Note: Descriptions are shown in the official language in which they were submitted.
1
Title of the Invention
A Liquefied Natural Gas terminal
Technical Field
The present invention relates to Liquefied Natural Gas (LNG) terminals
comprising floating
storage structures.
Background Art
Construction of Liquefied Natural Gas (LNG) terminals are often complex and
capital-
intensive due to various reasons such as; land usage, regulatory restrictions,
construction
costs and time, access to resources and productivity constrains during
construction, LNG
storage availability and end of life de-commissioning.
Several of these problems are currently solved by employing floating storage
structures.
Figure 1 is a schematic representation of an import LNG terminal involving
floating storage
structures. This terminal involves a large finger jetty with two floating
storage structures
arranged on either side of the jetty. The two floating storage structures
provide the LNG
terminal with higher redundancy, should one of the structures be unavailable
due to
maintenance or down-time. The jetty also has arrangements to allow berthing of
a LNG
carrier and transfer systems to allow the discharge of LNG from the LNG
carrier to the
floating storage structures. The floating storage structures will then
transfer LNG to an
onshore re-gasification facility that in turn will feed natural gas (NG) to
the consumers.
Deep water shorelines are considered beneficial for LNG terminals because the
jetty, or quay,
can be close to shore and allow berthing of large vessels without the need for
changes to the
seabed. Dredging the seabed in order to increase the depth of canals in the
way to, or at the
berth, has become increasingly difficult due to environmental restrictions and
high costs.
However, an excessively inclined seabed can become a design challenge because
such seabed
does not allow the use of conventional piling or earthing during construction.
Accordingly, the solution in Figure 1 is not suitable for steep shorelines
with deep water
bathymetry, such as sites in mountainous areas. In these locations, the seabed
is heavily
inclined and as a result the water depth increases significantly even at short
distances from
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the shoreline. In Figure 1, the hull orientation requires a long jetty in
order to accommodate
the three hulls that can berth at one time. This solution is not feasible for
steep shorelines
with deep water or other locations that can restrict the length of a jetty,
i.e. narrow channels.
Other types of jetties are also know, such as one shown in Canadian patent
application
publication 2842621, which discloses a LNG export terminal with a twin-hull
floating storage
and offloading vessel (FSO). However, this LNG export terminal requires the
construction of
large jetty structures around the twin hull FS0s, and such an arrangement is
not conducive
for use in sites with steep shorelines. In addition, by joining both hulls
together, the units are
not redundant and the failure in one of them can lead to a total loss of
storage.
A drawback with conventional LNG terminals comprising floating storage
structures is their
use of converted LNG carriers as floating storage structures. Most LNG
carriers are designed
for one purpose only, to transport LNG from a loading port to a discharge port
in the most
efficient way. As a result, when designing the LNG cargo handling system on
the LNG
carrier, the systems are required to carry out only one operation at a time.
Conventional
floating storage structures converted from LNG carriers can therefore handle
either loading or
offloading LNG, and never both at the same time. Although floating storage
structures built
from converted LNG carriers are typically cheaper and require less time to
build, the LNG
terminal may end up with a bottleneck in operations due to their inadequacy
for simultaneous
loading and offloading. Such bottlenecks may lead to increased down-time and
slower
loading or offloading from the LNG carrier, leading to a disruption in
operations at the LNG
plant and a stop in the continuity of LNG production which increases costs
heavily.
Furtheiniore, conventional LNG carriers are required to dry-dock every 2.5 to
5 years,
depending on age, in order to carry out out-of-water hull surveys, as well as
other
requirements to inspect and/or test the integrity of cargo tanks, safety
systems, hull structure,
etc. The LNG carriers are required to be in gas free condition prior to
entering a shipyard, and
are therefore required to have means onboard that allow them to purge, inert
and eventually
free all cargo tanks of gas prior to arrival. For floating storage structures
converted from LNG
carriers, the same will apply. The floating storage structures thus require
gas freeing
equipment on board requiring maintenance, and replacement floating storage
structures are
required during periods of dry-docking, thus driving up costs.
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The prior art does not show an LNG terminal with high loading and offloading
capacity,
availability and reliability, and simultaneously being suitable for deep water
shorelines.
Accordingly, a solution for LNG terminals in deep water shorelines with
improved
availability and reliability is needed.
Summary of the Invention
With the abovementioned challenges and known solutions in mind, the present
invention
provides an LNG terminal which overcomes the drawbacks in the prior art. The
new and
inventive LNG teiminal herein thus comprises an onshore LNG facility, at least
one floating
storage structure, a permanent mooring system, a jetty and a pipeline system
arranged in a
manner allowing for improved loading and offloading, availability and
reliability, and
simultaneously being suitable for areas where a long jetty is not feasible.
Thus, it may be advantageous provide an LNG terminal for deep water shorelines
with higher
redundancy, as it is capable of accommodating a plurality floating storage
structures.
Furthermore, the floating storage structures comprise of a multitude of
independent storage
containers, therefore issues with any one container should not affect the
operability of the
terminal.
More specifically, it may be advantageous to provide an LNG terminal with a
jetty allowing
for a plurality of floating storage structures to be arranged with an
orientation that does not
require the construction of long jetties, and therefore the invention is
suitable for sites with
steep shorelines and deep water.
Further, it may be advantageous to provide an LNG tenninal with simpler
floating storage
structures, since means for production and distribution of electric power,
utilities, controls,
LNG processing and BOG collection and management are handled at the onshore
plant.
The floating storage structures will thus have lower building costs, as well
as lower operating
costs due to reduced maintenance required for redundant equipment on board the
structures.
Further, it may be advantageous to provide floating storage structures which
are capable of
simultaneous loading and offloading from and to the LNG plant and LNG earner.
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Further, it may be advantageous to provide a system capable of isolating,
purging, inerting
and gas freeing any storage container on a floating storage structure without
having to do the
same with the rest of the operational storage containers. In this way, the
floating storage
structure can remain operational even if one or more storage containers are
opened for
inspection and/or repairs.
The present invention provides significant improvements in relation to known
solutions, as a
an LNG terminal comprising floating storage structures with low costs, high
reliability and
high availability can be provided for areas where long jetties are not
feasible for technical
and/economical reasons.
Accordingly, the present invention relates to LNG terminal, the terminal
comprising:
- an onshore LNG facility,
- at least one floating storage structure, the at least one floating
structure comprising
an elongated shape with a first end and a second end,
- a permanent mooring system for mooring the at least one floating structure,
- a jetty, the jetty extending in a longitudinal direction from a shoreline
out into a
body of water and terminating at a loading jetty portion, the loading jetty
portion comprising
a first mooring arrangement for mooring an LNG carrier and an external
transfer system,
- the jetty further comprising at least one internal transfer system, the at
least one
internal transfer system being arranged at a point along the length of the
jetty between the
shoreline and the loading jetty portion,
- a pipeline system adapted for transporting hydrocarbons between the
onshore LNG
facility, the at least one internal transfer system and the external transfer
system,
wherein the floating structure is connected to an internal transfer system at
the first end of the
floating structure, and where the floating storage structure is moored such
that the second end
is oriented in an angle substantially perpendicular to the longitudinal
direction of the jetty.
The angle between the jetty and at least one floating storage structure may be
defined herein
as the angle defined by a line running through the center of the jetty in the
longitudinal
direction of the jetty, and a line running through the center of the at least
one floating
structure in the longitudinal direction of the at least one floating
structure. A substantially
perpendicular angle may be defined herein an angle diverging up to +/-30
degrees from a
strictly perpendicular angle of 90 degrees between the jetty and the floating
storage structure.
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Such angle allows the floating structures to adjust to the shoreline
configuration and maintain
the advantages of a short jetty.
Thus, an LNG terminal can be provided in deep water shorelines or areas where
a long jetty
is not feasible, whilst providing for the use of low cost floating storage
structures with high
reliability and availability.
The jetty extends from land or the onshore LNG plant to a water body in one
direction, and
the length of the jetty may be considered the distance from the shoreline to a
distal end,
typically the end of a loading jetty to which the LNG carrier is moored.
Examples of water
body include, but are not limited to, sea, lake and water channel. In the
context of various
embodiments, the term jetty may refer to a dock, a harbour, a pier or a
structure projecting
into a sea or water body for mooring, docking or berthing sea-going vessels.
Examples of
jetty include, but are not limited to, finger jetty, quay, and T-shaped jetty.
The jetty may be T-
shaped as the loading jetty may be wider than the main jetty part extending
out to the loading
jetty, but the loading jetty will preferably not be wider than the length of
the jetty. The
loading jetty's width is advantageously adapted for mooring of the LNG
carrier, however the
construction of the loading jetty is also subject to technical and cost
considerations. A long
jetty may be considered as extending up to a mile from the shoreline, and a
short jetty being
considered as a jetty which is too short for parallel mooring of an elongated
floating storage
structure, the storage structure typically being a converted LNG carrier.
Short jetties may be
required due to geotechnical considerations or other considerations e.g. due
to insufficient
width of the body of water such as in a river. The invention may be especially
beneficial for
shorelines where the depth abruptly increases at a short distance from shore,
herein referred
to as steep water shorelines, thus making long jetties difficult to build as
the water may be so
deep that any foundations will be technically challenging. Normally
conventional pile with
concrete cap jetty design is feasible to up to 30 meters water depth, for
deeper waters jackets
i.e. structural towers need to be used. However, the cost of manufacturing and
installing
jackets increase significantly with their height, which depends on water depth
and seabed
conditions. Therefore, it is desirable to reduce the length of jetties in
steep or/and deep
shorelines. Shorter jetties may also be preferably due to lower capital and
operational costs. A
shorter jetty will require less LNG piping and handling systems thus reducing
costs, it will
also be beneficial for operations as they are not spread out over a large
area. Less LNG piping
will also reduce BOG production, thereby resulting in a more efficient LNG
terminal. The
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length of the jetty will thus be dependent on these technical challenges and
economic
considerations, which will be apparent to the person skilled in the art based
on the
requirements of the specific site for the LNG terminal and the disclosure of
the invention
herein.
An onshore LNG facility may be defined herein as a facility comprising means
for liquefying
or re-gasification of natural gas, and may further include facilities for
producing, processing
and/or storing natural gas. Facilities for storing natural gas may include
land-based storage
tanks. The term tank may refer to cargo tank, storage tank or any tank or
container which is
adapted to store or carry fluid, such as LNG. The onshore LNG facility
includes facilities for
re-gasification and further processing of LNG, and may further include
facilities for
producing, processing and/or storing other liquefied gases such as LPG, CNG or
hydrogen.
Facilities for storing natural gas may include land-based storage tanks.
The term floating storage structure may herein refer to floating storage tank
(FST), floating
storage unit (FSU), floating storage and offloading (FSO) unit, floating
production, storage
and offloading (FPSO) unit or any sea-going vessels having one or more tanks
or containers.
The floating storage structure may be a monohull vessel, i.e. a single hull in
contrast to the
catamaran hull shown in Canadian patent application 2842621. The floating
storage structure
may be a purpose-built floating storage unit or converted from an existing sea-
going vessel,
e.g. LNG carrier. The floating storage structure may include any one or more
types of tanks
onboard, e.g. International Maritime Organisation (IMO) Type A, Type B or Type
C tanks.
The term LNG carrier may refer herein to any receiving vessel which is to load
or offload
LNG depending on whether the LNG terminal is employed as an export or import
terminal.
The term transfer system refers herein to systems provided for transfer of
fluid between
structures or systems that are subject to relative motions therebetween, e.g.
jetty and LNG
carrier, jetty and floating storage structure. A transfer system may include
fluid pipelines,
support structure for supporting the pipelines, and mechanical and/or
electrical system for
moving or manipulating the pipelines. These pipelines may comprise flexible
pipes e.g.
flexible hoses, and/or articulated connections e.g. rigid arms with swivels or
bellows. The
internal transfer system refers to a transfer system for onloading and
offloading LNG
between the floating storage structures and either of the LNG carrier and
onshore LNG
facility.
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The permanent mooring system is configured to maintain the floating storage
structures in
position. Examples of a permanent mooring system include, but are not limited
to, a strut arm
system, piling system, wire systems, chain and anchor spread system, and pre-
tensioned
anchor system, etc. In some embodiments, at least part of or some components
of the
permanent mooring system may be provided at the jetty, thus mooring a floating
storage
structure to the jetty. The floating storage structures are moored to the at
least one permanent
mooring system to allow safe operations for extended period of time.
The floating storage structure is preferably elongated, such that it comprises
a width and a
length. The orientation of the floating storage structure may therefore also
be described as
having a width arranged alongside the jetty and having the length of the
floating storage
structure substantially free of the jetty. The floating storage structure will
thus preferably be
substantially parallel to a shoreline, or an underwater steep inclination
which typically
follows the shoreline. This orientation will also typically be in an angle non-
parallel to the
jetty. Thus, the floating storage structures may be safely and reliably moored
to a short deep
water jetty.
In an aspect of the invention, the at least one floating structure may
comprise a second
mooring arrangement for mooring the LNG carrier to the floating structure.
Since the LNG
carrier and the at least one floating structure will be substantially
parallel, mooring lines may
be used to moor the LNG carrier to the at least one floating structure.
In an aspect of the invention, the LNG carrier may be moored to at least one
dolphin
mooring. Dolphin moorings being defined herein as a marine structure that
extends above
water level and is preferably not connected to shore, and which are known in
the art.
In an aspect of the invention, the pipeline system may comprise a loading
system extending
between the onshore LNG facility and the at least one internal transfer
system. In an aspect of
the invention, the pipeline system may comprise an offloading system extending
between the
at least one internal transfer system and the at least one external transfer
system. In an aspect
of the invention, the pipeline system may comprise a vapor system extending
between the
onshore LNG facility, the at least one internal transfer system and the
external transfer
system. Advantageously, the pipeline system may thus handle continuous loading
and
offloading of LNG and boil off gas may thus be continuously managed, collected
and
returned to shore. thereby decreasing occurrences of LNG processing at the
onshore plant.
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In an aspect of the invention, the jetty comprises at least two internal
transfer systems, the at
least two internal transfer systems being arranged on opposite sides of the
jetty in the jetty's
longitudinal direction. In some aspects, the floating storage structures may
be arranged on
both sides of the jetty, i.e. the jetty is interposed between the floating
storage structures,
wherein each of the floating storage structures may have a width arranged
alongside the jetty
and having length substantially free from the jetty.
In an aspect of the invention, the terminal may comprise at least two floating
storage
structures, wherein each internal transfer system is connected to a separate
floating storage
structure. The use of more than one floating storage structure provides
redundancy to the
storage solution, so storage is always available even if one floating storage
structure is out of
service.
In an aspect of the invention, the LNG terminal may comprise at least two
floating structures,
wherein the terminal comprises at least two floating structures, wherein at
least one first
floating structure is connected to an internal transfer system at a first end
of the floating
structure, and a second floating structure is connected to the second end of
the first floating
structure. Thus, should only one side of the jetty have favorable conditions
for mooring
floating storage structure, the temtinal may still be provided with a
plurality of floating
storage structures for redundancy.
In an aspect of the invention, the at least second floating structure may be
moored in a
substantially similar longitudinal direction as the first floating structure.
In aspects where two
floating storage structures are provided, the floating storage structures may
be arranged in
tandem to one another, i.e. end-to-end or one following the other in a
lengthwise direction of
the floating storage structure, and may be further arranged such that the
starboard and port
sides of each floating storage structure are generally free of the jetty, i.e.
the starboard and
port sides of each floating storage structure are not arranged alongside the
jetty. The floating
storage structures may thus be arranged on a same side of the jetty, where a
first of the
floating storage structures has a first width arranged alongside the jetty
length and the
starboard and port sides generally free of the jetty. A second of the floating
storage structures
has a second width arranged proximate to the aft or forward end of the first
floating storage
structure and the starboard and port sides generally free of the jetty.
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In an aspect of the invention, the at least one second floating structure may
be connected to
the pipeline system via the first floating structure.
In an aspect of the invention, the onshore LNG facility may comprise
facilities for boil-off
gas BOG collection and management.
In an aspect of the invention, the onshore LNG facility may comprise
facilities for controlling
the LNG terminal. The control facility may include devices and systems for
controlling at
least some of the facilities and/or systems comprised in the LNG plant and/or
near shore
LNG terminal.
In an aspect of the invention, the onshore LNG facility may comprise
facilities for electric
power generation. The onshore power facility may include facilities for power
generation,
power storage facility and/or power transmission. Provision of electrical
power and utilities
from shore systems significantly reduces the refurbishment and conversion
costs as well as
the operational costs related to the maintenance of redundant equipment that
would normally
be onboard ships operating as floating storage structures.
In an aspect of the invention, the onshore LNG facility may comprise
facilities for producing,
processing and/or storing utilities, wherein utilities comprise any of:
nitrogen, water, cooling
water, compressed air, instrument air, heating and drainage collection.
Utilities may further
comprise missing inert gas, warm natural gas, firefighting means, pneumatic or
hydraulic
fluids or any alternative means of transferring power.
In an aspect of the invention, the jetty may comprise means for transferring
between the
onshore LNG facility to the at least one floating storage structure, any of:
electric power,
control signals and utilities. Integration of the floating storage structures
with the onshore
LNG plant will allow the floating storage structures to be operated from a
shore main control
room in the same manner as a conventional land-based tank, and drastically
reduce the need
of personnel onboard the floating storage structures.
In an aspect of the invention, the at least one floating storage structure may
comprise a
plurality of storage containers. A floating storage structure may thus
comprise of a multitude
of tanks or containers, therefore issues with any one tank should not affect
the operability of
the plant.
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In an aspect of the invention, the at least one floating storage structure may
comprise a cargo
management system arranged to load and offload LNG from selected storage
containers. This
beneficially provides:
- Continuous inflow or rundown of LNG (loading) from the shore production
facility (in the
case of a liquefaction plant) or from an LNG carrier (in the case of a
receiving plant).
- Cargo inventory management; by nominating the tanks where incoming LNG
will need to
be allocated into, or by internal tank to tank transfers.
-Discharge LNG from nominated cargo tanks onto a receiving LNG carrier (or
shuttle vessel
in the case of a liquefaction plant) with the purpose of transporting LNG to
other markets or
to a re-gasification process plant.
In an aspect of the invention, the at least one floating storage structure may
comprise an inert
gas system arranged to provide inert gas and dry air to selected storage
containers. On
conventional ships, it is normally not possible to inert and gas-free some of
the cargo tanks.
In contrast, the invention provides an inert and gas free system that is
capable of isolating,
purging, inerting and gas freeing any tank without having to do the same with
the rest of the
operational tanks. In this way, the floating storage structure can remain
operational even if
one or more tanks are opened for inspection and/or repairs.
Throughout the description and claims different words and terms are used, the
definitions of
these and other characteristics of the invention will be clear from the
following description of
a preferential form of embodiment, given as a non-restrictive example, with
reference to the
attached drawings wherein;
Brief Description of Drawings
Figure 1 shows an existing LNG terminal configuration;
Figure 2A shows a LNG terminal configuration having two floating storage
structures
arranged on both sides of a jetty according to one embodiment of the
invention;
Figure 2B shows a LNG terminal configuration having two floating storage
structures
arranged on same side of a jetty according to one embodiment of the invention;
Figure 2C shows FSOs oriented in various angles substantially perpendicularly
to the jetty.
Figure 3 shows a loading and an offloading liquid system;
Figure 4 shows piping arrangement at each tank interface of a floating storage
structure;
Figure 5 shows a vapour return system;
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Figure 6 shows a cooldown system;
Figure 7 shows an inert gas and gas freeing system;
Figure 8 shows a LNG terminal employed as an export terminal;
Figure 9 shows piping arrangement of the jetty portion; and
Figure 10 shows additional piping arrangement of the jetty portion.
Detailed Description of the Invention
The inventive concept will now be described more fully hereinafter with
reference to
the accompanying drawings.
The floating storage structures G1 are moored to the at least one permanent
mooring
system G8 to allow safe operations for extended period of time. Figures 2A and
2B show a
jetty 4, the jetty 4 extending in a longitudinal direction from a shoreline 5
out into a body of
water 6 and terminating at a loading jetty portion 7, the loading jetty
portion 7 comprising a
first mooring arrangement 8 for mooring an LNG carrier G2 and an external
transfer system
G6. The jetty 4 further comprises at least one internal transfer system G5,
the at least one
internal transfer system G5 being arranged at a point along the length of the
jetty between the
shoreline 5 and the loading jetty portion 7. Figures 2A and 2B also show a
pipeline system 9
adapted for transporting hydrocarbons between the onshore LNG facility G7, the
at least one
internal transfer system G5 and the external transfer system G6.
In some embodiments where two floating storage structures G1 are provided, the
floating storage structures G1 may be arranged in tandem to one another, i.e.
end-to-end or one
following the other in a lengthwise direction of the floating storage
structure (ii, and may be
further arranged such that the starboard and port sides of each floating
storage structure G1 are
generally free of the jetty 4, i.e. the starboard and port sides of each
floating storage structure
G1 are not arranged alongside the jetty 4. In the embodiment of Figure 2A, the
floating storage
structures G1 are arranged on both sides of the jetty 4, i.e. the jetty 4 is
interposed between the
floating storage structures Gl, wherein each of the floating storage
structures G1 having a
width 2 arranged alongside the jetty 4 and having the starboard and port sides
generally free of
the jetty4. In the embodiment of Figure 2B, the floating storage structures G1
are arranged on
a same side of the jetty 4. In other words, a first of the floating storage
structures G1 has a first
width 2 arranged alongside the jetty 4 length and the starboard and port sides
generally free of
the jetty 4. A second of the floating storage structures G1 has a second width
2 arranged
proximate to the aft or forward end 3 of the first floating storage structure
G1 and the starboard
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and port sides generally free of the jetty 4. Figures 2A and 2B also show
mooring lines 10
connecting the LNG carrier G2 to the loading jetty 7 and floating storage
structures Gl.
In some embodiments, the length of each floating storage structure G1 may be
generally
non-parallel to the jetty length 4. In some other embodiments, the length of
each floating
storage structure G1 may be generally parallel to a shoreline.
Fig. 2C schematically illustrates different aspects of the angle of
orientation of two floating
storage structures relative to the jetty. The aspect to the right in the
Figure 3 illustrates two
floating storage structures oriented in a strict perpendicular angle relative
to the jetty, where
the angle is 90 degrees. Whilst the aspect in the left and middle, illustrate
diverging aspects
where the angle may diverge up to 30 degrees from strictly perpendicular. The
dashed lines
illustrate the centrelines of the floating storage structures and the jetty
respectively.
A loading system shown in Figure 8 is provided and operative to fluidly
connect the
onshore plant G7 to one or more floating storage structures G1 for performing
loading
operations when the LNG terminal 1 is employed as an export terminal. More
particularly,
the liquid loading system Fl is operative to fluidly connect the onshore plant
G7, e.g. LNG
facility or land-based storage tank at the LNG plant, to one or more cargo
tanks G3 at one or
more floating storage structures Gl. The loading system Fl (or first set of
pipelines) in Figure
3 comprises one or more internal transfer system for loading L5, one or more
loading lines
Li, one or more branch-off lines L9 and one or more filling lines L12 as shown
in Figure 4.
Reference is made to Figures 3, 4 and 9 wherein each floating structure is
provided
with a loading line Li, one or more loading branch-off lines L9 and one or
more filling lines
L12. The loading line at the jetty JL1 is operative to fluidly connect the LNG
plant G7 e.g.
LNG facility or land-based storage tank at the LNG plant, to each of the
floating storage
structure's internal transfer system for loading L5. On each floating storage
structure, the
internal transfer system for loading L5 which is operative to fluidly connect
to a loading line
Ll. The loading line Li is operative to fluidly connect the internal transfer
system for loading
L5 to one or more branch-off lines L9. Each branch-off line L9 is operative to
fluidly connect
the loading line Li to one or more filling lines L12. Each filling line L12 is
operative to
fluidly connect a branch-off line L9 to a storage tank G3.
In some embodiments, a loading control valve L13 is provided and operative to
throttle, e.g. enable and/or modulate LNG flow or loading into any floating
storage structure
or isolate the floating storage structure, e.g. disable LNG flow.
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In some embodiments, the internal transfer system for loading L5 may be
located at
the jetty. In some embodiments, the internal transfer system for loading L5 is
operative to
fluidly connect to the loading line Li via a manifold. The manifold may be
located at the
midship or one of the ends of the vessel, e.g. bow or stern.
In some embodiments, the loading line Li comprises of necessary piping,
insulation,
valves, instrumentation and controls, to allow transfer of LNG from the
internal transfer
system for loading L5 to any one or more tanks L4 via loading branch-off lines
L9 and filling
lines L12.
In some embodiments, a loading control valve L10 is provided and operative to
throttle, e.g. enable and/or modulate LNG flow or loading into a respective
storage tank or
isolate the storage tank, e.g. disable LNG flow. The loading control valve L10
may be
provided at a loading branch-off line L9, e.g. operative to fluidly connect
the loading branch-
off line L9 to the respective filling line L12. The loading control valve L10
may be a remote-
controlled valve.
During a loading operation, the loading line JL1 receives LNG flow from the
LNG
plant G7 and directs the LNG flow to the internal transfer system for loading
L5 of any or all
the floating storage structures. The internal transfer system for loading L5
directs flow from
to the loading line Ll. The loading line Li receives the LNG flow and directs
the LNG flow
to one or more branch-off lines L9. Each branch-off line L9 receives the LNG
flow and
directs the LNG flow to one or more filling lines L12. Each filling line L12
receives the LNG
flow and directs the LNG flow to the respective tank G3.
An offloading system shown in Figure 8 is provided and operative to fluidly
connect
one or more floating storage structures G1 to a LNG carrier G2 berthed at the
LNG terminal
1 for performing offloading operations when the LNG terminal 1 is employed as
an export
terminal. More particularly, the offloading system F2 is operative to fluidly
connect one or
more storage tanks G3 at the one or more floating storage structures G1 to one
or more tanks
G3 at the one or more LNG carriers G2. The liquid offloading system may be
further
operative to fluidly connect various tanks within a same floating storage
structure for transfer
of LNG between the tanks. The liquid offloading system F2 may be further
operative to
fluidly connect storage tanks G3 of various floating storage structures G1 for
transfer of LNG
between these floating storage structures Gl, via an internal transfer system.
The offloading
system F2 (or second set of pipelines) comprises of interconnecting pipelines
JL2 at the jetty
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Figure 9 an internal transfer system for offloading L6 and one or more
offloading lines L2
Figure 4 on each floating storage structure Gl.
Reference is made to Figures 3, 4 and 9 wherein each floating structure is
provided
with a offloading line L2. The offloading line L2 is operative to fluidly
connect one or more
storage tanks to the offloading transfer system L6. The offloading line L2 is
separate from the
loading line Li to allow simultaneous and independent loading operation via
loading line Li
and offloading operation via offloading line L2. The internal transfer system
for offloading
L6 is operative to fluidly connect the offloading line L2 to the liquid line
at the Jetty JL2. The
offloading line JL2 is operative to fluidly connect and commingle LNG flow
from any one or
all floating storage structures. The liquid line or offloading line JL2 is
operative to fluidly
connect the commingled LNG flow to the LNG carrier through the external
transfer system
for offloading JL4. The external transfer system for offloading JL4 is
operative to fluidly
connect the offloading line JL2 to one or more cargo tanks of a LNG carrier.
In some embodiments, the internal transfer system for offloading L6 is
provided at the
jetty, e.g. installed at or fluidly connected to jetty offloading line JL2.
In some embodiments, the offloading line JL2 comprises of necessary piping,
insulation, valves, instrumentation and controls to allow for the transfer of
LNG from any one
internal transfer system for offloading L6 to another internal transfer system
for offloading
L6 to allow the transfer of LNG from any one floating storage structure to any
other floating
storage structure.
In some embodiments, the offloading line L2 comprises of necessary piping,
insulation, valves, instrumentation and controls to allow for the transfer of
LNG from any one
or more storage tanks G3 to another one or more storage tanks of the same
floating storage
structure, or for the offloading of LNG from any one or more storage tanks to
an internal
transfer system for offloading L6. From the internal transfer system for
offloading L6, LNG
can be transferred to storage tanks of another floating storage structure
through the jetty
liquid line JL2.
In some embodiments, LNG cargo pumps L11 are provided and operative to move or
transfer LNG out of storage tanks either for internal transfers to other
storage tanks or
offloading operations. LNG transfers between cargo tanks can be achieved by
pumping LNG
using the cargo pumps L11 from any storage tank through the offloading line L2
to the
targeted storage tanks by simply opening isolating valves L13 located at the
tank's filling line
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L12. Thus, LNG can be transferred to any one or more cargo tanks onboard on
any of the
floating storage structures and without affecting any ongoing loading
operations.
Prior to starting offloading operation, an offloading plan is prepared to
determine
ramp up and ramp down rates, as well as a predetermine offloading storage
tanks sequence.
Once the LNG carrier G2 is ready to receive LNG and the offloading line L2 and
JL2 and
transfer systems L6 and JL4 are cold (see cooldown system), offloading
operation
commences during which LNG is pumped from the pre-determined (offloading)
storage tanks
G3 using their submerged pumps L11 and distributed through the offloading line
L2 to the
internal transfer system for offloading L6 which may be provided at the
loading jetty, then
from the internal transfer system for offloading L6 to the jetty liquid line
JL2 and external
transfer system for offloading JL4 and finally from the external transfer
system for offloading
JL4 to the LNG carrier G2. The floating storage structure may employ one or
more external
transfer system for offloading JL4 depending on the type of offloading
transfer system being
used, flow and redundancy requirements.
LNG flowing through the external transfer system (s) for offloading JL4 will
be
distributed or allocated into tanks of the LNG carrier G2 based on the tank
arrangements of
the LNG carrier and offloading plan.
LNG flow to the LNG carrier G2 can be controlled by increasing or reducing the
pumps speed or number of pumps L11 in use and by throttling the valves located
at
discharges lines of each storage tank G3 that feed into the main offloading
line L2.
At the end of offloading operation, cargo pumps L11 are stopped, valves
closed,
piping and transfer systems drained warm up and inert if necessary.
A vapour system F3 shown in Figure 8 is provided and operative to fluidly
connect
the onshore plant G7, one or more floating storage structures G1 and one or
more LNG
carriers G2 for managing vapour or boil-off gas pressure during simultaneous
loading and
offloading operations. More particularly, the LNG carrier G2 is operative to
fluidly connect
to the onshore plant G7 and further to one or more floating storage structures
Gl. More
particularly, one or more carrier tanks of one or more LNG carriers G2 are
operative to
fluidly connect to the onshore plant G7 and further to one or more storage
tanks G3 of one or
more floating storage structures GL Vapour system F3 ensures that the overall
vapour
pressure at the floating storage structure and storage tanks G3 remains stable
and that all
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excess vapour generated onboard floating storage structures G1 and from
receiving LNG
carrier G2 during offloading operations is sent back to onshore plant G7 for
processing.
Reference is made to Figure 4, 5 and 9. The vapour system (or third set of
pipelines)
include an emergency release to flare V8, set of pipelines at the jetty JL3,
internal transfer
system for vapour VS, a vapour control valve V3, vapour header line VI or
first vapour line,
branch-off line V2 to each storage tank G3.
The vapour header line V1 is operative to fluidly connect one or more storage
tanks
G3 through a branch off-off line V2. The internal transfer system for vapour
V5 is operative
to fluidly connect the vapour header line Vito the jetty vapour line JL3. The
jetty vapour line
JL3 is operative fluidly connect the internal transfer system for vapour VS
from each of the
floating storage structures to the onshore plant G7. The vapour header line V1
is operative to
collect vapour produced by the storage tanks V4 via the branch-off line V2 and
direct the
vapour back to the onshore plant G7 via and internal transfer system for
vapour VS and jetty
vapour line JL3.
An emergency vapour release branch-off line V8 is provided to relieve pressure
from
the floating storage structures G1 and LNG carrier G2 to the onshore flare in
order to protect
storage tanks G3 and piping systems from over pressurization.
In some embodiments, another vapour control valve V7 is operative to fluidly
connect
the second vapour line JL3 to the floating storage structure(s) and distribute
at least some of
vapour flow into or stop all flow into the floating storage structure.
In some embodiments, a vapour control valve V3 is operative to fluidly connect
the
vapour header line Vito the internal transfer system for vapour VS and allow
controlled
transfer of some vapour returned from the LNG carrier G2 into the vapour
header line Vito
compensate for the volume displaced by LNG pumped out of the storage tanks G3
during
offloading and to maintain stable overall pressure and avoid tank over
pressurization or
vacuum.
During abnormal conditions, all the vapour can be redirected to a flare on
shore.
In some embodiments, the vapour header line V1 comprises of necessary piping,
insulation, valves, instrumentation and controls to allow collection of BOG or
vapour
produced by storage tank G3 of the floating storage structure G1 and direction
of the
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collected vapour to a compressor room in which the collected vapour would be
compressed
for re-liquefaction, or re-directed for fuel or to flare for burning (not
shown in figures).
In some embodiments, the compressor room may be located onshore, e.g. at LNG
plant, or at the jetty for easier modularization. In some other embodiments,
the compressor
room may be located at the floating storage structure.
In some embodiments, the internal transfer system for vapour V5 may be located
at
the jetty.
During loading operation, where LNG is transferred from onshore plant G7 to
floating
storage structure Gl, as the LNG enters a cargo tank G3, vapour (BOG) is
generated by
liquid flash, volume displacement and heat ingress. The vapour flows out of
the cargo tank
G3 through the branch off line V2 to the vapour header line VI, through
pressure control
valve V3 if any, through the internal transfer system for vapour V5 and
through the jetty
vapour line JL3 to shore. Additional BOG compressors on each floating storage
structure or
on the jetty are optional if the piping system cannot achieve free flow of
vapour back to
shore.
During offloading operation, where LNG is transferred from floating storage
structure
G1 to LNG carrier G2, a large amount of vapour is generated onboard the LNG
carrier G2,
which normally peaks at the start when the carrier tanks are empty and
relatively warm.
Vapour produced at LNG carrier tanks is pushed back to the floating storage
structure G1 by
the carrier's BOG compressors through its mid-ship manifold vapour return line
which is
fluidly connected to the external transfer system for vapour JL5. Some of the
vapour
produced at carrier tanks is used to maintain stable pressure of the storage
tanks G3 of the
floating storage structures Gl, this is achieved by vapour flowing into the
floating storage
structures though the jetty vapour piping JL3 and internal transfer system for
vapour V5,
vapour control valve V3 if any, vapour header line V1, branch-off lines V2 and
eventually to
the storage tanks G3. The excess vapour from LNG carrier continues its flow
through the
jetty vapour line JL3 to BOG compressors in the onshore plant G7. Shore BOG
compressors
ensure the overall BOG system pressure is maintained stable and any
malfunction will cause
the BOG to be re- directed to flare.
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During inter-tank transfers, the vapour is equalized by the natural flow of
vapour
between cargo tanks G3 as they remain fluidly connected through a normally
open vapour
header line V1 and branch-off lines V2
In case vapour pressure in the system breaches pre-set safety limits, a
release of
vapour is performed or activated through an emergency vapour branch off line
V8 into the
flare. If above system fails to activate, additional pressure protection
systems will release
excess pressure through an onboard vapour release mast or each of the cargo
tank's
independent pressure/vacuum protection valves V11.
A cooldown system comprises of necessary piping, insulation, valves,
instrumentation
and controls to allow all required cooldown operations on pipelines, storage
tanks, transfer
systems as required by the overall floating storage structure and plant design
requirements.
Reference is made to Figures 4, 6, 9 and 10. The cooldown system provides pre-
cooling of storage tanks G3 prior to loading operation by pumping LNG from any
of the
tank's cooldown pump C9 to the targeted storage tank's spray system C10 via
the cooldown
(spray) header line Cl.
The cooldown system also provides for pressure control in storage tanks G3 by
cooling down the tank's vapour space by pumping LNG into the target tank's
spray system
C10.
The internal return transfer system for cooling C5 can provide cooling
services to the
LNG plant thought the jetty cooldown line JC1.
A cooldown connection C8/S9 is provided to receive inert gas from the inert
gas
system (see Figure 7) for the purpose of decommissioning the cooldown system
or
maintenance operations.
A tie-in connection to loading and offloading system C6/L8 is provided to
allow
circulation of LNG to the offloading line Figure 3- L2, internal transfer
system for offloading
L6, jetty offloading line JL2 and external transfer system for offloading JL4
for pre-cooling
prior to any storage tank G3 transfer or offloading operations. The LNG is
circulated from
any cargo tank using cooldown pumps C9.
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Alternatively, LNG for cooling can be supplied by the onshore plant G7 from
the
loading line JL1 and tie-in connection JL6
A cargo tank spray system C10 operates by pumping LNG using the existing
cooldown pump C9 via the same tank's spray system C10 or send LNG to another
tank spray
system via the cooldown spray header Cl. The main purpose of the cooldown
system is for
tank cooldown in preparation for loading and/or to control the tank's internal
pressure by
cooling its vapour space.
In preparation for offloading operation, the cooldown system can be used for
the
initial cooling down of the offloading lines. To cool down the liquid lines,
LNG is pumped
from a source tank using the cooldown pump C9 and directed to the offloading
system F2 via
the tie-in to liquid system connection C6/L8. Through the tie-in connection,
LNG will flow
through the entire offloading line L2, internal transfer system for offloading
L6, jetty piping
JL2 and external transfer system for offloading JLS till the complete system
reaches the
appropriate temperature to allow safe offloading with cargo pumps L11.
Depending on the
floating storage structure's offloading frequency, the cooldown system can
also provide a
continuous recirculation to avoid the need of pre-cooling prior to every
offloading operation.
An inert gas system is provided to the floating storage structure Gl. The
inert gas
system provides inert gas and dry air respectively in connection with
isolation,
decommissioning, inspection and recommissioning of one or more tanks G3 while
maintaining the remaining tanks G3 in operation. It is also used for inert
spaces exposed to
NG ingress in case of storage tank leakage or even for corrosion prevention of
empty unused
spaces (void space) S5.
Type of inert gas used depends to specific requirements, cost of equipment and
availability of outside sources. Current application considers the use of
nitrogen or low
oxygen air as possible inert gas supplied from the onshore plant G7.
A dry air supply equipment can be installed on board or can be supplied from
shore
and the inert gas/air heater is optional to allow for faster operations.
In some embodiments, the inert gas system is provided at the jetty 4.
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Reference is made to Figure 3, 7 and 10. An inert gas header Si having branch-
off
lines to allow supply of inert gas or dry air into cargo holds or void spaces
S5, depending on
the type of cargo tank containment system used, is provided.
A service line header S2 having branch off lines leading to storage tanks G3
is
provided to allow the selective connection to storage tanks G3 for
decommissioning, tank
entry and subsequent recommissioning, while other storage tanks G3 remain in
operation.
An inert gas is provided from shore through internal transfer system for
service S10
which is operative to fluidly connect the jetty service line JS1 to inert gas
line Si and service
header S2 to provide inert gas or dry air for all operations when as needed.
An inert gas and/or air heater S7 is provided with optional fluid connections
to the
service header S2 or/and inert gas header Si to be used to supply hot inert
gas or hot dry air
for the purpose of storage tanks and pipeline warm up as and when needed.
Optionally, a
single heater can be used for either inert gas or NG heating.
A tie-in connection to the offloading system S8/L7 is provided to allow the
supply of
inert gas to the offloading line L2, internal transfer systems for offloading
L6 and jetty
offloading line JL2 when as needed.
During nonnal operations, the inert gas system supplies dry air or inert gas
to void
spaces adjacent to storage tanks through the jetty service line JS1, internal
transfer system for
service S10 into the inert gas header Si and distributes it to void spaces S5
(cargo holds) via
branch-off lines.
For the purposes of decommissioning and recommissioning of storage tanks G3,
as
required for maintenance, regulatory inspections, last minute repairs, etc.,
the inert gas
system will support the process of decommissioning, ventilation and
recommissioning of any
one or more tanks.
During decommissioning of tanks, the targeted storage tanks G3 are isolated
from the
liquid loading and offloading systems and a temporary connection is fitted to
fluidly connect
the service line header S2 branch off line to the filling line L12 between the
tank penetration
and the first valve. Then, a shore inert gas generator supplies dry clean
inert gas directly to
the tanks by flowing through jetty service line JS1, internal transfer system
for service S10
and service line header S2 and purging NG out of the targeted storage tanks
G3. Alternatively
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provides warm inert gas by flowing through the heater S7 (Optional) before
distributing it
with the same service header to the targeted cargo tanks.
After all the NO has been purged out of the cargo tank, shore supply switches
from
inert gas to dry air to purge the inert gas out of the tank and make the space
safe for entry.
During storage tank man entry, the service line header S2 supplies ventilation
air
continuously to ensure a safe environment for personnel at all times.
During recommissioning of tanks for return to service, the shore supply
switches back
from dry air to dry inert gas which flows to the target storage tanks G3
through the service
header S2 and branch off lines to replace the air in the tanks with inert gas
in preparation for
gas-up and cooldown.
Once all the tank is inert, NGs for gas-up can be supplied from other tanks
through
the existing vapour header line V1 and branch off lines V2 by re-opening
vapour isolating
valves of the target storage tanks G3.
Alternatively, the cooldown system can provide NG vapour to the targeted
storage
tanks G3 for gas-up through the tie-in to cooldown system connection S9/C8 to
the service
header S2 and branch-off connections.
Final cooldown of the tanks is done by the cooldown system by pumping LNG from
any of the other tank's cooldown pump C9 to the targeted storage tank's spray
system C10
via the cooldown (spray) header line Cl until the tank reaches a temperature
suitable for the
reintroduction on LNG.
If decommissioning and recommissioning of the loading and/or offloading system
is
required, the inert gas system can provide inert gas or dry air respectively
directly to the
loading and/or offloading system through the tie-in to liquid system
connection S8/L7.
An automation and control system (including safety systems) is provided to
allow the
monitoring and control of all cargo related operations from a single control
room which is
located at onshore plant G7.
Power, utility and control lines as shown in Figure 10 are provided and extend
from
onshore power, utility and control facilities at the onshore plant G7 to the
floating storage
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structures G1 for operation thereof through JUL It is to be appreciated that
separate lines can
be provided for power supply, utility and control signals.
Reference made to Figure 8. A method of operating the LNG export terminal 1 is
described here. Generally, for operation as a LNG export terminal 1, LNG is
transferred from
the onshore plant G7 to one or more floating storage structures G1 and,
subsequently, from
the floating storage structures G1 to one or more LNG carriers G2 berthed at
the jetty 4 to be
transported to another location.
At the onshore LNG plant G7, natural gas (NG) is processed and liquefied into
LNG.
The LNG is supplied through the liquid loading system Fl to the designated
floating storage
structure (s) G1. It is to be appreciated that the LNG may be stored at an
onshore tank of the
onshore LNG plant G7 before being supplied through the liquid loading system
Fl to the
designated floating storage structure(s) G1. The LNG supplied through the
liquid loading
system Fl is then stored at the floating storage structure(s) G1 storage tanks
G3.
At the onshore plant G7, power generation, utility and control facilities,
electrical
power, utilities and control signals are produced and are supplied through
respective lines
Figure 10 ¨JUL e.g. power cables, utility lines, electrical signal lines, to
the designated
floating storage structure G1 for operation thereof. It is to be appreciated
that the electrical
power and/or utilities may be stored onshore before being supplied through
respective lines to
the designated floating storage structure G1.
BOG generated on the floating storage structures G1 is collected by the vapour
system F3 and returned back to onshore plant G7 for re-processing. The proper
collection and
management of the BOG is important to control the pressure in the storage
tanks G3 and
ensure the stability of the LNG terminal 1 and onshore plant G7 liquefaction
process.
A LNG carrier G2 for exporting the LNG to another location is berthed at the
loading
jetty portion 7. Using the offloading system F2 which receives LNG from the
floating storage
structures Gl, LNG stored at the floating storage structure tanks G3 is
offloaded to the LNG
carrier G2.
When offloading to the LNG carrier G2, vapour or BOG generated by the carrier
is
collected by the vapour system F2. A portion of the collected vapour is
returned back to the
storage tanks G3 of the floating storage structures G1 to compensate for the
volume of LNG
which was transferred from the storage tanks G3 of the floating storage
structures G1 to the
LNG carrier G2 and the remaining vapour is sent back to shore plant G7 for re-
processing.
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The vapour system F3 ensures that BOG pressures between the carrier G2 and the
floating
storage structures G1 is equalized and ensure the stability of the system.
For inventory management as and when required, LNG is transferred from one
floating storage structure G1 to another floating storage structure G1 through
the liquid
offloading system F2.
Operation reliability and continuity failures in the floating storage
structures might
lead to a reduction on the floating storage structure capabilities but shall
not lead to shutdown
of the onshore plant G7. If one floating storage structure G1 or any storage
tank G3 within
the floating storage structure G1 is out-of-service, storage of LNG can be
transferred to
another floating storage structure G1 or another storage tank while the
affected floating
storage structure G1 or storage tanks G3 is being repaired or replaced. For
example, in an
extreme case, a completely out-of-service floating storage structure G1 can be
decoupled
from the permanent mooring system G8 and transported away from the LNG
terminal 1 and,
subsequently, a replacement floating storage structure is installed in place
of the out-of-
service floating storage structure Gl, and in the meantime, the LNG terminal
can operate
with the remaining floating storage structure G1. Alternatively, if any
storage tanks G3
within the floating storage structure G1 is out-of-service and the remaining
tank(s) G3 remain
operational, the floating storage structure G1 may not require replacement.
For operation productivity and safety, the floating storage structures G1 are
controlled
as an integral part of the onshore plant G7. Since electrical power and
utilities are transferred
from an onshore plant G7 to the floating storage structures G1 no personnel is
needed
onboard the floating storage structures G1 during normal operations.
Therefore, the LNG
terminal can be operated as a fully integrated part of the onshore LNG plant,
in a similar
manner as conventional land-based tanks.
It is to be appreciated that the LNG terminal 1 arrangement according to the
invention
may alternatively be used as a LNG import terminal. Generally, for operation
as a LNG
import terminal, LNG is transferred from a LNG carrier G2 berthed at the
loading jetty
portion 7 to the floating storage structures G1 and, subsequently, from the
floating storage
structure G1 to an onshore LNG plant G7 where the LNG is stored and or re-
gasified before
distributing to the consumers, e.g. industries and retail users, by pipelines,
rail, land vehicles
or water vessels. Accordingly, the onshore LNG plant G7 would include a re-
gasification
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facility. Alternatively LNG can be reloaded to smaller vessels, rail tanks or
truck tanks for
further distribution.
Suitable modifications to the pipelines would be required including, but not
limited
to, modifying floating storage structure tank offloading lines to fluidly
connect to the first set
of pipelines instead of to the second set of pipeline in order to transfer LNG
to the onshore
LNG plant. In other words, the liquid loading system Fl or first set of
pipelines would be
employed for liquid offloading while the liquid offloading system F2 or second
set of
pipelines would be employed for liquid loading.
The invention is herein described in non-limiting embodiments and variations.
A person
skilled in the art will understand that there may be made alterations and
modifications to the
embodiments and variations that are within the scope of the invention as
described in the
attached claims.
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