity, larger trains typically
suffer
from very large and heavy equipment with associated large diameter pipes. The
combination increases the footprint, equipment weight and module weight (per
unit
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of capacity in MTPA). By selecting a smaller train size, the equipment density
in the
module can be increased significantly. Relatively low capacity liquefaction
trains
have the benefit of small equipment and associated small diameter pipes.
Relatively
low capacity liquefaction trains typically have as a disadvantage an increased
number
of equipment, instrumentation, valves and other bulks for a given capacity,
which
tend to increase the capital expenditure. It also becomes impractical to
operate so
many trains for a given capacity. Bulks herein may relate to all kinds of
smaller
pieces of equipment, such as relief valves, drain systems, etc. required for
safe
operation of the LNG train. Models have indicated that modular built LNG
trains
having a capacity in the range of 2 to 4 MTPA have the lowest capital
expenditure
for the same total capacity of all trains combined.
As an example, Fig. 6 indicates results of modelling of the total equipment
weight depending on the capacity of size of each respective train. Total
equipment
weight herein refers to the weight of all equipment combined for all
liquefaction
trains (i.e. within battery limit) for a certain total capacity. Line 400
indicates
modelled results for the system of the present disclosure. Line 402 herein is
a
reference, relating to a state-of-the-art liquefaction project. Both lines 400
and 402
relate to a total capacity of all trains combined of 14 mtpa.
The figure shows the total equipment weight required for a 14 MTPA facility
as a function of the liquefaction train size. Two effects are apparent: 1)
smaller trains
(and hence more trains) do reduce the overall equipment weight, contrary what
is
normally assumed in industry, and 2) For an equal train size, total equipment
weight
for a facility according to the disclosure is significantly smaller than the
total
equipment weight of the reference modular LNG plant.
By applying a mid-scale concept rather than a large-scale concept, the total
equipment weight per MTPA will decrease. This weight reduction is for instance
driven by pressure vessels (and equipment that can be considered as such) as
they
represent the highest weight fraction of total installed weight and provide
the highest
weight reduction when downscaling. Overall, by constructing two trains each
having
half the capacity of a single larger train, the weight of equipment in all
modules
combined can be reduced. As an example, the selection of four smaller modules
of
3.5 mtpa each provides a reduction of the total equipment weight of about 27%
with
respect to two trains having a 7 mtpa capacity each. Combining smaller trains
with
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substantially all other measures as disclosed herein provides a further
reduction in
equipment weight in the order of 73%. A strong impact on the latter weight
reduction
is due to selection of light weight equipment, such as PCHEs, see for instance
Figure
7 and the related description below.
In an embodiment, the system 200 of the disclosure uses water for cooling a
process stream rather than air. Cooling process stream herein relates to, for
instance,
coolers 15, 17, 23, and 25 (see Fig. 2). Conventionally, LNG liquefaction
facilities
have generally been based on air cooling. In other words, coolers 17, 23 and
15, 25
have typically been implemented using air coolers (fans), which are typically
relatively large and heavy. The system 200 of the present disclosure applies
water
cooling. Cooling using water as a coolant enables relatively compact and light
heat
transfer equipment and increases the process efficiency. Improved process
efficiency
in turn reduces overall green-house gas emissions for a given LNG capacity.
In a practical embodiment one or more of the coolers 15, 17, 23, 25 (Fig. 2)
are
so-called printed circuit heat exchangers (PCHE). In a preferred embodiment,
all
coolers 15, 17, 23, 25 (Fig. 2) are so-called printed circuit heat exchangers
(PCHE).
Conventional LNG facilities, especially facilities located on-shore, typically
use air
coolers. In conventional water-cooled on-shore LNG facilities, shell-and-tube
heat
exchangers would be selected as water coolers in view of significantly lower
capital
expenditure for equipment for the same capacity. However, Applicant has found
that
printed circuit heat exchangers provide significant benefits to the modular
concept of
system 200. As shown in Figure 7, an exemplary printed circuit heat exchanger
420
can be up to 85% smaller and lighter than a shell-and-tube heat exchanger
having the
same cooling capacity. Printed Circuit Heat Exchangers may be sourced from,
for
instance, companies such as Heatric (a division of Meggitt (UK) Limited) and
Alfa
Laval Corporate AB (Sweden). Yet, Applicant has found that the selection of
PCHEs
in the modular concept of system 200 provides additional benefits above and
beyond
the size of the heat exchangers itself. As described in more detail below, in
combination with some or all of the features of embodiments described herein,
these
additional benefits make up for the additional capital expenditure for PCHEs.
As a
result, capital costs for the entire system 200 are significantly reduced with
respect to
conventional liquefaction systems, including modular systems.
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Figure 8 herein indicates a relation between a number of parameters for a
selected module i (i being an integer ranging from 1 up to the total number of
modules in a facility):
- Mechanical weight or mass Mm i [in kg]: Combined weight of
all
equipment in a respective module i, excluding structural steel and
conduits (430).
- Mechanical density Dm i [in kg/m3]: Density of all
equipment within the
volume Vi of module i.
- Module volume Vi = Mmi/Dmi (432) [in m3]: Total volume of
module i.
- Structural density Ds i [in kg/m3]: Density of all items to provide
structural support included in module i(such as columns, beams, steel
structures, basically a structural frame).
- Structural weight or mass Ms i (434) = V1 * Ds: Weight of
all items to
provide structural support to module i.
- Piping density Dpi [in kg/m3] (436): Density of pipes and conduits in
module i, for instance for connecting the equipment in the module to
respective process streams.
- Piping weight Mpi [kg] = Vi * Dpi: weight of all pipes and
conduits in
module i.
- Electrical and Instrumentation density De i [in kg/m3]: Density of
electrical equipment (such as cables, transformers) and instrumentation
(such as temperature sensors, pressure sensors, flow meters and control
valves) in module i.
- Electrical and Instrumentation weight Me i (438) = Vi *
De,: Weight of
electrical and instrumentation equipment in module i.
- Mmodi / Mm i = 1 + (Dsi + Dpi+ Dei) / Dm: Weight of module
i
divided by the mechanical weight in module i. I.e. the ratio between
module weight and mechanical weight for module i.
Based on the above, applicant found a number of interlinking effects which
reinforce each other. The embodiments as disclosed herein use these
interlinlcing
effects to provide optimal results for a modular setup. For instance, by
reducing the
weight of individual pieces of equipment (Mm), the corresponding weight of
required piping (MO, structural (Ms) and electrical & instrumentation weight
(Met)
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is also reduced. See Fig. 8. At constant densities, these weight reductions
will
inherently lead to a decrease of respective module volume V. The volume of
respective modules (Vi) can decrease even further, due to the use of smaller
(more
compact) equipment. Viz, with Vi=Mmi/Dmi, with smaller equipment the
mechanical
weight decreases while the mechanical density of equipment in a module
increases,
leading to a smaller volume per module. Together, the lower volume and
increased
compactness (Dm) provide a mutually reinforcing effect decreasing the weight
of
piping, structural steel and Electrical and Instrumentation (E&I) for a
respective
module. See for instance 436.
Optionally, the printed circuit heat exchangers included in the system 200 of
the disclosure may be provided according to the setup and used according to
the
method as disclosed in US20200182552. This embodiment provides a further
reduction in weight and size of the heat exchangers. Consequently, also the
piping
density and weight is reduced even more. Said further reduction in size and/or
weight
may be in the order of 20 to 45% (compared to state-of-the-art printed circuit
heat
exchangers), depending on specifics. As explained with respect to Fig. 8,
weight
reduction provides significant benefits, including cost reduction, well
exceeding the
extra costs of selecting printed circuit heat exchangers for at least some but
preferably all of the coolers included in the system 200. Said coolers may
include at
least all coolers as included in the precool refrigerant cycle 4 and/or the
main
refrigerant cycle 6.
The selection of relatively light equipment, in particular the application of
Printed Circuit Heat Exchangers (PCHE) for water cooling instead of the
conventional shell-and-tube heat exchangers significantly reduces the size and
weight of heat transfer equipment in the LNG train, and the volume and weight
of
associated conduits. In the system 200 of the disclosure, a majority of the
heat
exchangers for cooling a process stream with respect to a temperature of the
environment (also referred to as ambient temperature, or ambient) are based on
PCHEs. Said temperature of the environment is typically transferred via a
medium
such as air or water. The phrase majority herein does allow to include a few
aircoolers as well. A few herein indicates that the number of air coolers is
significantly less than the number of water coolers, for instance about 10% of
the
total at most, or preferably about 5% at most (in number and/or in cooling
capacity).
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Figure 9 indicates examples of the dependence of module weight to equipment
weight ratio (on the vertical axis) with respect to equipment weight only (on
the
horizontal axis) for respective modules individually. Module weight herein
includes
the total weight of a module, including both equipment and structural
components
(such as a steel support frame). Mechanical equipment weight herein is the
same as
just equipment weight, both referring to the equipment weight of all equipment
combined in a respective module.
Fig. 9 indicates a ratio of module weight to equipment weight in the module
and the relation thereof to just the module weight. Herein, module weight is
the total
weight of a respective module. Equipment weight is the total weight of all
equipment
in the respective module, without constructional elements (elements which are
for
support). Mechanical equipment weight is the same as equipment weight.
The plot of Figure 9 includes entries 450 for modules of the system of the
present disclosure, entries 452 for respective modules of a number of
reference
projects, and entries 454 for process modules of a floating LNG project. Line
of best
fit 460 is fitted to the entries 450, 454. Line 462 is fitted to the entries
452.
Fig. 8 and the related description above indicated a formula for the ratio
between total module weight - including all structural and support structures -
and
the total weight of only the equipment in the respective module: Mmodi/Mmi =
1+
[(Dsi+Dpi+Dei)/Dmi]. Fig. 9 shows a graphical example, indicating that the
piping
density and structural density have a negative impact on the ratio (i.e.
increasing the
ratio), while the equipment density reduces the ratio. Using the specific
selection as
described with respect to embodiments disclosed herein, the system 200 of the
present disclosure enables to increase the equipment density significantly,
leading to
more compact modules requiring less space. This has been achieved while
maintaining overall module density substantially the same as historical
projects
warranting similar congestion and therefore similar operational space,
maintenance
space and safety distances between equipment. See for instance the table below
for
an example of the system 200 compared to a state-of-the-art modular reference
project:
Concept Dmod Ds (kg/m3) Dp (kg/m3) Dm De
(kg/m3)
(kg/m3) (kg/m3)
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Reference 201 116 37 30 17
System 216 116 42 45 13
(200)
Difference +7.5% +0.0% +13% +50% -24%
Herein, Module density (Dmod) = Ds (structural density) + Dp (piping density)
+ Dm (mechanical density) + De (density of 'e8d, i.e. electrical and
instrumentation;
this relates to electrical cables and equipment such as controllers and
transformers).
The required module volume is determined by, for instance, the equipment
types, equipment count, equipment size and equipment spacing, amount of piping
and number of mini FARs and substations. Maximization of high-density
equipment
like PCHEs plays a relatively big role. The weight of PCHEs is significantly
lower
than the weight of shell-and-tube heat exchangers which are used
conventionally.
The weight may be about a factor 5 lower. Also, the volume of PCHEs is smaller
(more than a factor five), resulting in increased equipment density. There is
also an
impact on piping due to reduction of parallel configurations.
As can be seen in the table above, the structural density and piping density
are
fairly constant, implying structural weight and piping weight scale
proportionally
with module volume. This seems reasonable as bigger modules require more steel
for
support structures, such as beams and columns, to support its own weight.
Similarly,
bigger modules will have equipment arranged spaced apart more, leading to an
increase in piping weight.
The graph of Figure 9 with two lines 460, 462 shows two effects:
a) For modules with lower equipment weight, the slope of both curves starts to
increase. This indicates that the impact of equipment weight on total module
weight
decreases. For lower equipment weight, total module weight is determined more
by
piping, structural weight and other disciplines (for instance, mechanical
density
decreases).
b) As shown in Figure 9, the system 200 of the disclosure has a significantly
lower ratio of Mmodi/Mmi than a reference project of a modular built LNG
facility,
indicating that the system 200 has an increased mechanical density.
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Preferably, the maximum weight of each module 210, 220, 230, 240 is limited
to a predetermined maximum threshold. In a practical embodiment, said
threshold,
also referred to as the maximum module weight, is about 5000 or 6000 tonnes.
Line
456 in Fig. 9 provides an estimation of the 5000 tonnes per module upper
threshold.
Larger or heavier modules suffer from a relative increase in construction
steel with
respect to equipment weight. Construction steel refers to the steel and other
components required to provide structural strength to a respective module.
Modules exceeding said threshold will typically increase fabrication time in
the
yard, with more manhours, which will typically increase the overall project
schedule
of the project. See Fig. 10. The maximum 5000 or 6000 metric tonnes of module
weight also simplifies transport, as a relatively large number of vessels or
barges is
available that can transport modules up to said threshold.
Figure 10 shows the time it takes to fabricate a module (vertical axis)
plotted in
dependence of the total weight of the respective module (horizontal axis).
Entries
480, 482, 484, and 486 respectively indicate data points for practical
embodiments of
the modules 210, 220, 230 and 240 of the system 200 of the disclosure. Please
note
that data points close to each other may relate to modules having a different
function,
but the general trend and trend line can be construed. First reference data
entries 490
relate to a first reference project. Second reference data entries 492 relate
to a second
reference project.
The graph of Fig. 10 indicates a correlation, indicated by line 494, between
the
fabrication time for a respective module and the (total) weight of said
module. So, in
practice, modules having a lower overall weight can be constructed faster than
heavier modules. Using the example of Figure 6, it is possible to compare the
production of multiple trains having a smaller capacity per train (e.g. 2
times 3.5
mtpa) with another single liquefaction train having larger modules and the
same
overall capacity (e.g. 7 mtpa). For the construction of four modules (together
being
comprised in a liquefaction train having a 3.5 mtpa capacity), a significant
part of
fabrication of respective modules of the two trains can happen in parallel. As
a result,
the two trains can be fabricated faster than a single larger train having the
same total
capacity. As the fabrication schedule of two full trains according to the
disclosure, as
represented by system 200, will be shorter than a single large state of the
art modular
train having the same capacity. Hence, first LNG production will be earlier.
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Fig. 11 shows a cooling system 500, as included in a preferred embodiment of
the system 200 of the disclosure. Herein, the PCHEs 502, 504, 506 are included
in
respective primary cooling loops 512, 514, 516. PCHEs 502, 504, 506 herein
indicate
a combination of all heat exchangers in the liquefaction train 200 (see, for
instance,
Figures 1, 2A, 2B) which cool with respect to a temperature derived from
ambient.
The heat exchangers are preferably printed circuit heat exchangers. Although
Fig. 11
only shows the PCHEs schematically, the PCHEs in a respective liquefaction
train
can be connected to the primary cooling loop in series or in parallel.
Preferably the
coolers are connected in parallel. Some PCHE heat exchangers in the water loop
502,
504 can be connected in series, whereas said series may be connected in
parallel to
other PCHE heat exchangers or series of PCHE heat exchangers.
The primary cooling loops 512, 514, 516 may cycle a first coolant, for
instance
comprising clean water. Clean herein refers to the absence of impurities in
the water.
The clean water herein may refer to softened water or demineralized water.
Also
included in the clean water may be additives, such as a corrosion inhibitor
and anti-
freeze. Anti-freeze herein may comprise glycol. The water purity of the clean
water
may typically be in accordance with an accepted standard, such as EN 12952-12,
EN
12953-10, VGB-M 407, or VGB-S-010-T-00. Softened water herein refers to water
wherein following a water softening process calcium (Ca), magnesium (Mg), and
certain other metal cations have been removed. Said cations may have been
replaced,
for instance with Na (sodium). In a broader sense, the term demineralized
water may
be understood to also include reverse osmosis permeate. The demineralized
water or
permeate may have an electrical conductivity of for example -_ 30 S/cm.
Alternatively, the clean water may be de-ionized water with an electrical
conductivity of about 0.2 to 20 S/cm, or so-called ultra-pure water with an
electrical
conductivity of 0.055 S/cm at most. The whole purpose of the clean water in
the
closed loop is that the fouling of the PCHEs and that scaling of calcium or
magnesium carbonates in the PCHEs is prevented. The softened water, soft
water, or
demineralized water reduces or eliminates scale build-up in the PCHEs.
The primary cooling loops 512, 514, 516 may each be regarded as a Clean
Closed Cooling water (CCW) loop. As an example, see Fig. 11, water loops 512,
514
are related to two separate liquefaction trains 200. Cooling loop 516 is, as
an
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example, related to heat exchangers 506 not included in a liquefaction train,
but
elsewhere in the liquefaction facility.
The closed water-cooling loops 512, 514, 516 may comprise pumps 520, 522,
526 for pumping water around the respective loop. The respective pumps can
pump
the water towards the PCHEs 502, 504, 506. Each loop may comprise an expansion
vessel 530, 532, 536 for receiving the water output from the heat exchangers
502,
504, 506. Heat exchangers 540, 542, 546 receive the warmed water from the
vessels
530, 532, 536 for cooling thereof. In a practical embodiment, the heat
exchangers
540, 542, 546 are Plate and Frame Heat Exchangers.
The primary cooling loops 512, 514, 516 can in turn be cooled with respect to
a
second coolant of a secondary cooling system 550. The second coolant may be
cycled in a loop, wherein the system 550 can be regarded as a secondary
cooling loop
550. When cycled in a secondary cooling loop, the second coolant may comprise
seawater or water from cooling towers. Alternatively, the second coolant may
be air.
In the latter case, the secondary heat exchangers 540, 542 include air
coolers, and the
secondary cooling system 550 is formed by said air coolers.
The secondary loop 550 may comprise a first header 552 for providing the
second coolant to the respective heat exchangers 540, 542, 546 via associated
conduits 554, 556, 558. Warmed second coolant from the heat exchangers 540,
542,
546 may be collected at a second header 560. From the second header 560, warm
second coolant may be provided to a cooler, such as at least one cooling tower
or
spray tower 570. A first pump 572 can circulate the second coolant in the
secondary
cooling loop 550. A make-up system 580 may typically be provided to provide
additional secondary coolant to top up lost coolant or to add fresh water 582
to
control the composition of the coolant. The makeup system may comprise a
second
pump 584 to pump fresh water 582 from a well or other source to the loop 550,
for
instance to the cooling tower 570.
It is understood that the second coolant can be selected from a group
consisting
of water from a cooling tower system, sea water, air, or a combination
thereof. That
is, cooling tower 570 can be replaced or supplemented with sea water or air.
Fig. 11 also shows ISBL 592 of an LNG production facility which comprises
multiple trains 200 as shown. As shown in Fig. 11, the ISBL units in ISBL 592
comprises primary cooling loops 512, 514, and 516 and the associated equipment
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shown. While not shown, it is understood that ISBL 592 further comprises the
ISBL
equipment from each train 200, such as the ISBL units illustrated as part of
ISBL
202, such as those shown in Figs. 4 and 5A, and consecutive cooling cycles 4
and 6
and the associated equipment, such as those shown in Figs. 1 and 2A. When a
particular train 200 is operating and producing liquefied natural gas, the
modules
produce at least one process stream 596, 598, 600 that can be cooled further
against
an ambient temperature. For instance, the first and second mixed refrigerants
from
the cooling cycles that are connected to the liquefaction module can also be
cooled
against an ambient temperature. As described, train 200 comprises a primary
cooling
loop 512, 514, 516 to cool at least a process stream 596, 598, 600 from each
module
210, and the first mixed refrigerant and the second mixed refrigerant against
a first
coolant comprising clean water, preferably consisting essentially of clean
water. The
primary cooling loop 512, 514, 516 is a closed clean water cooling loop and
the
cooling is against an ambient temperature. Train 200 comprises a first
plurality of
heat exchangers through which the primary cooling loop 512, 514, 516 extends.
The
cooling by the primary cooling loop 512, 514, 516 is via heat exchange in at
least the
first plurality of heat exchangers with respect to the first coolant. More
than 50% of
the first plurality of heat exchangers are printed circuit heat exchangers
502, 504, 506
which are are adapted to provide at least 80% of the cooling against the
ambient
temperature. The remaining less than 20% of the cooling duty against ambient
temperature can be done using other types of heat exchangers such as ACHEs.
For the sake of simplicity, Fig. 11 shows streams 596, 598, and 600 for each
respective train 200 for illustrative purposes of the applicable process
streams from
the modules and the first and second mixed refrigerants of the particular
train 200, as
well as any other process streams desirable to be cooled against an ambient
temperature via primary cooling loop 512, 514, or 516, respectively. Streams
596,
598, and 600 extend through PCHEs 502, 504, and 506, respectively, which
represent the more than 50% of the first plurality of heat exchangers through
which
the primary loop of a particular train 200 extends to provide cooling against
an
ambient temperature. The less than 50% of the first plurality of heat
exchangers
through which the primary loop extends can be other types of heat exchangers,
such
as ACHEs.
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It is understood that for the sake of simplicity, Fig. 11 depicts only one
PCHE
502, 504, or 506 for a particular train 200, but that train can have any
suitable
number of PCHEs according to aspects of the facility and systems described
herein.
That is, train 200 can comprise 10 heat exchangers to cool against ambient, at
least
six of which would be PCHEs through which the primary cooling loop of train
200
(e.g., 512, 514, or 516) extends, and the at least six PCHEs provide at least
80% of
cooling duty with respect to an ambient temperature for that train 200. Other
trains
200 can have different numbers of heat exchangers for cooling against an
ambient
temperature consistent with the features described herein, depending on the
particular
design and/or specification as known to one of ordinary skills.
FIG. 11 shows a preferred embodiment where the cooling against an ambient
temperature by the primary cooling loop 512, 514, or 516 is via secondary loop
550
where the thermal energy from ISBL 592 from the process streams and first and
second mixed refrigerants of a respective train 200 is carried by the first
coolant is
transferred to secondary loop 550 in OSBL 594 and dissipated in OSBL 594. The
thermal energy transfer from the primary cooling loop 512, 514, 516 to
secondary
loop 550 is via heat exchange against the second coolant in a second plurality
of heat
exchangers 540, 542, or 546 through which secondary cooling loop 550 extends.
Secondary cooling loop 550 comprises a suitable cooler to cool the second
coolant against ambient temperature. For example, the cooler can be cooling
tower
570 as depicted and described herein. While not shown, it is understood that
cooling against an ambient temperature by the primary cooling loop 512, 514,
516
can be done without secondary cooling loop 550, such as by routing the first
coolant
through ACHEs that are located in the OSBL 594.
As provided, the embodiment depicted in Fig. 11 enables the moving of at least
80% of thermal energy from ISBL 592 to the OSBL 594 for dissipation against
the
ambient temperature in OSBL 594. This is in contrast with other types of heat
exchangers, such as ACHEs, particularly ACHEs that are placed on top of ISBL
units. Unlike train 200 described herein, a train with banks of ACHEs to
provide the
majority of cooling duty against an ambient temperature dissipates the thermal
energy removed by the banks of ACHEs to the environment or ambient in the ISBL
rather than in the OSBL, such as OSBL 594, as described herein
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By enabling dissipation of thermal energy in OSBL 594 in certain
embodiments, the present disclosure to allows for a design of compact ISBL
modules
that are not limited by the size of the ACHE banks. Also, when heat
dissipation
occurs in the OSBL, there is flexibility around the mechanism through which
that
dissipation is achieved, such as through sea water, cooling towers, or air,
without
impacting the designs or configurations of the ISBL units, thereby allowing
for train
designs or aspects of train designs to be replicated from facility to
facility.
Minimization of installed spares and valves. Traditional practice includes
installing spared equipment such as pumps and their associated piping, valves
and
instrumentation in the respective modules. In other words, conventional
modules
used to comprise spare second versions of selected pieces of equipment, ready
to be
connected and used when a first version of said equipment failed. In the
concept of
the present disclosure, (some or all) equipment spares have been warehoused
instead
of installing them. These pieces of equipment are designed as 'Plug and Play'
for
easy removal and re-installation during a period of maintenance, also referred
to as
turnaround. Also, installation of bypass valves has been rationalized to
significantly
reduce the number of valves in a process unit. This approach enables the
compactness of each module in the system 200 and further reduces the module
weight for each respective module. For specifics and details, reference is
made to, for
instance, the disclosure of W02019110770.
In the system of the disclosure, arrangement of equipment has been optimized.
Optimizing the arrangement of equipment in the process modules 210-240 herein
implies, for instance, that distance and piping requirement between respective
pieces
of equipment has been minimized. This in turn reduces the piping weight and
module
weight for each module 210 to 240. Reference is made to Figure 8.
Optionally, an additional and significant weight reduction for a respective
module can be achieved by applying, for instance:
1. Single stage PMR instead of two-stage PMR. 'Single stage DMR' herein refers
to a DMR liquefaction process with a single heat exchanger in the precool
cycle 4 (as shown in, for instance, Fig. 2). 'Two-stage PMR' herein refers to
a
DMR liquefaction process comprising two consecutive heat exchangers in the
precool cycle 4, each operation at a different internal pressure (as shown,
for
instance, in Fig. 1). Application of the single stage PMR process provides the
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potential to obviate a relatively heavy HP PMR suction drum (not shown),
while adding a relatively light interstage cooler 17.
2. Obviating a PMR sub-cooler (relatively low impact on overall efficiency).
3. Obviating an HMR expander (i.e. no active expander at position 29 in Fig. 1-
2;
has relatively low impact on overall efficiency; can be replaced with
expansion valve or JT valve)
4. Obviating an intercooling system on the AGRU absorber (and associated
equipment). See, for instance, W02016150827 for an intercooler on the
AGRU absorber.
5. Use of PCHE's with Closed cooling water system instead of shell-and-tube
heat exchangers with open loop cooling water system (see Figure 8).
6. Run or maintain philosophy (as described in W02019/110770), with less
installed spares as a result, for instance:
a. Series compressor configuration instead of parallel;
b. No sparing of AGRU Charge pump;
c. No sparing of AGRU Booster pump;
d. No sparing of HTF pump;
e. No sparing of Closed Cooling water pumps; and
f. Single Stabilizer overhead compressor (and associated equipment).
The following examples are provided to facilitate a better understanding of
the
leap forward provided by the system according to the present disclosure. In no
way
should these examples be construed to limit, or define, the scope of the
invention.
Figures 12A to 12C provide plan views of exemplary liquefaction systems 200
to scale and for the same total capacity, to allow a comparison of footprint.
The
capacity is, for instance, about 7 mtpa for each of the facilities shown in
Figures 12A,
12B and 12C.
Herein, Figure 12A shows two liquefaction systems 600 using state of the art
C3MR liquefaction technology. Systems 600 have a width W1 and a length Ll.
Total
width of the two systems 600 is W2 = 2*Wl.
Fig. 12B shows a liquefaction system 650 using state of the art DMR
liquefaction technology. System 650 has a width W3 and a length L2. Total area
covered by the system 650 is about 60% of the area covered by the two systems
600
in Fig. 12A.
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Fig. 12C shows two liquefaction systems 200 according to the present
disclosure. Systems 200 have a width W4 smaller that the width W3 of the
system
650. Systems 200 have a length L3. Herein, L2 equals about 2*L3. Total area
covered by the system 200 is about 40% of the area covered by the two systems
600
in Fig. 12A.
Figure 13 shows facility 670 for the production of liquefied natural gas,
comprising a number of liquefaction trains. The facility 670 comprises, for
instance,
two modular liquefaction trains 650 (see Figure 12B). The facility 670 may
comprise
four liquefaction systems 200 according to the present disclosure (see, for
instance,
Figure 12C). Figure 13 allows a side by side comparison of systems 200 and
650,
allowing to put the saving in area (footprint) as mentioned with respect to
Figures
12A to 12C into perspective. For the same area available for two reference
systems
650 side by side, having a total width of 2 times W3, the system 200 of the
present
disclosure allows to arrange four systems 200 in a matrix. The latter would
still leave
additional space to place two additional systems 200 on the same area required
for
two state-of-the-art liquefaction trains 650. In other words, a facility
comprising one
or more liquefaction trains 200 in accordance with the present disclosure
allows to
increase the LNG production capacity per area with about 50%.
In an exemplary embodiment, system 200 compares favorably with respect to
state-of-the-art modular facilities. Exemplary parameters are indicated in the
table
below.
GT Drive E- drive
Unit Reference (Fig. 4) (Fig.
5A) A
Nr. of LNG trains 2 4 4
LNG Production MTPA 14 14.4 15.6 3 to
11%
Plot requirement for all -35 to -
liquefaction trains M2/MTPA 12*103 7.7*103 7.1*103
41%
Nr. of equipment for all
liquefaction trains total nr. 250 440 412 43%
Total equipment weight for
all liquefaction trains tons (103 kg) 21*103 13*103
12*103 -39%
Largest Module Weight tons 11000 5000 5000 -55%
Total ISBL Weight of
Modules tons 162* 103 68* 103 62* 103 -
58%
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Largest Module fabrication
time months 24 18 18 -
25%
Total site hours
(ISBL+OSBL) Million hrs. 18 13.3 13.4 -
26%
Total Yard hours Million hrs. 34 28 26.3 > -
18%
With respect to the information included in the table above: System 200 with
electric drivers for the compressors produces somewhat more per year due to
higher
availability and because electric drives power output is less dependent on the
ambient
temperature compared to gas turbine drives. The greenhouse gas (GHG)
generation
excludes GHG production of power generation. Overall, despite the smaller
modules,
a facility comprising a number of systems 200 according to the disclosure
still
requires fewer modules overall, with each process unit in one module, and
fewer site
hook-ups. Due to four smaller modular trains, the facility comprising four
systems
200 includes more pieces of equipment in total, but each piece of equipment is
smaller and lighter. And lighter modules reduce transportation costs. Also,
heavier
modules take longer to fabricate. The total number of fabrication yard hours
to
construct the modules reduces with almost 20%. The remaining expensive
construction hours at the production site reduce with about 26%. The reduction
in
number of hours to construct both in the yard and on site is due to, for
instance, the
lower weight for each module weights and fewer site hookups, representing a
significant cost saving.
As indicated in the table above, the number of pieces of equipment for all
liquefaction trains combined increases with respect to a reference system.
Also, the
costs of certain individual pieces of equipment may be more expensive. For
instance,
Printed Circuit Heat Exchangers are more expensive than traditional Shell and
Tube
heat exchangers. However, equipment costs are only about 10% of the total
installed
costs. Thus, even though the costs to buy heat exchangers increases (for
instance due
to application of PCHEs), that contribution to the total installed costs is
relatively
low, substantially negligible. Consequently, the total procurement costs, i.e.
the costs
to obtain equipment, piping and bulk material (such as valves, etc.) is
approximately
the same for the system of the present disclosure and several reference
projects as
referred to herein. The total procurement costs represent approximately 20% of
the
total installed costs of a modular built LNG project. However, the total
installed costs
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of the liquefaction systems according to the present disclosure is about 15 to
20%
lower than the total costs to construct a conventional facility including
relatively
large modular LNG trains. Installed costs herein refer to capital expenditure
to build
the facility, including all liquefaction trains.
Figure 14 provides another comparison of plot space or footprint between a
side-by-side arrangement of two systems 200 according to the invention, with a
series of common utility units 750 arranged between the two systems 200. The
utility
units may include, for instance, an MLA unit 760 (Marine Loading Arms, i.e.
arms
for offloading cargo to a vessel), a fractionation unit 770, and a power
generation
unit 780. The setup may have a width W5 and a length L5. The setup of two
systems
200 is compared with an exemplary state of the art and modular built
liquefaction
facility 700 having the same LNG production capacity.
As graphically shown in Figures 12 to 14, the system 200 of the present
disclosure provides a significant reduction in plot space or footprint with
respect to
conventional facilities. Footprint reduction with respect to a stick-built
facility may
be in the order of 50 to 60%. Footprint reduction with respect to a state-of-
the-art
modular built facility may be in the order of 30 to 40%.
Another graphical representation of the significant reduction in footprint is
provided in Figure 15. Herein, the ISBL area of the system 200 is indicated
per unit
of capacity (typically in mtpa) and compared to a range of conventional
liquefaction
facilities. Said facilities include both modular built facilities and stick-
built facilities.
The system 200 of the disclosure can require down to about 30% the area per
mtpa of
a conventional liquefaction facility (area herein is the inside battery limit
area).
As indicated before, see for instance Figures 9 to 15, the system 200 of the
disclosure provides significant advantages with respect to weight reduction
and
footprint reduction. With respect to other measures, the system 200 of the
disclosure
compared favorably with conventional liquefaction facilities also. See below.
As exemplified in Figure 16, a practical embodiment of the system 200 of the
disclosure has a significantly lower green-house gas intensity than virtually
any other
conventional liquefaction facility. Greenhouse gas intensity herein is
calculated
excluding (bar 800) and including (bar 802) the total electrical power
requirements,
for instance generated by a typical combined cycle powerplant.
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Figure 17 indicates the equipment count per unit of production (typically in
mtpa) compared to conventional facilities. Although the capacity for each
train of
system 200 individually is typically smaller compared to some traditional
large (base
load) liquefaction trains, the number of pieces of equipment per mtpa still
benchmarks top quartile.
Figure 18 indicates the module weight per unit of production compared to
traditional modular built LNG trains. Module weight is a key indicator for
total
installed costs and the figure shows that the system 200 of the present
disclosure
benchmarks "best in class".
The system of the present disclosure provides significant cost savings, as it
deals with substantially all aspects linked to capital expenditure of modular
built
facilities. For off-shore LNG plants and offshore gas production systems,
modular
built used to be the norm, as offshore used to have a strong focus on
available plot
space and weight reduction. For instance, water cooling has been used for
cooling in
offshore LNG production. The system of the present disclosure recognizes that
despite abundant plot space and availability of air for cooling, for onshore
modular
LNG facilities implementing water cooling in combination with relatively light
and
small equipment, such as printed circuit heat exchangers, provides significant
cost
savings. The system and method of the current disclosure combine features and
layout, and modular construction, to achieve optimal benefit and reduction of
capital
expenditure above and beyond state-of-the-art modular construction for onshore
facilities.
The design of the system 200 of the present disclosure is agnostic for
compressors drive. The driver of the precool compressor 14 and main compressor
22
may be for instance a gas turbine or an electric motor. The site layout and
arrangement of modules remains substantially the same.
Summarizing the above, over the last 10-15 years, the LNG industry has seen a
shift from traditional stick-built LNG export projects towards modular-built
projects.
The main driver behind this trend is to move construction work offsite to a
fabrication yard where the modular process units are built in a more
controlled
environment benefiting from higher productivity, lower labor rates, better
quality,
fewer safety incidents and ¨ as a result ¨ more competitive, repeatable and
predictable cost and schedule outcomes. If not applied as a design philosophy
from
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the start, modular construction may however be disadvantaged by complex and
expensive logistics, less efficient operations and maintenance and
underutilization of
local content opportunities.
Applicant's Modular LNG concept as disclosed herein combines and integrates
various technologies, thus addressing not just one or two, but substantially
all levers
impacting the capital expenditure to fabricate and build a facility comprising
modular
built LNG trains. As a result, the facility of the disclosure allows to
significantly
reduce the costs of a facility including modular built LNG trains for a
comparable
total capacity. The facility according to the disclosure can have a comparable
or
better efficiency than conventional facilities, with best in class GHG
emissions.
This is achieved by:
= Using DMR liquefaction technology and a selection of other low-weight,
compact equipment, challenging the number of installed spares and
reconfiguring the
internal module layout and location of the main pipe rack.
= A conscious choice to apply water cooling, reducing the equipment weight
and therefore module weights significantly and reducing the specific GHG
emissions.
= Comprising at least one or more full process units inside a respective
module. A process unit herein relates to a unit to perform a specific step of
a
liquefaction process, such as acid gas removal, dehydration, condensate
stabilization.
This enables to maximize pre-commissioning at the fabrication yard and
minimizing
interconnections and hookups between respective modules and hence minimizing
work at the production location to interconnect the modules and construct the
liquefaction train.
= Optimizing the capacity of each liquefaction train to between 2 to 4 MTPA.
Larger trains suffer from large and heavy equipment and large bore piping.
Smaller
trains may suffer from interconnection inefficiencies for a given larger
capacity.
= Offering essential configuration options with limited overall design
impact.
For instance, the refrigerant compressors can be driven by aeroderivative gas
turbines
or by electric motors. The choice does not change the overall layout of the
LNG train
of the disclosure.
= The design caters for a wide feed gas composition range and therefore
enabling standardization and repeatability across multiple locations ¨ with
further
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potential benefits if using the same fabrication yards, contractors and main
equipment vendors.
Comparison with other Modular LNG built trains indicate a 40 to 50%
reduction in equipment weight, module weight and plot requirement (normalized
per
MTPA of installed capacity) and approximately 20% reduction in site
construction
hours as well as fabrication yard hours. Combined, this reduces the costs of
the
modular built LNG trains according to embodiments described herein with 20% or
more with respect to conventional liquefaction systems, including modular
built
systems. The facility of the disclosure enables significant additional future
savings at
project portfolio level.
The present disclosure is not limited to the embodiments as described above
and the appended claims. Many modifications are conceivable within the scope
of
the appended claims. Features of respective embodiments may be combined.
