Note: Descriptions are shown in the official language in which they were submitted.
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METHOD OF OPERATING A LIQUEFIED NATURAL GAS PRODUCTION
FACILITY
FIELD OF THE INVENTION
The present invention is directed to a method of operating a liquefied natural
gas production facility. The facility typically comprises one or more
production
trains 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 APCI
C3/MRTm or APXTM processes, the Phillips Optimized Cascade Process, the Linde
Mixed Fluid Cascade process or the Shell Double Mixed Refrigerant or Parallel
Mixed Refrigerant process.
Regardless of the choice of liquefaction technology, refrigerants are used to
reduce the temperature of the treated gas to a temperature of around -160 C to
form
LNG, resulting in warming of the refrigerant which must be compressed for
recycle
to the liquefaction process. The compressors used for this duty are
traditionally gas
turbines or electric motors depending on the power requirements and layout
issues of
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a particular LNG production train. The coolers required for the various
compression
and heat exchanger operations associated with an LNG plant may be air coolers
or
water coolers arranged in a heat exchanger bank.
Prior art modularized LNG production trains have been closely based upon the
design and layout of the more traditional stick-built LNG production trains.
Until
now, modularization has been conducted by slicing up an existing stick built
LNG
train design into transportable sections, leading to some compromises
regarding the
placement of the module boundaries. Prior art examples of modularization of a
traditional air-cooled LNG train have relied on dividing the air-cooled heat
exchanger bank into the smallest number of modules possible for a given size
of air
cooler within the air-cooled heat exchanger bank. To keep the overall plot
size of the
LNG production train to a minimum, it is known to arrange sub-sections of the
air-
cooled heat exchanger bank over the top of each module so as to cover one
hundred
percent of the area defined by the base of said module with a view to making
the air-
cooled heat exchanger bank as large as possible for a given module size.
Having
made the decision to fully cover each of the modules with a portion of the air-
cooled
heat exchanger bank, selected larger or taller pieces of process equipment
operatively
associated with each module, such as pressure vessels, compressors and the
cryogenic heat exchanger are either stick built or constructed as separate
modules
which are designed to remain uncovered by the air-cooled heat exchanger bank.
The overall footprint of such modularized LNG production plants is large
because sufficient plot space needs to be allocated to allow for covered
modules
incorporating the air-cooled heat exchanger bank to be positioned in a
straight line
running along the central longitudinal axis of the LNG production train with
the
uncovered modules being offset from the central longitudinal axis and located
on one
side or the other side of the centrally located air-cooled heat exchanger
bank. This
prior art design has several disadvantages. A high number of interconnections
are
required across the modules between the air-cooled heat exchanger bank covered
modules and the associated equipment located on an adjacent uncovered module.
The
use of a large number of small modules inevitably requires that the air
coolers within
the air-cooled heat exchanger bank that are required to perform cooling duty
for a
particular module will need to span across at least two modules, preventing
fluid
circulation through the air coolers until these two modules are joined at the
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production location. These prior art designs rely on duplication of structural
steel as
there is inevitably a large amount of void space underneath the air- cooled
heat
exchanger bank in addition to the structural steel that is used for the
uncovered
spatially offset process equipment modules.
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, wherein the major axis of the bank is parallel to the
major axis
of the train. A subset of the plurality of heat exchangers is arranged on a
first level
vertically offset from the base of at least one module to form a partially
covered
module, and wherein the major axis of the partially covered module is arranged
to lie
perpendicular to the major axis of the train when the partially covered module
is
installed at the production location. The heat exchanger bank has a footprint
and the
base of the partially covered module projects transversely outwardly beyond
the
footprint of the heat exchanger bank to provide an uncovered section of the
module
base on a first side of the heat exchanger bank. The uncovered section of the
module
base is sized for mounting a selected piece of process equipment. In another
form,
the heat exchanger bank has a footprint and the base of the partially covered
module
projects transversely outwardly beyond the footprint of the heat exchanger
bank to
provide a first uncovered section of the module base on a first side of the
heat
exchanger bank and a second uncovered side of the module base on a second side
of
the heat exchanger bank, wherein the first uncovered section is sized for
mounting a
first selected piece of process equipment and the second uncovered section is
sized
for mounting a second selected piece of process equipment.
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
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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
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.
Despite the many advantages and modular setup, the LNG production trains of
US-2014/053599-A1 and US-2016/0010916-A1 still require a relatively large plot
space. Also, capital expenditure is still relatively high.
In general, over the last one or two decades, LNG project costs (for instance
when expressed in project costs per tonne per annum) have increased about 2 to
4
times in comparison to older LNG production facilities, older herein typically
referring to plants constructed before 1990. Typical Capex is currently in the
range of
USD 1000-2000/tpa (or about 50 to 100 USD/tonne of LNG produced for a 20 years
lifetime of the facility). Reasons for these increased costs of construction
are, for
instance, one or more of the following. The time schedule for construction is
on
average about 50% longer when compared to historic projects (e.g. constructed
before 1990). Costs of equipment (for instance compressors and heat
exchangers)
and raw material, such as steel and nickel, have doubled over time. In
addition, many
LNG facilities are planned to be built in, or have been built in countries
having
relatively high labor costs. Modularization, which for instance aimed to
circumvent
high labor costs by constructing (modules of) facilities in a location having
reduced
costs of labor and subsequently move the preconstructed modules to the LNG
production location, has disappointed in practice, i.e. production costs
remained
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relatively high compared to older facilities. Another factor which is
sometimes
mentioned is the reduced impact of innovation.
LNG production trains typically have a significant impact on capital
expenditure and plot space of an LNG production plant. Consequently, there
remains
a need to explore alternative designs for an LNG production train to improve
on one
or more of the disadvantages referenced above.
SUMMARY OF THE INVENTION
In one aspect, the present invention is directed to a method of operating a
liquefied natural gas (LNG) production facility, the method comprising the
steps of:
i) providing at least a first LNG production train and a second LNG production
train, each production train comprising at least one integrated process unit
comprising interconnected compact building blocks;
ii) providing a set of spare compact building blocks;
iii) running the first LNG production train during a first operating period;
iv) running the second LNG production train during a second operating period;
v) shutting down the first LNG production train during a maintenance period
for removing one or more pre-selected building blocks from the first LNG
production
train for maintenance, and replacing said pre-selected building blocks with
compact
building blocks from the set of spare compact building blocks having the same
functionality and process equipment;
vi) maintaining the pre-selected compact building blocks removed from the
first LNG production train to provide renovated compact building blocks;
vii) including the renovated compact building blocks in the set of spare
compact building blocks; and
viii) repeating steps v) to vii) for the second LNG production train.
In an embodiment, the method comprising the steps of:
ix) providing a third LNG production train, comprising at least one integrated
process unit comprising interconnected compact building blocks;
x) running the third LNG production train during a third operating period; and
x) repeating steps v) to viii) for the third LNG production train.
In another embodiment, the first operating period and the second operating
period are displaced in time with respect to each other.
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In an embodiment, the facility comprising only a single set of spare compact
building blocks. The method only involves providing a single set of spare
compact
building blocks.
The first operating period and/or the second operating period can be at least
in
the order of a year. The maintenance period may be in the order of one or two
weeks.
In an embodiment, the step of maintaining the pre-selected compact building
blocks including the steps of:
transporting the pre-selected compact building blocks removed from the first
LNG production train to a maintenance location which is remote from a
production
location;
maintaining said pre-selected compact building blocks removed from the first
LNG production train at said maintenance location to provide maintained
compact
building blocks; and
returning the maintained compact building blocks to the production location.
In yet another embodiment, each compact building block comprising one or
more pieces of selected process equipment, enclosed by a support frame, the
support
frame having a size substantially compatible with a standard freight
container.
In an embodiment, the step of shutting down the first LNG production train
comprising:
removing hydrocarbons or other process streams from the first LNG production
train using at least one vacuum system.
The at least one vacuum system may be connected to a gravitationally lower
end of a respective process section.
In another embodiment, the step of running the first LNG production train
during the first operating period comprises monitoring and controlling the
first LNG
production train from a monitoring location remote from a production location
of the
LNG production facility; and
the step of running the second LNG production train during the second
operating period comprises monitoring and controlling the second LNG
production
train from the monitoring location.
In another embodiment, the step of running the first LNG production train
during a first operating period comprising automatic startup of the first LNG
production train; and
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the step of running the second LNG production train during a second operating
period comprising automatic startup of the second LNG production train.
In an embodiment, the step of running the first LNG production train during a
first operating period comprising automatic operation of the first LNG
production
train; and
the step of running the second LNG production train during a second operating
period comprising automatic operation of the second LNG production train,
the automatic operation substantially lacking human intervention.
In another embodiment, the steps of running the first LNG production train and
running the second LNG production train comprising:
detecting undesired conditions to allow timely intervention using monitoring
instrumentation.
The step of detecting undesired conditions may comprise one or more of:
- detecting leaks on drain points;
- monitoring of critical areas using camera systems;
- Noise detection systems, which may trigger zoom-in by the camera system;
and
- Vibration monitoring using sensors.
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 perspective view of a conventional stick-built LNG
production train;
Figure 2 shows a top view of a conventional modular built LNG production
train;
Figure 3 shows a perspective front view of an embodiment of an LNG
production train according to the disclosure;
Figure 4 shows a perspective rear view of the embodiment of Figure 3;
Figure 5 shows a perspective view of another embodiment of an LNG
production train according to the disclosure;
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Figure 6 shows a diagram of a method of operating at least two LNG
production trains;
Figures 7-9 show respective side, top and front views of a method of operating
an LNG production train;
Figure 10 shows a diagram of a method of operating an LNG production train;
Figure 11 shows a diagram of a conventional process section;
Figure 12 shows a diagram of an embodiment of a process section according to
the disclosure;
Figure 13 shows a diagram of another conventional process section;
Figure 14 shows a diagram of another embodiment of a process section
according to the disclosure;
Figure 15 shows a diagram of a conventional valve section in a conventional
LNG production train;
Figure 16 shows an embodiment of a valve section according to the disclosure;
Figure 17 shows a diagram of a conventional pressure vessel section;
Figure 18 shows a diagram of an embodiment of a pressure vessel section
according to the disclosure;
Figure 19 shows a diagram of a conventional column type process equipment
section;
Figure 20 shows a diagram of an embodiment of a column type process
equipment section according to the disclosure;
Figure 21 shows a perspective view of a compact building block provided with
a transport frame.
DETAILED DESCRIPTION OF THE INVENTION
Certain terms used herein are defined as follows:
The term "LNG" refers to liquefied natural gas.
The term "plant" may refer to the LNG production plant including one or more
LNG production trains.
The term "facility" may typically refer to an LNG production plant, but may
alternatively refer to an assembly in general.
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
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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 "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.
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 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.
The term "building block" or "compact building block" refers to a part of a
section of an LNG production train or plant that can be replaced relatively
easily and
with minimal interference with other parts or blocks of the production train
or
respective process section. This method of replacement may be referred to as
plug-
and-play. The building block may be assembled on the production location, or
may
be preassembled at a construction or assembly location remote from the
production
location. At the production location, the plant may be constructed by
connecting
building blocks to each other and to other process equipment in a
predetermined
manner.
Many of the building blocks may be relatively small, typically having a size
comparable to, or fitting in a standard freight container (e.g. a 40 or 45
foot
container). Thus, each building block may be designed to be transported from a
maintenance location or assembly location to the production location and vice
versa
on floating barges or by land using, for instance, rail or truck. After each
building
block is moved from the maintenance or assembly location to the production
location, the renovated or new block can replace a functioning block of the
plant
having a corresponding functionality, allowing the functioning block to be
removed
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for maintenance. The latter may be referred to, or covered by the term "plug
and
play".
In general terms, a process for liquefying a natural gas stream typically
comprises certain process steps, embedded in subsequent sections of an LNG
production train. Figures 1 to 3 show a few different conventional LNG
production
trains, including the typical sections.
Figure 1 shows an example of a liquefied natural gas (LNG) production train 1.
The production train is a stick-built train, wherein all sections are arranged
substantially one after the other. The production train 1 has a substantially
longitudinal form, all section being arranged in longitudinal direction. The
train 1
typically comprises subsequent sections for performing, at least, the process
steps of:
i) pre-treating a natural gas feed stream in a pretreatment section 10 to
produce
a pre-treated natural gas stream;
ii) pre-cooling the pre-treated natural gas stream in a first refrigerant
compression section 12 to produce a pre-cooled gas stream and a first
refrigerant
vapor stream which is compressed therein;
iii) condensing the first refrigerant vapor stream in a first refrigerant
condenser
section 14 to produce a compressed first refrigerant stream for recycle to
step ii);
iv) further cooling the pre-cooled gas stream in a main cryogenic heat
exchanger 16 operatively associated with a liquefaction section 18 through
indirect
heat exchange with a second refrigerant to produce a liquefied natural gas
product
stream 20 and a second refrigerant vapor stream; and,
v) compressing the second refrigerant vapor stream in a second refrigerant
compression module 22 to produce a compressed second refrigerant stream for
recycle to step iv).
In addition, the train typically comprises a pipe rack 24 extending in
longitudinal direction along the length of the production train 1. Air cooled
heat
exchangers 26 are typically arranged on top of the pipe rack, to allow the
release of
heat rejected by the natural gas during cooling - which is cooled from ambient
to
cryogenic temperatures ¨ to the environment.
For additional details of the cooling process and the respective sections of
the
LNG production train, reference is made to, for instance, one or more of US-
6370910
(discloses aspects of one particular cooling process, the double mixed
refrigerant
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process (DMR)), US-6389844 (discloses a parallel mixed refrigerant process),
US-
2015/0300731, US-7152431 and US-9396854 (process to remove contaminants).
The production train 1 shown in Figure 1 has typical dimensions indicated by
length Li and width W 1, the length being significantly longer (for instance
at least
twice as long) than the width. Said length and width define a substantially
longitudinal area, which may be referred to as the area inside the battery
limit
(ISBL). An LNG plant typically comprises other sections in addition to the LNG
production train 1, which are located outside the battery limit (OSBL).
Examples are
the one or more LNG storage tanks 24 for storing the produced LNG 20. Also,
the
plant typically comprises sections for supply of natural gas and for
offloading of the
LNG, for instance a jetty for transferring LNG to an LNG carrier vessel.
Figure 2 shows an example of a prior art modular production train 2, with the
above-referenced basic sections indicated. Herein, the respective sections 10,
12, 14,
18 and 22 of the train are comprised in corresponding modules 40, 42, 44, 46,
and 48.
Thus, prior art LNG production train 2 comprises the following modules:
a) a pretreatment module (40);
b) a first refrigerant compression module (42), in this example, a propane
compression module;
c) a first refrigerant condenser module (44), in this example, a propane
condenser module;
d) a liquefaction module (46); and,
e) a second refrigerant compression module (48).
Respective modules have covered sections covered by the air cooled heat
exchangers 26, and uncovered sections 50. Process equipment is arranged on the
uncovered sections of the respective modules. The covered sections do not
comprise
process equipment.
As example only, the first refrigerant may be propane while the second
refrigerant may be a mixed refrigerant hydrocarbon mixture. This type of
process is
known as the propane pre-cooled mixed refrigerant, or C3MR process. Other
processes, as mentioned in the introduction above, are equally conceivable.
When
using propane, or another hydrocarbon or mixture of hydrocarbons, as the first
refrigerant, care is to be taken to ensure that the propane or mixture of
hydrocarbons
does not leak, because these are highly flammable.
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Using the process of the prior art, the process equipment required for propane
compression is grouped together within a propane compression module to
facilitate
the pre-commissioning and commissioning of that module having all of the
accessories that are needed to circulate fluid through the compressor at the
production location. To further improve safety, the main rotating equipment
associated with the propane compression circuit is placed on an uncovered
section 50
of one of the plurality of modules, i.e. on a section of the modules not
covered by air-
cooled heat exchangers 26, rather than underneath a plurality of air-cooled
heat
exchangers 26 arranged on an elevated level.
Although the width of the modularized LNG production train 2 may be a bit
smaller than the width W1 of the stick-built train 1 shown in Fig. 1, the
length L2 of
the train 2 (Fig. 2) is substantially similar to the length Li of train 1
(Fig. 1).
In an alternative prior art modularized LNG production train (not shown, but
see for instance US-2016/0010916), respective modules 40-48 may be arranged
side-
by-side rather than in subsequent order. Despite the potential advantages this
may
provide, the total footprint of the train remains the same as the footprint of
the
production train 2 shown in Fig. 2.
As a result, although the overall footprint (ISBL) of the modularized train 2
(Fig. 2) may be a bit smaller than the footprint of the stick-built train 1
(Fig. 1), in
practice the capital expenditure turns out to be almost the same or even
higher than
the capital expenditure for a conventional stick-built train 1. As capital
expenditure is
¨ eventually ¨ one of the most important deciding factors to indicate if and
when an
LNG production plant will break even, a plant with stick built LNG production
trains
is often more cost effective.
Applicant has found that, for instance, a significant cost factor in
constructing
LNG plants is related to the actual preparation of the site. Preparation
herein may
include, but is not limited to, one or more of removing soil, arranging
appropriate
foundations, creating concrete base structures to hold process equipment
and/or other
sections of the facility. For instance the time schedule for the preparation
of the site
and the creation of the concrete base structures typically overruns, for
instance with a
factor of 50% or more. Cement need to dry after being poured in the correct
place to
form the concrete base, and drying of the cement slurry in practice typically
takes
longer than scheduled. Overruns of the construction schedule may lead to
additional
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costs or delayed income due to, for instance, costs of equipment rental, labor
costs,
hiring of contractors, reduced net present value of the project due to delayed
commencement of sales and/or potential claims for damages in supply contracts.
In
fact, these costs may be one of the most important causes of the increased
capital
expenditures of LNG production plants compared to older plants constructed
prior to
1990.
In the history of onshore plant construction, both pre-fabricated modules and
stick built trains have been used extensively. The general view is that,
unless local
labor costs are unusually high and/or productivity is particularly low, a
plant with
stick built LNG production trains results in the lowest costs, albeit a longer
production schedule and the most exposure to local influences and potential
quality
issues. The classic modular approach generally is seen to lead to a shorter
overall
production schedule and better quality of the LNG production train, yet at the
expense of higher capital expenditure. This higher cost is mainly attributable
to the
required structural steel and the transportation cost of the modules.
The choice to use modular built instead of stick-built for LNG production
trains is generally taken after the basic 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 has to be leak tested on site. Additionally, the
majority of
the cabling has to be installed and tested on site. The latter are both
relatively time
consuming and costly.
To overcome these disadvantages, the applicant proposes a combination of
unconventional and bold measures. As the measures and features described below
are
mutually beneficial, one or more thereof in combination may enable to
dramatically
bring down capital expenditure. The LNG production train of the disclosure can
be
built faster and at lower cost.
An embodiment of a liquefied natural gas production train 3 according to the
present disclosure comprises one or more integrated process units 100, 110.
One
integrated process unit may combine multiple functional sections of the LNG
production train. The integrated process unit(s) herein extends in horizontal
or
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longitudinal direction, but also in vertical direction. This means that
respective pieces
of process equipment of the train which are comprised in the same integrated
process
unit may be arranged side-by-side, but also above each other on respective
process
equipment floors.
In the embodiment shown in Figs. 3 and 4, the LNG production train 3
comprises, for example, two integrated process units 100, 110. The first
integrated
process unit 100 may have multiple levels or process equipment floors 101,
102, 103
respectively, arranged on top of each other. The second integrated process
unit 110
may have multiple levels 111, 112, 113 respectively, arranged on top of each
other.
The phrase multiple levels herein may imply at least two levels. The
production units
100, 110 may have at least three or four levels, or more. Thus, the integrated
process
units 100, 110 of the LNG production train of the present disclosure may
provide a
stacked construction. Herein, selected pieces of equipment may be arranged not
only
side by side, but potentially also vertically separated at a different
vertical level in the
same integrated process unit, thus limiting the area of the base of said unit.
The plot
size of the train will be limited accordingly. The integrated process units
100, 110 of
the LNG production train 3 thus extend both in horizontal, longitudinal but
also in
vertical direction. The integrated process units form generally three
dimensional
structures.
For instance, the first integrated process unit 100 may comprise the entire
gas
pre-treatment section 10. The second integrated process unit 110 may comprise
the
refrigeration section. Herein, a pre-cooler 114 for precooling refrigerant may
be
arranged on a side of the integrated process unit 110. A main cryogenic heat
exchanger 116 may be arranged on another side of the unit 110. The train may
have a
pipe rack 24, to hold pipes, for instance for providing natural gas to the
train and for
guiding liquefied natural gas to a storage tank (comparable to the facilities
in Figs. 1
and 2).
The train may, for instance, comprise a scrub column 118 to remove heavy
hydrocarbons from the natural gas before liquefaction thereof in the main
cryogenic
heat exchanger 116. Removal of heavy hydrocarbons, such as C6+ from natural
gas
is done prior to cryogenic liquefaction in order to prevent freeze-out of
these
components in the cryogenic heat exchanger 116. Traditionally, cryogenic
methods
such as passing feed gas through a scrub column 118 or a front-end NGL
extraction
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unit (not shown) have been employed for this purpose. Adsorption-based
separation
processes are an alternative method to strip trace heavy hydrocarbons from
natural
gas. Adsorption may be a good alternative for the scrub column for certain
feed gas
streams such as lean natural gas containing relatively low amounts of C2-C4,
yet
significant amounts of C6+. Lately, several sources of natural gas, such as
shale gas,
coal-bed methane, etc., report lean feed gas of this nature. Although not
shown,
instead of the scrub column 118, an adsorption-unit or a front-end NGL
extraction
unit may be included in one of units 100 or 110.
Other pieces of equipment may be arranged at one of the various vertical
levels
of one of the units 100, 110, to render the design as compact as possible and
to
minimize the length of piping to interconnect said equipment. The units each
have a
mechanical support structure 122, to support the plurality of levels or
process
equipment floors 101-103, 111-113 respectively.
The mechanical support structure, or structural frame 122, may comprise a
number of columns 126 extending in vertical direction interconnected by beams
128
extending in horizontal direction. The beams 128 and columns 126 support the
respective process equipment floors.
The structural frame 122 of one or more of the integrated process units 100,
110 may be arranged on supports 115. The supports may be, for instance,
blocks,
column beams, or pillars. The supports 115 lift a lower process floor 101, 111
of the
respective process unit 100, 110 a predetermined distance above ground 119.
This
may create a space 117 between the ground and the lower process floor. In a
practical
embodiment, the predetermined distance may be in the order of 0.5 to 5 meters
or
more. In practice, the predetermined distance may be in the order of 1 to 3
meters.
As described above, the integrated process units 100, 110 may be connected to
one or more pieces of process equipment arranged on the ground 119 adjacent to
the
respective integrated process unit, such as the pre-cooler 114 and/or the
cryogenic
heat exchanger 116. The vertical elevation of the lower process equipment
floor 101,
111 provided by the supports 115 assists draining of process sections using
gravity.
This may limit the requirement for pumps. The gravity draining also assists to
limit
the total number of drainage points (for instance as required when the LNG
production process is stopped). The vertical elevation allows optimizing
draining of
process equipment sections by gravity, using a relatively limited number of
drainage
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points. For more detail in this respect, please see the description below
regarding Fig.
12.
In an embodiment, the train 3 may comprise one or more water cooled heat
exchangers 124 to cool process streams and allow the LNG production train to
get rid
of the heat removed from the natural gas feed stream. In the stacked structure
of the
train 3, multiple water cooled heat exchangers may be arranged at various
levels and
throughout one of more of the integrated process units 100, 110. Thus, the
heat
exchangers 124 can be arranged relatively close to the related equipment
and/or
process stream which needs cooling, to limit, for instance, the length of
piping, the
related amount of steel and the number of connections and valves. Also, the
water
cooled heat exchangers 124 allow the integrated process units to be relatively
compact.
The water cooled heat exchangers may, for instance, use seawater for cooling,
which allows for a cost effective and efficient means of heat rejection.
Options
include once-through seawater cooling, a direct method of seawater cooling.
Such
method is suitable to be used for main shell and tube heat exchangers,
including a
refrigerant condenser, a sub-cooler and compressor coolers. The train may also
include some smaller heat exchangers, which may employ an indirect, or closed
loop
system whereby the seawater (in a first loop) is used to cool fresh water (in
a second
loop) through the use of plate and frame exchangers. It may be preferred to
select
indirect seawater cooling for all the heat transfer services, including the
refrigerant
condenser and coolers, and avoid direct seawater completely.
Figure 5 shows an embodiment of an LNG production train 4 for the
production of LNG, comprising three integrated process units 100, 110, and
120. The
third integrated process unit 120 may comprise one or more compressor units.
For
instance, the third integrated process unit 120 may comprise, at least, a
first
compressor unit for compressing a first refrigerant stream. Optionally, the
third
process unit 120 may comprise at least a second compressor unit for
compressing a
second refrigerant stream. For details of an exemplary cooling process,
including a
compressor for a mixed refrigerant stream and the connections thereof with
respect to
other process equipment, reference is made to, for instance, patent
application
U520120103011.
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In an embodiment, the fan driven air coolers 26 can be arranged on top of
one or more of the integrated process units. The train 4 comprises a number of
integrated process units 100, 110, 120. Each unit comprises a mechanical
support
structure 122 comprising a plurality of process equipment floors or levels 101-
103,
111-113. At least part of the process equipment for the cooling of a natural
gas feed
stream, or process gas stream, is arranged on the plurality of process
equipment
floors.
The process equipment comprises, at least, the cryogenic heat exchanger 116
wherein the process gas stream is indirectly heat exchanged against a
refrigerant
stream to produce cryogenically cooled LNG. Heat removed from the process gas
stream is absorbed by the refrigerant stream. The pre-cooler 114 for
precooling
refrigerant and the main cryogenic heat exchanger 116 may be arranged
alongside
and connected to the integrated process unit 110.
In the embodiment of Fig. 5, the process equipment of the train 4 comprises at
least an air draft cooler 26 arranged to establish indirect heat exchange
between
ambient air and, at least, a refrigerant stream leaving the cryogenic heat
exchanger
116. In use, said refrigerant stream has been warmed due to the heat that has
been
absorbed from the process gas stream. Herein, heat from the warmed refrigerant
stream is rejected to the ambient air. The air draft cooler 26 may comprise a
fan to
induce an air draft into the mechanical support structure 122, typically from
the sides,
and through the air draft cooler 26 in a direction away from the mechanical
support
structure, typically upwards.
With the embodiment of Figure 5, in the train 4 invention the process
equipment and the air coolers 26 can all be shop built into the integrated
process unit.
Thus, the process equipment does not have to be connected to the air coolers
26 on
site. In use, the air coolers 26 cause a current of relatively cool air around
predetermined heat exchangers and other process equipment located near the
respective air cooler 26. Safety is guaranteed because as a result of the air
current it
becomes more difficult to accumulate an ignitable gas mixture in the
integrated
process unit, in case of a gas leak.
In the embodiment of Figure 5, the air coolers 26 are arranged at the
uppermost
process equipment floor, covering the respective process unit 100, 110, 120.
Although part of the process equipment, in particular the cryogenic heat
exchanger
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116, may be placed alongside an integrated process unit, the majority of the
remainder of the process equipment is arranged inside one of the multi-leveled
process units 100, 110. Said units in turn are substantially covered by air
cooled heat
exchangers 26 over their entire area in top view, also covering the pieces of
process
equipment arranged in the respective integrated process unit.
In a practical embodiment, the required total area covered by the air coolers
may be in the order of 1900 m2 for an LNG production capacity of about 2 MTPA.
This may be within the available bay area on top of the Gas Processing unit
100 and
the Liquefaction unit 110. Part of the air coolers 26 may have to be fitter on
top of
the compressor unit 120. The area covered by air coolers 26 on top of the
compressor
unit 120 may be in the order of 550 m2, leaving scope for further capacity
increase of
LNG production.
A reduction in the area required for air coolers could involve fans providing
relatively high air velocity ¨ for instance using Whizz-Wheel fans by
Bronswerk
Heat Transfer (The Netherlands). Alternatively, a reduction in aircooler area
could be
obtained by applying fans with groovy fins as supplied by GEA Group
Aktiengesellschaft (Germany). Thus, the required aircooler area can be fitted
on a
fourth process equipment floor 104, on top of the integrated process units
100, 110,
120 for an LNG production capacity up to at least 2 MTPA, as exemplified
above.
In a practical embodiment - for instance of the production trains 3 or 4 - the
integrated process units 100, 110 may have a size (length, width, height) in
the order
of 20m x 20m x 30m per unit. Height of a unit 100, 110 may be in the order of
20m
to 40m or more. Height herein is defined as the distance in vertical direction
between
ground level 119 and a highest end of a respective unit. Both the LNG
production
train 3 and 4 may have a total length L3 in the order of 60-70m for a train
having a
capacity of about 1.5 to 2.5 mtpa. For comparison, a stick-built LNG
production train
1 having a comparable capacity would typically have a length Li exceeding 200
m.
Also, the width W3 of the production train 3 of the disclosure may be reduced
with
respect to the width W1 of a stick-built train because respective processing
equipment can be arranged in a vertically stacked arrangement with respect to
each
other.
The integrated process units 100, 110 provide a vertically built LNG
production train. Herein, a height H3 of one or more of the integrated process
units
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100, 110 is substantially equal to or larger than a width W100 and/or a length
L100,
L110 of the respective integrated process unit 100, 110. In an embodiment, the
height
H3 of at least one of the integrated process units 100, 110 may exceed the
width
W100 and the length L100, L110 of the respective integrated process unit 100,
110.
The height H3 of at least one of the integrated process units 100, 110 may,
for
instance, exceed the width W100 and/or the length L100, L110 of the respective
integrated process unit 100, 110 with a factor of about 30% or more. The
height H3
may be, for instance, about 150% or more of the width W100 and the length
L100,
L110 of an integrated process unit.
The production train 3 of the disclosure is also suitable for larger
capacities, up
to 4 to 5 mtpa or more per LNG production train. Cost savings may be even
larger, as
test runs and modelling have indicated that economies of scale apply to
provide
additional benefit. An optimal cost versus efficiency is achieved in the 4 to
5 mtpa
capacity range.
The plot size (length L3 x width W3) of the LNG production train of the
disclosure, inside the battery limit, may be about two times smaller than the
plot size
required for a conventional stick-built train (L1 x W1) having the same
capacity
(expressed in mtpa). In a practical embodiment, the required plot size may be
even
smaller, for instance at least three times smaller. In a practical embodiment,
plot size
of the LNG production train of the disclosure may be up to three to four times
smaller than the plot size of a conventional LNG production train having the
same
capacity. The smaller plot size reduces capital expenditure. For instance, it
provides
savings associated with corresponding reductions in time required to prepare
the
production site, time to arrange appropriate foundations and base structures
for the
integrated process units. Also, the overshoot of the preparations will be
reduced or
substantially obviated entirely.
As shown in Fig. 6, in an embodiment, the integrated process units may each
be assembled from a multitude of compact building blocks 150. Respective
building
blocks may be arranged side-by-side and also on top of each other. Each
compact
building block may comprise one or more pieces of selected process equipment.
Each
building block 150 forms a part of an integrated process unit 100, 110. The
train 3
uses relatively small and compact equipment, selected to suit plant sections
made up
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of the relatively compact building blocks 150 rather than adopting the prior
art
approach of relying on economy of scale.
In other words, each integrated process unit 100, 110, 120 is comprised of a
number of compact building blocks 150. The sizes of respective building blocks
may
differ, depending on the size of respective pieces of equipment. Yet, the
compact
building blocks have a size which can be relatively easily transported.
As an example, Fig. 6 shows a first LNG production train 3A and a second
LNG production train 3B, each comprising two integrated process units 100, 110
in
accordance with the embodiments shown in, for instance, Figures 3-4 or 5. The
integrated process units may be assembled using a number of interconnected
building
blocks 150. One of the building blocks, a scrub column block 160, may comprise
the
scrub column 118 and some associated pieces of equipment. For transport, the
building block may be provided with a protective support frame 162. The
support
frame 162 typically comprises a number of interconnected structural beams, for
instance made of steel or a corresponding high strength material, to form a
substantially box shaped block 160. At an upper end, the support frame of a
building
block may be provided with suitable connectors for lifting, such as hoisting
or
rigging hooks 164.
The support frame 162 of one particular building block can be linked to
corresponding support frames of adjacent building blocks 150 of the respective
integrated process unit. Combined, the support frames of the building blocks
150 of
the integrated unit form the support structure 122 of the integrated unit.
Figs. 7, 8 and 9 show respective side, top and front views of an embodiment of
integrated compressor unit 120, comprising at least one compressor 170. The
compressor, for instance a compressor for a (mixed) refrigerant, may be
powered by
an electrical generator 172, which in turn is driven by the output shaft of a
gas
turbine 174. In an exemplary embodiment, the gas turbine 174 may be included
in a
dedicated compact building block, indicated as gas turbine block 180. Like the
scrub
column block 160 (Fig. 6), the gas turbine block 180 may include some
additional
pieces of equipment associated with the functioning of the gas turbine 174.
Also, the
gas turbine block 180 may be provided with a support frame 162, typically at
least
enclosing the outer sides of the gas turbine block.
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Figs. 7-9 show exemplary steps Si to SS for removing a compact building
block, such as gas turbine block 180. Placing a compact building block 150 in
an
integrated process unit may follow substantially the same steps, but in
reverse order.
In a first step Si, a crane 178, for instance a gantry crane, is moved into
position
above the selected building block. In a second step S2, the selected building
block, in
the example of Fig. 7 the gas turbine block 180, is hoisted upward (for
instance using
the hoisting hooks 164 and cables). In a third step S3, the crane moves the
building
block in horizontal direction away from the integrated process unit. In fourth
step S4,
the building block 150 is lowered to ground level to be transported for
maintenance
in a fifth step SS.
The compact building blocks allow more flexibility in the operation of the
LNG train of the disclosure. For instance, as for instance indicated in Figs.
6 and 10,
a compact building block 150 (comprising certain process equipment, for
instance
scrub column block 160 or gas turbine block 180) may be removed from the
production train 3 for maintenance. As the building blocks are designed for
easy
transportation, for instance per ship 200, the maintenance may be done at a
remote
location. Such remote location may include a maintenance shop 202 and/or the
factory 204 of the original equipment manufacturer (OEM) of the respective
piece of
process equipment.
When removing a building block for maintenance, another building block
providing the same functionality may be inserted in the respective integrated
process
unit. If the production location is provided with at least two production
trains, for
instance a first production train 3A and a second production train 3B (Fig.
6), this
enables run-or-maintain type operation. This includes periodical maintenance
at set
time intervals, which if set appropriately will significantly limit downtime
of the train
by limiting or entirely obviating the tripping of process equipment.
The periodical maintenance may include, for instance, a set time period for
removing one or more pre-selected building blocks 150 from the first
production
train 3A for maintenance. A set of spare compact building blocks may be
provided,
comprising new or renovated building blocks having the same functionality and
process equipment as the building blocks of the respective production train.
After
removing the building blocks from a production train for maintenance, the
building
blocks can be replaced with the equivalent spare building blocks.
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By selecting the interval for maintenance for each building block 150
appropriately, the number of spare parts required may be significantly
reduced. For a
conventional stick-built train 1 (Fig. 1), typically the operation would
include at least
one spare part for virtually every piece of process equipment. The operation
in
accordance with the present disclosure allows operating an LNG production
train
having at least two or more trains 3, with only a single spare piece of
process
equipment. For instance, only a single set of spare compact building blocks
may be
sufficient. After maintenance, the maintained and renovated building blocks
are
returned to the production location. There, the renovated building block can
replace
the corresponding building block in the second train 3B. Operation for an LNG
production plant having three or more LNG production trains will generally be
similar, but will typically provide an even greater cost improvement, because
a single
set of spare parts or spare pieces of process equipment may be sufficient for
reliable
operation of all three LNG production trains.
In a practical embodiment, periodical maintenance for an LNG production
facility according to the present disclosure may include, for instance, a set
yearly
maintenance period for each train 3A, 3B, etc. The maintenance period, or turn
around period, may be in the order of one to two weeks. During the maintenance
period, the respective train to be maintained will be shut down. A selected
number of
pre-determined process equipment will be replaced with new or maintained
process
equipment. building blocks providing the same functionality. The process
equipment
may be included in compact building blocks. Some of the process equipment may
be
replaced during every maintenance period, while other pieces of process
equipment
or valves may be replaced only once every two to four years. For instance,
while
preventative testing for safeguarding against equipment trips will be done
every
maintenance period, some process equipment may be tested and/or replaced only
every second or third maintenance period, or less. For example:
- Every turn-around (yearly): Safeguarding testing; Amine filter; Gas Turbine;
Generator; Transformers; Variable frequency drive;
- Every other turn-around (bi-yearly): Pump maintenance;
- Every third turn-around (every three years or less): Relief valve testing;
Cleaning the amine section; Mercury removal section; Compressors; Molsieves;
Switching valves.
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The overall layout of the production train 3 of the present invention,
comprising for instance gas treating unit 100 and liquefaction unit 110, may
be
designed for modularization. This means that each building block 150 may be
designed as a module, suitable to be constructed at a remote fabrication
location and
transportable to the production location. Herein, each integrated process unit
100,
110 may itself be assembled by connecting the respective building blocks,
forming a
plug-and-play type integrated structure, wherein building blocks can be
connected
and replaced for maintenance relatively easily.
The LNG production trains 3 or 4 of the present disclosure allow operation
based on the principle of "run or maintain", as exemplified above. This mode
of
operation may obviates in the order of thousands of isolations, such as
valves, that
are traditionally installed to enable "hot" maintenance in a running plant
(i.e. under
the most difficult and hazardous circumstances). Hot maintenance herein refers
to a
reactive type maintenance, wherein parts and pieces of equipment are only
replaced
if and when they fail. This requires a multitude of spares on site, while also
requiring
replacement of equipment in a plant which has not yet fully cooled down from
process conditions, hence the term "hot" maintenance. In a nutshell, the LNG
production train of the present disclosure can achieve run-or-maintain type
operation
by combining one or more of the following elements:
- Elimination of the vast majority of operational problems by full automation;
- Simplify automation by removing process permutations (reducing the number
of spares; reducing complexity of the train);
- Reduce design complexity by elimination of problems at root (for instance
caused by human operators).
In addition to, and in combination with, the above described features of the
LNG production train of the present disclosure, costs of the LNG plant are
limited by
setting a very strict cost target. In an exemplary embodiment, in the order of
USD
200-300/tpa ISBL is deemed achievable. Thus, capital costs of the LNG
production
train of the present disclosure can be limited to the same level or lower as
the costs of
conventional LNG production trains of decades ago. Features and embodiments of
the present disclosure can be applied in combination, and/or can be applied to
other
equipment and processes of the LNG production plant at large, adding to cost
limitations.
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This concept is for instance possible by avoiding the usual cost creep. For
instance, conventionally it was often argued that additional equipment is
required to
achieve safety and reliability goals. Yet, surprisingly, the applicant found
that in most
cases this reasoning is flawed. The additional equipment and complexity of the
design and plant operations become the actual cause of incidents and
unreliability.
The simpler a design of the LNG production train is, the fewer failure modes
the
train has. As a result, operation is fundamentally safer and more reliable.
These
principles must be actively guarded during all phases of design because the
natural
tendency is to revert to classic complicated designs. The embodiments
described
below improve simplicity of the design, and thus limit costs while also
improving
process safety and significantly increasing uptime. The embodiments described
below can, for instance, be combined with the vertical stacked design of the
embodiments of integrated process units of trains 3 and 4. Alone or in
combination,
the features and embodiments of an LNG production train disclosed herein may
ultimately allow for highly automated batch operation of the LNG production
train.
It should be stressed that the LNG production industry, due to the inherent
danger of processing explosive materials, has a strong focus on reliability,
but
conventionally this has resulted in a relatively conservative approach to
plant design.
In practice, this boils down to a strong preference for proven technology. In
this
context, the present disclosure provides significant improvements and
potential break
though ideas, ultimately enabling the industry to remain cost effective.
Numerous studies around Abnormal Situations (such as equipment trips and
plant down time) mostly point to the same root causes. As a typical example,
research by the Abnormal Situation Management (ASM) consortium has found that
about 70% of "abnormal situations" and "unreliability" is caused by human
error,
either due to direct mistakes (40%), and/or to conscious or unconscious
mistreatment
of equipment (30% of total). This situation is expected to worsen in the
future, due to
an aging population and (too) limited supply of technical staff, having the
right
technical qualification. Thus, in combination with embodiments described
herein, the
LNG production train of the disclosure aims to remove human operators from
direct
control of the train and associated LNG production process, and to almost
completely
remove human operators from "decision making" in the line of command between
business and the process equipment.
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In conventional operation, equipment failure is almost exclusively referred to
as "Technical Failure". However, in practice almost all failures are the
consequence
of human choices, either directly or indirectly, consciously or unconsciously.
It is
human choice to properly commission, operate within limits, maintain,
lubricate and
so on. However, as an example, pump damage because it ran dry cannot be
classified
as genuine technical failure, as it would have been prevented if the pump
would have
been operated within its design limits. In short, equipment generally does not
fail
outside normal design limits, it typically gets killed. Although this is the
root cause
of the vast majority of equipment failures and trips, this is generally not
taken into
account. Without a large step-change (for instance, automated operation and a
facility
enabling automated operation), this conventional practice will continue.
An achievable aim is, for instance, operation wherein one or more of the LNG
production trains disclosed herein is automated, such that the LNG production
trains
only require the presence of a small number, for instance one to three,
operators
during office hours (about 40 hours per week). The remaining time (128 hours
per
week), the production site can be unmanned. Off site and remote (for instance
in a
nearby town, maybe even at home, or in a major research center), there may be
an
operator on duty, equipped with a pager or similar device. In case of a plant
trip (for
instance caused by lightning strikes to disrupt power to equipment), the
operator on
duty can poll the plant status by means of a computer or tablet PC via a
secured
interne connection. Full and autonomous automated operation has proven to be
far
superior to any form of human control. It provides the best results in
combination
with hardware that has been specifically designed for it, as the embodiments
of an
LNG production train as disclosed herein.
As on-site organization will be almost entirely obviated, the monitoring,
supervision and servicing of the facilities may be arranged through a Regional
(or
Global) Service Centre (RSC). There is no control room at the LNG production
location in the traditional sense. Neither will offices be installed. Such RSC
is
envisaged as a cost-effective office space in existing Technology Centers, for
instance the research centers of Applicant in Amsterdam (NL), Calgary (CA), or
Houston (US). Here, abundant engineering support is already available. This
would
not only significantly simplify organizational barriers, but also create a
more intimate
involvement of "designers" with the end product. Additionally, this will be an
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natural environment for growing and developing the desired engineer-type of
operations staff. Thus, the automated remote operation of the LNG production
train
of the invention may obviate local organizations and the associated overhead,
buildings, etc. This improves cost-effective operation.
Redundancy can be provided by linking two or more RSCs via a network
connection. This operating philosophy assumes that a (potentially large)
number of
LNG liquefaction facilities are monitored by an engineer position (for
instance just
one engineer) on a 24/7 basis from a remote location. Monitoring will not
require
continuous attention, but may be based on "one traffic light per facility",
indicating
either ok or not-ok, potentially with an intermediate (amber) indication.
To accommodate (near) zero-human presence at the production location, the
LNG production train of the disclosure may have no isolation between equipment
and no installed spares, as elucidated below. Maintenance shall be fully
predictive
and campaign based. For the avoidance of doubt, there shall be no designed
breakdown ("run to failure") maintenance whatsoever. Maintenance shall be
based on
"plug and play" replacement (see for instance Fig. 6). There shall in
principle be no
"in situ repair" of parts or equipment; these will be replaced with fully
maintained or
new parts during the turnaround or maintenance period.
Fig. 11 shows a detail of a typical conventional train, with consecutive
exemplary pieces of process equipment 210, 212, 214. Each piece of process
equipment is provided with a dedicated relief system 220, 222, 224, connected
to a
common relief line 226. The process equipment is connected via horizontal pipe
sections with dedicated valves 234, 236, with valves 230, 232 at the inlet and
oulet of
the exemplary process.
Such traditional designs are typically segmented and provided with numerous
hose connections and vents to flare or atmosphere for safety. Removing
hydrocarbons is usually done by piston-purging with nitrogen, hooked up by
hoses or
by a fixed connection. Sometimes some form of heating up the purge gas is
provided.
Interconnecting piping typically spans relatively large horizontal distances,
and is
notoriously difficult to decontaminate (for instance, empty in case of an
emergency).
The piston purging requires large amounts of purge gas, which leads to
constructing
large nitrogen units to enable this. It typically takes several days and does
not reach
all extremities of the plant, sometimes leaving pockets of gas or liquid
behind. It is
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not unusual to see continued gas-freeing still going on to halfway a shutdown,
while
managing the associated risks is complex. As a result, status change from
running to
stop and vice versa is relatively time consuming, with associated risks of
incomplete
purge.
Fig. 12 shows an embodiment of the process section 238 according to the
disclosure, comprising the exemplary pieces of process equipment 210, 212,
214.
Herein, said pieces of process equipment are interconnected by sloping pipe
segments 235, 237. The downward sloping pipe segments 235, 237 are continuous
and without valves. A purging system 242 may be connected to a secondary inlet
of
the process section, via a valve 244. At a gravitationally lower end of the
process
section, the process section may be provided with a vacuum system 246 via
valve
252 to remove hydrocarbons or other process streams from the system. The lower
end may also be provided with a liquid outlet 256 with dedicated valve 254.
The
vacuum system 246 may be connected to a flare 248 and/or a vent to atmosphere
250.
The embodiment of Fig. 12 provides a relatively compact, vertically oriented
design without segmentation by valves between adjacent pieces of equipment.
Preferably, the process equipment is connected via a downward sloping pipe, to
allow draining by gravity. In an emergency, or during maintenance, liquid can
be
removed under (sub-atmospheric) pressure by the vacuum system 246. In a
practical
embodiment, the LNG production train may be provided with fluid outlets of the
vacuum system located substantially at ground level, allowing relatively easy
and
simple maintenance. Also, the total number of such fluid outlets can be
relatively
limited.
In a practical embodiment, hydrocarbons can be removed from the process
section by pulling vacuum (by opening valve 252). A suitable vacuum herein is,
for
instance, below 1 bara down to about 0.1 bara. Pulling vacuum multiple times,
for
instance about three times, can be combined with purging (filling the system
and
pipes 235, 237) with nitrogen in between. The embodiment of Fig. 12 allows to
achieve a situation with about 0.1 vol% hydrocarbon or less in the process
section
shown in a relatively short time period. Short time period herein may be
within 6
hours or less. This is far below the lower explosion limit, in other words a
safe
situation. After the last evacuation, air may be let into the process section.
The
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embodiment has the additional benefit that the procedure obviates analytical
equipment, as the adequacy is simply guaranteed by the process conditions. The
process to remove hydrocarbons from the system ensures removal of hydrocarbons
below the explosion safety limit, even in the smallest corners of the process
section.
The nitrogen demand is only a fraction of the piston purging method of the
conventional system shown in Fig. 11.
In a practical embodiment, the LNG production train of the disclosure can be
purged using about 500 m3 of gaseous nitrogen per flush (or about 1 m3 of
liquid
nitrogen). This can be supplied by a standard evaporator unit from for
instance Linde
or Air Products. A threefold purge, guaranteeing very low hydrocarbon residue
in the
system, would require about 1500m3 of gaseous nitrogen. The nitrogen would be
delivered in, for instance, about 4 to 6 hours. This is achievable using, for
instance, a
relatively small Linde evaporator (e.g. L 40-12F4L). The exemplary embodiment
shows that this method enables fast removal of hydrocarbons from the system.
The
method obviates the requirement for a capex intensive large-volume nitrogen
plant.
In an embodiment, the vacuum system 246 may also allow for water removal
from the process section by applying deep vacuum (for instance down to about
10
mbar). In the LNG production train of the disclosure, this would be applicable
for
drying out after hydrostatic testing, or for a dry-out after a turnaround.
Tests have
indicated that water can be removed in about two days, as opposed to the usual
nitrogen purging methods spanning about 2 to 3 weeks.
The vacuum system 246 may also allow leak testing prior to start up, by means
of vacuum (for instance of about 0.1 bara). This is a fast and effective
method to
confirm that there are no leaks. As opposed to pressure testing, the vacuum
method is
not influenced by typical temperature-induced pressure swings, and is
generally very
sensitive. In combination with a fully welded design, it will speed up plant
commissioning significantly.
In a practical embodiment, for instance the integrated liquefaction unit 110
(Fig. 3,4) of the LNG production train 3 may be provided with (only) in the
order of
7 to 8 relief systems 240 (for emergencies only such as fire or lightning).
This is a
significant limitation compared to the 300 to 400 relief devices 220, 222 in
conventional plant designs.
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The embodiment of Fig. 12, in combination with the relatively compact and
vertically oriented structures of the LNG production train 3 (Fig. 3), allow
relatively
rapid status changes (between operating and stopped) by dropping out liquids
and
removing remaining gas by vacuum. This is virtually impossible if parts of the
train
are horizontally spread out over a large area, such as the stick built train
1. In such
case the interconnecting horizontal lines cannot, or only at great cost, be
laid on slope
over the relatively long horizontal distances involved. Decontamination of
such
systems is notoriously difficult, in particular if liquid remnants must be
evaporated.
Traditionally, this leads to complicated and lengthy piston purging
procedures. In
turn this leads to more valves in the design and to overall time loss and
increased
operational risk and complexity. Using gravity for draining, as with the
embodiment
of Fig. 12, is relatively easy and simple. The integrated process units 100,
110 of the
present disclosure, wherein some equipment may be stacked on top of each other
and
the integrated process units 100, 110 may itself be elevated with respect to
ground
level by supports 115, will enable gravity draining. Interconnecting lines may
be
either vertical, or horizontal but sloping downward. The relatively short
horizontal
distances between subsequent pieces of equipment allow interconnecting piping
to be
laid sloping downward. In turn, this limits the number of draining points
(252, 254)
to only a few low points to drop out liquids, followed by complete removal of
remaining hydrocarbons by vacuum.
In an embodiment, the LNG production train of the present disclosure aims to
limit design complexity and simplify hardware. As exemplified in Fig. 13, in
conventional LNG production facilities it is standard practice to install
spares (260B,
262B) of process equipment in parallel with the main piece of process
equipment
(260A, 262A). Herein, the spare can take over if the main part trips, by
switching the
required valves 264 accordingly.
However, contrary to popular belief, installed spares (such as pumps) for
properly operated and monitored equipment do not increase uptime. On the other
hand, the spared systems significantly increase complexity, both with respect
to
hardware and in operating procedures. Moreover, automation of the myriad of
possible permutations of spared systems is complex.
The simple exemplary embodiment shown in Fig. 14 indicates how the LNG
production train of the present disclosure obviates spares and associated
hardware
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such as valves. A first piece of process equipment 260 is directly connected,
via
piping 266, to a second piece of process equipment 262.
A special case of sparing is the bypass around control valves 270, shown in
Fig. 15, conventionally included in an LNG production train. Fig. 15 shows a
control
valve 270, with block valves 272 to block the regular flow and direct it via
bypass
valve 275. This setup requires many welded connections 274 (indicated by dots;
about 20 welded connections in a typical conventional bypass arrangement). As
a
result, the setup has many potential leak paths 276 (indicated by circles;
about 18
leak paths in a typical conventional bypass arrangement).
The bypass is intended to enable reactively swapping a particular control
valve
270 when it fails, while continuing the LNG production process. If this is
required
however, it is usually only in cases where proper, predictive maintenance has
not
been done. Besides, in practice, it turns out that it is substantially
impossible to
control a flow manually via the bypass valve 275 (by a human operator at the
radio,
24 hours per day every day until the control valve 270 has been replaced) due
to
small changes in process dynamics. Also, isolating the control valve 270 under
pressure is, in practice, often impossible due to leaking or non-moving block-
valves
272. In operational reality, successfully removing and replacing one of the
control
valves 270 "on the run" is exceptionally rare. Moreover, the bypass
arrangement
shown in Fig. 15 may be and often is abused to enable to run the process
outside the
design operating window.
In an embodiment, the LNG production train of the disclosure is provided with
control valves 270 without bypass arrangement (Fig. 16). This limits the
number of
welded connections 274 (for instance to about four) and the potential leak
paths (for
instance only one). This results in a reduction of direct costs for hardware
(not only
the manual valves, but also plot space, steel structure, provisions for
accessibility,
etc.). Yet it also results in indirect savings, as a bypass valve 276
generally incurs an
additional flow rate requirement on the control valve 270 for safeguarding
purposes,
typically about 50% additional flow on top of a maximum flow rating of the
control
valve 270. This propagates into inflated design of other process equipment as
well,
for instance relief systems 220 (shown in Fig. 11). Removing the bypass on
control
valves in combination with automated operation and/or the run or maintain
philosophy elucidated above limits capital expenditure while at the same time
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improving operational security (no trips; operating within design limits) and
overall
uptime (due to automated operation and the run or maintain philosophy).
As another example, pressure vessels 280 for process fluids in conventional
facilities are typically provided with a double or triple set of relief valve
structures.
See Fig. 17. The relief valve structure functions as a safety valve,
connecting the
pressure vessel 280 to a flare 282 if the pressure inside the pressure vessel
exceeds a
safety threshold. The conventional relief valve structure typically comprises
about
eight valves 284-298.
In the LNG production train of the disclosure, relief valves are not spared. A
pressure vessel 280 is provided with a single relief valve structure connected
to the
flare 282. The relief valve structure may have, for instance, about three
valves 286,
288, 292. See Fig. 18.
The operating concept described above ensures that process variations are more
limited with respect to conventional operation. Due to the run or maintain
mode of
operation, a typical accident due to accidental lifting of relief valves will
be obviated.
The "run or maintain" philosophy guarantees an annual opportunity to replace
relief
valves for testing and re-certification. The facility of the disclosure thus
allows the
design to be simplified, whereas all risks associated to "hot swapping" are
eliminated.
Conventionally, column type process equipment 300 is provided with a reboiler
306 and associated pump 308 (Fig. 19). Typical combinations of reflux drum 306
and
associated pump 308 usually involve significant amounts of complexity.
Overhead
vapor is typically condensed in a cooler 304, typically an air cooled heat
exchanger.
The cooled and condensed liquid is supplied from the heat exchanger 304 as a
liquid
to a condenser vessel 302. The liquid is pumped back into the column 300 by
pump
310.
In an improved embodiment, shown in Fig. 20, the condenser vessel 302 is
arranged above the column 300. The condenser vessel 302 may be integrated in
the
top part of the column. Herein, a cooling heat exchanger 316 is arranged at a
gravitationally higher level than the condenser vessel 302. Warmed vapor will
rise
from the column to the heat exchanger 316, while cooler recondensed liquid
will
drop, by gravity, from the heat exchanger 316 to the condenser vessel 302.
Thus, reboiler pumps 310 can be eliminated. Optionally, the condenser vessel
302 may be connected to the top of the column 300 via a thermosiphon 314. In
cases
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where 100% reflux is required (typical knock-back arrangements), the liquid
stream
from the overhead condenser 302 (which may be arranged at the top level of the
integrated process units 100, 110. See Figs. 3, 4) can be routed back into the
vessel
300, which is arranged in the same column shell as the condenser vessel 302.
The
small pressure differential across the condenser can be broken by a simple
gravity-
based siphon 314. Alternatively, the condenser vessel can be connected to the
column 300 via a dip tube from column top to the top tray like a downcomer.
If the gas/liquid mixture from the overhead condenser 302 can be sufficiently
separated inside the condenser 302, the top vessel might be eliminated as
well. If
some of the liquid must be removed from the process (for instance water
control), a
simple draw-off tray might be applied.
In addition, the concept of Gas plant in a Bottle, as marketed by Ortloff
Engineers Ltd. (Texas, USA), for instance for the demethaniser. Such
integration of
heat- and mass-transfer into a single pressure shell greatly simplifies plant
complexity and floor space.
In an embodiment, relatively small and compact equipment is selected to suit
the plant sections made up of relatively compact building blocks. This
replaced the
conventional approach of relying on economy of scale, in particular for stick-
built
plants. Instead, smaller, more intensive equipment has been selected in order
to be
able to fit more items inside respective building blocks 150 of a limited size
and
weight. Using smaller units and keeping selected pieces of equipment
integrated in
the same building block, minimizes the number of piping connections to be made
at
the site of the production location.
As an example, Fig. 21 shows an amine filter unit 320 as a compact building
block 150, provided with a support frame 162. In a practical embodiment, the
amine
filter 322 is enclosed by a support frame 162 having a size substantially
compatible
with, or fitting in, a standard (for instance 20 feet) freight container. The
support
frame 162 can hold a single vessel 322. Thus, the filter forms a "cartridge",
suitable
for plug and play type application. Connections are standardized and limited
as much
as possible. Optionally, a small circulation pump (not shown) may be
integrated in
the frame 162, to be maintained at every cartridge swap. If fitted in a low-
pressure
part of the system, such cartridge or compact building block 150 can be
replaced in a
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matter of hours, and cost effectively transported by a standard truck and/or
container
ship to the original equipment manufacturer (OEM) or service center (Fig. 10).
In an embodiment, selected pieces of process equipment, such as the gas
turbine and refrigerant compressor, can be included in a separate integrated
process
unit 120. This for instance enables the compression system to be fully tested
up to a
nitrogen test run stage at the construction or assembly location. The extra
level of
commissioning and testing at the construction or assembly location is
beneficial in
reducing the amount of carry-over work that has to be done at a significantly
higher
labor rate at the production site. The variable speed nature of the aero-
derivative gas
turbines simplifies the compressor start-up and eliminates the need to
depressurize
refrigerant. Removing the need for starter/helper motors for gas turbines used
in prior
art LNG trains also significantly reduces the maximum electrical power demand
of
the LNG train of the present disclosure and helps to limit the size of the
compact
building blocks 150.
As described above, the LNG production train 3, 4 of the present disclosure is
suitable for operation in a normally unmanned mode. During turn-around, the
train is
manned and checked by operators. The LNG production trains of the disclosure
allow automated start-up from maintenance to normal operation, and automated
shut-
down for maintenance.
In the start-up procedure it is important to define the moment, at which the
unit
is handed over from the turn-around crew to operations. At this point the unit
may be
unmanned and the automatic start-up procedure takes over. As an example of
startup
of the gas treatment unit 100, it is assumed that the unit is handed over dry
and
leakage tested. Automatic startup, operation, and shutdown will be described.
Other
process sections of the LNG production train 3 or 4 may be likewise automated.
The first step to be reviewed is oxygen freeing of the unit. It is proposed to
execute this task by pulling a vacuum on the unit and then fill the unit with
nitrogen
(see Fig. 12). Solvent is filled next. Ramping up of solvent, regenerator
temperature
and feed-gas flow can be achieved by sequences in the control system.
At this point the system can switch into normal operation and allow advanced
process control loops to take over the optimization of the system in order to
achieve
the required treated gas specifications. A slow ramp up of the treated gas
flow for the
first one or two days of operation might be required.
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Similar sequences can be applied for startup of the unit after a short stop.
The
system will need to have the required diagnostic tools to judge from which
step in the
startup procedure the sequence needs to be initiated. Potential parts of the
diagnostic
tools could be pressures and temperature in absorber, flash and regenerator
and
solvent levels.
Operator rounds may be done to detect undesired conditions and allow timely
intervention. Issues like local instruments readings, leakages or vibration
noise at a
pump are typical issues to check during a round. A number of these can be
detected
by additional instrumentation like:
- Liquid detection, or leak detection, on drain points 256, 254 in the liquid
containment under the unit;
- Camera systems, which allow for monitoring of critical areas. The camara
systems may record video data of preselected critical areas, and provide the
video
data to a monitoring system. The monitoring system may be provided with an
algorithm to detect aberrations in the video data, which may for instance
correspond
to a potential leak. If the algorithm detects a potential leak in the video
data, the
monitoring system raises an alarm. Herein, the video camera may be coupled to
an
Analytic Video Monitoring System for Automated Real-Time Detection and Alarm
Generation in Industrial Applications, such as marketed by Intelli View
Technologies
(Calgary, Alberta, Canada). An alternative automatic video monitoring system
is
marketed by FLIR Systems, Inc. (UK);
- Noise detection systems, which may trigger zoom-in by the camera system.
Noise detection systems herein may include sound sensors (microphones) to
detect
sounds, coupled to a monitoring algorithm to raise an alarm in case unwanted
sounds
are detected;
- Vibration monitoring using sensors. Herein, the sensors to monitor vibration
may include vibration sensors to detect vibrations, coupled to a monitoring
algorithm
to raise an alarm in case the detected vibrations exceed a predetermined
safety
threshold.
Additional robotic systems could be employed for special monitoring tasks.
Again referring to the gas treatment unit 100 as an example, shutdown of the
LNG production process may be at least partly automated. Several levels of
shut
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downs can be defined. In a first step of shutdown, only the feed gas flow
would be
shut in. No special additions to the design are required to restart.
In a next step of shutdown, a reboiler and amine circulation would be stopped.
In order to recover from this state, a sequence, which re-establishes the
amine
circulation and ramps up the duty to the reboiler in line with ramping up the
feed gas
may be required.
For a full shut down in preparation for a maintenance period or turn-around,
the following sequence may be suitable:
- Close gas supply and discharge line. Circulation of the solvent and
operation
of the regenerator can continue for a certain time to ensure regeneration of
the
solvent.
- Shut down of the reboiler. When the acid gas flow has
decreased, close acid
gas discharge. Stop the condenser and reflux system.
- Continue circulation of the amine until the whole solvent has been cooled
down.
- Shut down solvent coolers.
- Pump-out of solvent via the booster pump into the amine storage tank.
- Upon reaching LZA-LL on the main amine levels, drain out the solvent.
Automatic draining of, for instance, solvent may be done using automatic
valves 254 on drain connections 256 from the vessels and low points. During
draining, nitrogen 242 may be admitted into the system or process section 238
to
maintain an inert atmosphere. Therefore, in an embodiment the system includes
a
permanently hooked up nitrogen connection 242. In order to empty the process
section 238, the process section can be slightly pressurized with gas to push
out
liquid. Automatic flushing of the system with demineralized water is an
optional
additional step.
The arrangement of the process equipment across each integrated process unit
in the illustrated embodiments may be optimized to provide integrated process
units
of total weight in the order of 2000 to 8000 tons, preferably 3000 to 4000
tons. The
capacity of the train is around 2 to 5 million tons per annum (mtpa) of LNG
production. If a higher capacity is desired at a particular production
location, two or
more LNG production trains may be provided in combination. By way of example,
two trains 3A, 3B according to the present disclosure may be arranged at a
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production location to provide an overall LNG production capacity of, for
instance, 4
to 10 mtpa.
The production location can be onshore, offshore on a floating facility,
offshore
on a fixed facility, or a barge-mounted or grounded facility. By way of
example, the
compact building blocks may be floated-in using steel or concrete gravity
based
structures with integrated LNG storage, loading and boil-off gas re-
liquefaction
functionality. Gas may be supplied to the production location via a (subsea)
pipeline.
The LNG plant may further include optional treatment steps such as product
purification steps (for instance helium removal, nitrogen removal, mercury
removal)
and non-methane product production steps (de-ethanizing, de-propanizing,
sulphur
recovery) if desired. The natural gas feed stream may be produced at and
obtained
from a natural gas or petroleum reservoir. As an alternative, the natural gas
feed
stream may also be obtained from another source, also including a synthetic
source
such as a Fischer-Tropsch process wherein methane is produced from synthesis
gas.
The present disclosure involves a number of technologies and a step out
operational and maintenance philosophy to allow for a significant reduction in
CAPEX. Capital expenditure may be in the order of 30% compared to CAPEX of a
typically stick built LNG production train (i.e. a cost reduction of about
70%). The
step out operational philosophy may be referred to as "remote operation" or
"normally unmanned installation".
Remote operation allows a particular part of the plant (such as the processing
units) to be operated from a distance. This in turn allows staff to be located
and to
work in and from, for instance, an urban area rather than from a remote area.
This
allows for a cost reduction related to facilities for staff, and in addition
reduced
operating costs. Also, this may significantly increase job satisfaction for
staff while
also limiting staff turnover.
The step out maintenance philosophy may be referred to as run or maintain.
The run or maintain operation involves the removal of installed spares and the
surrounding valves and piping and consequently allows for a reduction in
construction scope and associated costs.
The "frugal" concept per embodiments disclosed above revolve around
replacing a century-old petroleum industry design approach that is geared to
"keep
running at all times" and "operating by (fallible) humans". This traditional,
so far
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unchallenged hybrid is inherently error-prone and leads to increasingly
complicated
and costly plant designs and associated organizational practices. In the order
of 80%
of the trips and downtime in the LNG industry may be the result of human
error. The
"frugal" design philosophy combines one or more features of the embodiments
described above. The concept is particularly beneficial for newly built, small
and
mid-sized LNG facilities (in the order of I to 3 mtpa, for instance about 2 to
2.5 mtpa
per train) are ideally suited for the Frugal class of operations. The concept
disclosed
herein may comprise:
- Run the facility using a run or maintain (Either operate or maintain)
schedule.
This schedule comprises the step of periodical maintenance including
replacement of
selected hardware for offline renovating. This obviates the need for thousands
of
hardware provisions and associated opportunities to induce incidents. The
design
includes means to provide very rapid transitions between the operational state
and a
fully product free state;
- Remove human error and related process upsets by application of Fully
Autonomous Process Control, to enable a process design in the simplest
possible
way;
- Enhanced Process Safety by reducing or eliminating flammable inventory
and
physically separating the human operators from hazard (unmanned operation).
It is stressed, that although the concepts of the embodiments described above
introduce simplicity in the design and operation of the LNG facility, actual
implementation is a significant organizational challenge in an industry
heavily reliant
on proven technology concepts due to risk avoidance because of the combination
of
handling vast amounts of flammable or even explosive material (hydrocarbons)
and
significant upfront investment (in the order of billions of USD per project).
Yet, the estimated benefits of the application of one or more of the concepts
and embodiments described above, alone or in various combinations, may provide
up
to:
- CAPEX reduction up to -40% on a USD/tpa basis (compared to facilities
constructed in the last decade);
- Further CAPEX reduction through staged investment (staged installation of
multiple relatively simple trains to together form a larger plant;
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- OPEX reduction up to -50% (compared to facilities constructed in the last
decade) due to a reduction or elimination of local organizations and the
unmanned
concept;
- Faster construction and deployment (within planned schedule) due to "plug
and play" of compact building blocks. Reduction of unforeseen delay and
additional
work;
- An improvement of process safety by up to 1 to 3 orders of magnitude (due
to
non-flammable refrigerants, elimination of opportunities to create incidents,
almost
complete elimination of personnel on site).
The present disclosure is not limited to the embodiments as described above
and the appended claims. Many modifications are conceivable and features of
respective embodiments may be combined.
The following examples of certain aspects of some embodiments are given to
facilitate a better understanding of the present invention. In no way should
these
examples be read to limit, or define, the scope of the invention.
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