WO2022089930A2

WO2022089930A2 - Compact system and method for the production of liquefied natural gas

Info

Publication number: WO2022089930A2
Application number: PCT/EP2021/078096
Authority: WO
Inventors: Carolus Antonius Cornelis Van De Lisdonk; Mark Antonius Kevenaar; Saheed Olukayode Steven TAIWO
Original assignee: Shell Internationale Research Maatschappij BV; Shell Oil Co
Current assignee: Shell Internationale Research Maatschappij BV; Shell USA Inc
Priority date: 2020-10-26
Filing date: 2021-10-12
Publication date: 2022-05-05
Anticipated expiration: 2023-04-26
Also published as: AU2021370108A9; CA3199448A1; WO2022089930A3; US20230392860A1; AU2021370108A1

Abstract

A facility for the production of liquefied natural gas comprising a liquefaction train. The train comprises a plurality of modules to perform the process steps associated with liquefied natural gas production. The train further comprises a primary cooling loop to cool at least a process stream from each module and a first and a second mixed refrigerants against a first coolant comprising clean water. The primary cooling loop is a closed clean water loop, and the cooling is against an ambient temperature. The train further comprises a first plurality of heat exchangers through which the primary cooling loop extends. The cooling is via heat exchange in at least the first plurality of heat exchangers with respect to the first coolant. More than 50% of the first plurality of heat exchangers are printed circuit heat exchangers, which are adapted to provide at least 80% of the cooling against the ambient temperature.

Description

COMPACT SYSTEM AND METHOD FOR THE PRODUCTION OF LIQUEFIED

NATURAL GAS

FIELD OF THE INVENTION

The present invention is directed to a system and a method for the production of liquefied natural gas (LNG).

BACKGROUND TO THE INVENTION

Natural gas (NG) is routinely transported from one location to another location in its liquid state as Liquefied Natural Gas (LNG). Liquefaction of the natural gas makes it more economical to transport as LNG occupies only about 1/600 of the volume that the same amount of natural gas does in its gaseous state. After liquefaction, LNG is typically stored in cryogenic containers, typically either at or slightly above atmospheric pressure. LNG can be regasified before distribution to end users through a pipeline or other distribution network at a temperature and pressure that meets the delivery requirements of the end users.

Wellhead gas is subjected to gas pre-treatment to remove contaminants prior to liquefaction. The hydrogen sulphide and carbon dioxide can be removed using a suitable process such as amine absorption. Removal of water can be achieved using conventional methods, for example, a molecular sieve. Depending on the composition of contaminants present in the inlet gas stream, the inlet gas stream may be subjected to further pre-treatment to remove other contaminants, such as mercury and heavy hydrocarbons prior to liquefaction.

Liquefaction is achieved using processes which typically involve compression, expansion and cooling. Such processes are applied in technologies such as C3/MR process, the AP-X™ process, the Cascade Process, the Mixed Fluid Cascade process or the Double Mixed Refrigerant or Parallel Mixed Refrigerant process.

Refrigerants are cycled in one or more refrigeration loops to reduce the temperature of the treated gas to a temperature of around -160°C to form LNG. This results in warming of the respective refrigerant which must be compressed for recycle to the liquefaction process and subsequent expansion. Compressors used for this duty may be centrifugal compressors driven by gas turbines or electric motors. The refrigeration loop may comprise coolers to remove heat added due to cooling and liquefying of the natural gas and due to the compression of the respective refrigerants.

Over the last 10 to 15 years, the LNG industry has seen a shift from traditional stick-built LNG facilities to modular built projects. Examples are available in, for instance, Australia, the Russian arctic, and Canada. A main driver to change to modular built LNG trains is to move much of the site construction work to an offsite fabrication yard. At the yard, process units can be built in modular form in a controlled, predictable environment. Remote fabrication of modules may result in increased productivity and lower labor rates, better quality, reduced chance of safety incidents, and improved predictability with respect to cost and schedule.

US-2014/053599-A1 discloses a liquefied natural gas production facility comprising a plurality of spaced-apart modules for installation at a production location to form a production train having a major axis and a minor axis, each module having a module base for mounting a plurality of plant equipment associated with a selected function assigned to said module, the module base having a major axis and a minor axis; and a plurality of heat exchangers arranged to run parallel to the major axis of the production train to form a heat exchanger bank having a major axis and a minor axis

US-2016/0010916-A1 discloses a liquefied natural gas production process for producing a product stream of liquefied natural gas at a production location, said process comprising: a) designing a plurality of modules for installation at the production location to form an installed production train; (b) designing an air-cooled heat exchanger bank including: a first row of air-cooled heat exchanger bays, and, an adjacent parallel second row of air-cooled heat exchanger bays; (c) arranging a first sub-section of the first row of heat exchanger bays at an elevated level vertically offset from and towards a first edge of a first module base to form a covered section of the first module base, the first module base being designed and sized to include an uncovered section for mounting a selected piece of process equipment, wherein the first module includes the first subsection of the first row of heat exchanger bays without including a sub-section of the second row of heat exchanger bays; (d) arranging a first sub-section of the second row of heat exchanger bays at an elevated level vertically offset from and towards a first edge of a second module base to provide a covered section of the second module base, wherein the second module includes the first sub-section of the second row of heat exchanger bays without including a sub-section of the first row of heat exchanger bays; and (e) positioning the first edge of the second module base at the production location towards the first edge of the first module base.

Modularization, which for instance aimed to circumvent high labor costs by constructing modules of facilities at a location having reduced costs of labor and subsequently move the preconstructed modules to the LNG production location, has disappointed in practice. Production costs remained relatively high compared to conventional stick-built facilities. The general view is that, unless local labor costs are particularly high and/or productivity is particularly low, a plant with stick-built LNG production trains result in the lowest costs, albeit with an extended construction schedule, increased exposure to local influences and potential quality issues. The conventional modular approach generally is seen to lead to a better quality of the LNG production train, yet at the expense of higher capital expenditure.

Historically, the choice to use onshore modular built instead of stick-built for LNG production trains is generally taken after the basic (process) layout of the plant is fixed. Conversion of the plant design to a modular setup typically results in relatively large modules requiring a lot of structural steel and relatively few equipment items per module. The large number of modules required to span the still relatively large plant layout results in a relatively large residual in-field hook-up scope as there are many piping connections. As a result, the full system must be leak tested on site. Additionally, most of the cabling has to be installed and tested on site. The latter are both relatively time consuming and costly.

WO2019110769 in the name of applicant provides a modular liquefaction train for LNG production, with reduced capital expenditure and footprint. Footprint herein refers to the area of the liquefaction train. Area herein refers to the surface included within the boundaries of the liquefaction train.

Despite the advantages and cost savings provided by the modular designed liquefaction systems as for instance disclosed in the references above, there remains a need to explore alternative designs to further reduce capital expenditure and footprint. SUMMARY OF THE INVENTION

In one aspect, a facility for the production of liquefied natural is provided. The facility comprises an inside battery limit (ISBL) comprising a liquefaction train. The liquefaction train comprises a plurality of modules with each module being adapted to perform at least one process step associated with liquefied natural gas production. The plurality of modules comprise a first module for acid gas removal; a second module comprising a dehydration unit; a third module, being the liquefaction module; and a fourth module comprising equipment for processing of natural gas liquids.

The train further comprises a first mixed refrigerant cycle comprising a first mixed refrigerant and a second mixed refrigerant cycle comprising a second mixed refrigerant connected to the liquefaction module for cooling a gas stream to produce the liquefied natural gas. The train further comprises a primary cooling loop to cool at least a process stream from each module and the first mixed refrigerant and the second mixed refrigerant against a first coolant comprising clean water. The primary cooling loop is a closed clean water cooling loop and the cooling is against an ambient temperature. The train further comprises a first plurality of heat exchangers through which the primary cooling loop extends, and the cooling by the primary cooling loop is via heat exchange in at least the first plurality of heat exchangers with respect to the first coolant. More than 50% of the first plurality of heat exchangers are printed circuit heat exchangers which are adapted to provide at least 80% of the cooling against the ambient temperature.

Optionally, the liquefaction train further comprises a second plurality of heat exchangers through which the primary cooling loop extends to cool the first coolant by heat exchange with a second coolant, and the facility further comprises

- an outside battery limit (OSBL) comprising a cooler for cooling against the ambient temperature; and

- a secondary cooling loop extending through the second plurality of heat exchangers and the cooler to cool the second coolant against ambient temperature, thereby enabling moving of thermal energy from the ISBL to the OSBL for dissipation against the ambient temperature in the OSBL. Optionally, the second coolant comprises water from a cooling tower system, sea water, or air.

Optionally, each of the plurality of modules of the liquefaction train has a predetermined maximum weight threshold, which can be 6000 tonnes.

Optionally, for the liquefaction train, the first module having a first side engaging a first side of the second module, and the second module having a second side opposite the first side engaging a first side of the fourth module. The liquefaction train further comprises a first module series comprising the first module engaging the second module engaging the fourth module, the first module series being aligned with and arranged adjacent to a second module series comprising the third module arranged between the first compressor on one side and the second compressor on the opposite side.

Optionally, the liquefaction train further comprises:

- a first compressor arranged on a first side of the liquefaction module and connected to the first mixed refrigerant cycle for compressing the first mixed refrigerant; and

- a second compressor arranged on a second side of the liquefaction module, the second side being opposite to the first side, and connected to the second mixed refrigerant cycle for compressing the second mixed refrigerant.

Optionally, the liquefaction train further comprises:

- a pre-cool heat exchanger arranged on the first side of the third module and connected to the first mixed refrigerant cycle for pre-cooling the gas stream in heat exchange with respect to the first mixed refrigerant; and

- a main heat exchanger arranged on the second side of the third module, the second side being opposite to the first side, and connected to the second mixed refrigerant cycle for at least partially liquefying the pre-cooled gas stream in heat exchange with respect to the second mixed refrigerant.

Optionally, the liquefaction train further comprises a pipe-rack for supporting conduits, the pipe-rack extending through at least the first module, the second module and the fourth module.

Optionally, the first mixed refrigerant cycle comprises a single precool heat exchanger. The first mixed refrigerant cycle can further comprise a compressor intercooler adapted to cool first mixed refrigerant compressed by the first compressor without condensing the first mixed refrigerant, an outlet of the compressor intercooler being connected to a subsequent stage of the first compressor.

Optionally, the liquefaction train has a capacity of production of liquefied natural gas in the range of about 2 to 4 MTPA.

According to another aspect, the disclosure provides a method of producing liquefied natural gas using a system as described above.

The system and method described above have been designed with modularization in mind. The result provides a significant cost saving and footprint reduction with respect to convention systems, including modular built systems. Details are provided in the detailed description section below.

BRIEF DESCRIPTION OF THE DRAWINGS

The drawing figures depict one or more implementations in accord with the present teachings, by way of example only, not by way of limitation. In the figures, like reference numerals refer to the same or similar elements.

Figure 1 shows a diagram of a liquefaction system suitable for a system of the disclosure;

Figure 2A shows a diagram of another embodiment of a liquefaction system suitable for a system of the present disclosure;

Figure 2B shows a diagram of yet another embodiment of a liquefaction system suitable for a system of the present disclosure;

Figure 3 shows a perspective view of an embodiment of a system according to the disclosure;

Figure 4 shows a plan view of an embodiment of a system according to the disclosure;

Figure 5A shows a plan view of another embodiment of a system according to the disclosure;

Figure 5B shows a plan view of an embodiment of the system of the disclosure, including a diagrammatical example of a flow of feed gas from gaseous feed to liquefied product;

Figure 5C shows a plan view of an embodiment of the system of the disclosure, including a diagrammatical example of a flow of cooling water through the modules; Figure 6 shows a diagram indicating dependence of total equipment weight (in tonnes) for a liquefaction system of a selected total capacity on size of each liquefaction train (in million tonne per annum [mtpa]);

Figure 7 schematically shows a perspective view of a shell-and-tube heat exchanger and a printed circuit heat exchanger for use in a system of the present disclosure;

Figure 8 shows a diagram indicating rationale of designing a system of the present disclosure;

Figure 9 shows a diagram indicating a relation between a ratio of module weight to equipment weight (vertical axis) and (mechanical) equipment weight (in tonnes) for modules of embodiments of the disclosures and modules of conventional projects as reference;

Figure 10 shows a diagram indicating an exemplary relation between fabrication time (in months) and module weight (in tonnes);

Figure 11 shows a diagram of an exemplary cooling water loop for a system of the present disclosure;

Figures 12A, 12B and 12C respectively show, on the same scale and for the same liquefaction capacity (in mtpa), schematic representations in plan view of an exemplary conventional stick-built liquefaction train, an exemplary state of the art modular liquefaction train, and an embodiment of a liquefaction system according to the present disclosure;

Figure 13 shows a plan view of an exemplary site layout of a facility for the production of liquefied natural gas, comprising a number of liquefaction trains, including state-of-the-art modular liquefaction trains and liquefaction systems according to the present disclosure.

Figure 14 shows a plan view of a comparison of a footprint of an embodiment of a liquefaction system according to the present disclosure and a state-of-the-art modular built liquefaction facility, for the same production capacity (typically expressed in mtpa);

Figure 15 shows a diagram indicating an area or plot space per unit of production (in mtpa) of a number of conventional (stick built and modular built) liquefaction facilities and of embodiments of a system according to the disclosure; Figure 16 shows a diagram indicating green-house gas (GHG) intensity of a number of conventional liquefaction facilities (stick built and modular built) and of embodiments of a system according to the disclosure;

Figure 17 shows a diagram indicating an estimate of pieces of equipment per unit of production (in mtpa) of a number of conventional liquefaction facilities and of embodiments of a system according to the disclosure; and

Figure 18 shows a diagram indicating module weight per unit of production (in mtpa) of a number of conventional modular built liquefaction facilities and of embodiments of a system according to the disclosure.

DETAILED DESCRIPTION OF THE INVENTION

Certain terms used herein are defined as follows:

The term "LNG" refers to liquefied natural gas.

"Natural Gas Liquids" or "NGLs" are hydrocarbon components of natural gas that are separated from the gas state in the form of liquids. NGLs may also be referred to as condensate.

"LPG" relates to Liquid Petroleum Gases. LPG is a subset of NGL. LPG are C3 to C4s with high vapor pressure. LPG typically includes propane and butane. Trace amounts of C5 can be found in LPG due to the fractionation process.

"Heavy Hydrocarbons" or "HHC" are hydrocarbon components comprising five carbon atoms or more (C5+ components), including aromatics.

The term "LNG production train" refers to an assembly comprising process units used for the pre-treatment of a natural gas feed stream to remove contaminants and provided treated gas, and process units used for receiving the treated gas and subjecting the treated gas to cooling to form liquefied natural gas.

The term "plant" may refer to the LNG production plant including one or more LNG production trains.

The term "facility" may refer to an LNG production plant, but may alternatively refer to an assembly in general.

The term "stick-built" refers to an LNG production train which has sections built in subsequent order at the production location. Herein, stick-built is similar to conventional construction. Both refer to construction of a production train or another section of a plant predominantly at a production location. Herein, production location is the location of the plant itself. In contrast, the term "module" refers to a section of a plant that may be preassembled at a construction or assembly location remote from the production location. Each module is typically designed to be transported from the construction or assembly location to the production location. Modules may be transported by towing or on floating barges, or by land using, for instance, rail or truck. After each module is moved from the construction or assembly location to the production location, the module is positioned in a suitable pre-determined orientation to suit the needs of a given LNG production facility.

As used herein, ISBL has its ordinary meaning known by one of ordinary skill in the art, including being defined as comprising all equipment and associated components (piping, etc.) that act upon the primary feed stream of a process, which is the process for the production of the liquefied natural gas in this instance (including removing contaminants from a natural gas feed stream to provide treated gas and cooling the treated gas to form liquefied natural gas). ISBL is functionalbased and refers to equipment and other components that are solely dedicated to a particular process (e.g., process for the production of the liquefied natural gas). Such equipment may be referred to as the ISBL equipment or ISBL units.

Correspondingly, Outside Battery Limits (OSBL) as used herein also has its ordinary meaning known to one of ordinary skill in the art, including being defined as utilities, common facilities, and other equipment and components not included in the ISBL definition. OSBL refers to systems (equipment pieces and associated components) that support several units, including ISBL units. Typical OSBL equipment includes cooling towers, water treatment facilities, tanks farms, LNG loading equipment, etc.

"Metric Tons" or "Tonnes" is a unit of weight equal to 1,000 kilograms.

LNG plant capacity is usually specified in million metric tonnes per year (mt/y or mtpa).

The capital expenditure to fabricate and build an LNG facility comprising modular built LNG trains is typically driven by a few key levers, such as:

1) the compactness of each module individually;

2) the footprint of all modules of a liquefaction train together;

3) the equipment costs (for all equipment of all liquefaction trains); 4) weight of respective modules, and the ratio of total weight of a module to the weight of equipment in the respective module;

5) number of construction hours at the fabrication yard (for the entire plant, including all modules); and

6) number of construction hours at the LNG production site (for the entire plant, including all modules and including connections ['hook ups’] between respective modules in a liquefaction train).

Weight of respective modules is relevant to capital expenditure due to transportation costs, and the costs of steel to construct the respective modules. Module weight is an indicator for estimating costs. Module weight is typically linked to the number of fabrication hours in the yard as well as site hours and civil scope to support the modules on site.

Conventional modular liquefaction facilities typically improve on one or two of the levers listed above. As explained herein below, embodiments of the system of the disclosure target and improve on at least a majority of, or even all of, the levers listed above. As a result, capital expenditure to construct the system of the present disclosure is significantly reduced with respect to conventional liquefaction facilities, including existing modular liquefaction facilities. Herein, a system according to the disclosure is compared to conventional plants, wherein the system of the disclosure has at least a similar production capacity and a similar energy efficiency. In addition to efficiency and capacity, the system of the present disclosure also enables to achieve close to best in class green-house gas (GHG) performance. The LNG production system of the disclosure can be built faster and at lower cost. This is done by combining one or more, preferably all, of the features described below. A description of each item respectively follows herein below, with reference to the drawings.

1. Selection of DMR technology as liquefaction process.

2. Liquefaction capacity per liquefaction train between 2 to 4 MTPA.

3. Selection of light-weight equipment.

4. A closed loop for water cooling.

5. Limited weight per module.

6. A foil process unit in a module.

7. A pipe rack integrated in the module(s). 8. Installing long lead items outside modules.

9. Minimization of installed spares and valves.

10. Arrangement of equipment to minimize distance and piping.

A first step involves a selection of a liquefaction process. Various liquefaction processes are available. A comparison is for instance provided in the article "Analysis of Process Efficiency for Baseload LNG Production" by T. J. Edwards et al. [1984] of Air Products and Chemicals Inc. According to the article, the C3MR and DMR have similar thermodynamic efficiencies. Both are more efficient than the cascade liquefaction process. According to the article, C3MR "has distinct advantages over the other process cycles, e.g. by way of simpler control, less costly and more reliable equipment, and ease of startup." Consequently, the most commonly used liquefaction process for existing plants is the C3MR process. Relatively small LNG plants can use SMR (a process using a single mixed refrigerant cycle) or a nitrogen (N2) cooling cycle as liquefaction technology, but these technologies provide relatively poor liquefaction efficiency and increased specific green-house gas (GHG) emissions.

Despite the general preference in the industry for the C3MR process, Applicant has found that the DMR process provides certain benefits in combination with the modular setup. For instance, the Dual Mixed Refrigerant (DMR) process has a lower equipment count than C3MR and optimized cascade. Also, DMR enables to use lighter equipment.

The pre-cool cycle of the DMR process can be based on single stage (single heat exchanger) or dual stage (two heat exchangers), as explained below. Figures 1 and 2 show embodiments of a liquefaction process suitable for the system of the disclosure.

Figure 1 shows a DMR process with a dual stage precool loop. Dual stage herein refers to two or more separate heat exchangers in the precool cycle, each consecutive heat exchanger operating at a lower internal pressure than the previous heat exchanger. Fig. 1 schematically depicts a system 1 and associated method for liquefying a gas 2, such as natural gas. Please note that various modifications to the scheme of Figure 1 are conceivable. For instance, the gas 2 in its associated conduit may have been pre-treated. Several types of gas treatment can precede the scheme of Fig. 1. Various other types of equipment can be added downstream of the system to further process the at least partly condensed or fully liquefied gas 30 provided by the system of Fig. 1. Such equipment may include a nitrogen removal section or addition of an end-flash section. Also, there may be differences between respective liquefaction systems, for instance with respect to thermodynamics, pressure ranges, temperature ranges, and flow rates at various locations in the system during operation, equipment sizes, maximum capacity, etc.

At a generic level, the liquefaction system 1 comprises two consecutive cooling cycles 4 and 6. The pre-cool cycle 4 may comprise at least one, for instance two heat exchangers 10 and 12 and at least one pre-cool refrigerant compressor 14. The cycle 4 may also include at least one cooler 15. Pre-cool refrigerant conduits 16 guide precool refrigerant from the compressor 14 through the two heat exchangers 10 and 12 and back. Refrigerant conduits 16 may comprise conduits 16a to 16f. Together, conduits 16 constitute a loop to circulate a refrigerant. The refrigerant circulated in loop 4 may be referred to as, for instance, precool refrigerant, precool mixed refrigerant (PMR) or first refrigerant.

The first pre-cool heat exchanger 10 may operate at a first pressure and the second pre-cool heat exchanger 12 may operate at a second pressure. Herein, the first pressure typically exceeds the second pressure. As a result, the first heat exchanger 10 may be referred to as high-pressure (HP) pre-cool heat exchanger. The second heat exchanger 12 may be referred to as low-pressure (LP) pre-cool heat exchanger.

The main cooling cycle 6 comprises at least one main heat exchanger 20 and at least one main refrigerant compressor 22. The cycle 6 may include one of more coolers 23, 25. Main refrigerant conduits 24 extend from the compressor 22 through the two heat exchangers 10 and 12, subsequently through the at least one main heat exchanger 20, and back to the compressor 22. The cycle 6 may comprise a separator 26 to split the mixed refrigerant of the main cycle 6 in a heavy mixed refrigerant 27 and a light mixed refrigerant 28. Refrigerant conduits 24 may comprise conduits 24a to 24f. Together, conduits 24 constitute a loop to circulate a refrigerant. The refrigerant circulated in loop 6 via conduits 24 may be referred to as, for instance, main refrigerant, mixed refrigerant or second refrigerant.

The gaseous feed stream 2 is routed via conduits extending through the two heat pre-cool exchangers 10 and 12, and subsequently through the at least one main heat exchanger 20, to provide at least partially condensed or liquefied gas 30. Both the pre-cooling cycle 4 and the main cooling cycle 6 may use a mixed or multi-component refrigerant to pre-cool and subsequently condense or liquefy the gaseous feed stream 2. Expanded pre-cool mixed refrigerant 50, 52 provides cooling duty to the pre-cool heat exchangers 10, 12 respectively and to all streams routed through the inside of said heat exchangers. Expanded heavy mixed refrigerant 29 and expanded light mixed refrigerant 31 provide cooling duty to the main cryogenic heat exchanger 20 and to all streams routed through the inside of the MCHE 20.

For further details of the cooling cycles and the operation thereof, reference is made to, for instance, US6370910 or US6658891.

The system 1 typically also includes a system 40 to remove natural gas liquids. The embodiment of system 1 shown in Figure 1 is provided with a liquids removal section 40 comprising, for instance, a first separator 140, and a second separator 142. First and second separator 140, 142 may be flash vessels. Alternatively, the first separator may be a scrub column. Herein, a vertical scrub column for removing hydrocarbon liquids from natural gas may refers to a piece of equipment having multiple (for instance more than five, up to about ten) layers of stages with packing or trays as internals.

A conduit 150 may connect an outlet of the first pre-cool heat exchanger 10 with an inlet of the first separator 140. A second conduit 152 connects an upper outlet 154 of the first separator 140 with an inlet 156 of the second pre-cool heat exchanger 12. A third conduit 158 connects an outlet 160 of the second pre-cool heat exchanger 12 with an inlet 162 of the second separator 142. A fourth conduit 164 connects an upper outlet 166 of the second separator 142 with an inlet 168 of the main heat exchanger 20.

An optional bypass conduit 60 may be provided, connecting the inlet of the bundle 80 of the first heat exchanger 10 to an outlet of said bundle 80. The conduit 60 may be provided with a valve 62. The valve 62 may be controllable within a range between a closed position and an open position, allowing to adjust a flow of gas through the bypass conduit 60. The latter allows at least a section or part of the gas 2 to bypass the bundle 80 in the heat exchanger 10.

A fifth conduit 170 is connected to a lower outlet 172 of the first separator. Liquids can be removed from the first separator 140 via the conduit 170. A sixth conduit 176 is connected to a lower outlet 178 of the second separator 142. Liquids can be removed from the second separator 142 via the conduit 176. Optionally, the liquids from the second separator 142 can be recycled back to the first separator via line 173, either by gravity or optionally aided with a pump (not shown). Liquids may be removed, bypassing the first separator 140 via line 179. The conduits 173 and/or 179 may be provided with valves 63 and 65 respectively, allowing to control the flow in each conduit.

Figure 2A shows a system 101, wherein the pre-cool cycle 4 includes a single heat exchanger 10 provided with two bundles 80, 82 for guiding and cooling the natural gas feed stream 2. The first bundle 80 is connected to a second outlet 84 of the heat exchanger 10 which in turn is connected to conduit 150. The conduit 152 is connected to a second inlet 86 of the heat exchanger 10 connected to the second bundle 82. The conduit 158 may be connected directly to the inlet 168 of the main heat exchanger.

The pre-cool cycle 4 may include two or more coolers 15, 17. Thereof, the cooler 15 may be referred to as precool condenser. The cooler 15 may provide an at least partly condensed refrigerant stream 182. The precool cycle 4 may include a knock-out vessel or other gas-liquid separator 180. A lower outlet for liquids 184 of the vessel 180 is connected to the conduit 16d. The outlet 184 provides a condensed (liquid) refrigerant stream 186 to the precool heat exchanger 10.

The embodiment of Fig. 2B shows system 111, comprising interstage cooler 17 for cooling precool mixed refrigerant as compressed in a first stage of the compressor 14 before entering a subsequent stage of said compressor 14. The intercooler 17 of the precool refrigerant compressor 14 allows to reduce the compressor power. In a practical embodiment, the output of the intercooler 17 is a cooled vapor stream. Liquids in the output of the intercooler 17 are preferably prevented.

The system 111 may comprise a knock-out drum 300 to ensure only vaporous precool refrigerant is provided to the precool compressor 14. the compressor 14 may be provided with a first feedback conduit 302 with valve 304 to loop refrigerant back to the inlet of the compressor, via the knock-out drum 300. The cooler 15 of the liquefaction system 111 may be a de-superheater. The cooler 15 may be succeeded by another cooler 310, referred to as condenser. The cooler 310 may at least partially condense the compressed refrigerant. A second feedback conduit 312, provided with valve 314, may connect the refrigerant flow between the cooler 15 and the condenser 310 with a middle inlet 316 of the compressor 14. An outlet of the condenser 310 may be connected to PMR accumulator 180. A lower outlet 184 of the accumulator may be connected to a lower inlet 320 of tube bundle 322 for precool refrigerant in the heat exchanger 10. An outlet of the tube bundle 322 is connected to an expansion device 324, such as a JT valve. An outlet of the expansion device is connected to inlet 98. The system 111 may comprise a single heat exchanger 10 included in the precool cycle 4.

The gas tube bundle 84 may extend though the entire heat exchanger 10. Exit 84 of the gas tube bundle may be connected to the separator 140. The gas outlet 154 of the separator 140 may be connected to inlet 168 of the main heat exchanger 20.

In use, the single heat exchanger 10 of Figs. 2A and 2B is set to operate at a predetermined internal pressure. Precool refrigerant is passed through conduit 16d. Main refrigerant is passed through conduit 24b. The natural gas 2 is passed through the bundles 80 and 82. Cooled precool refrigerant in conduit 16f is expanded. The expanded precool refrigerant 98 is diffused into the heat exchanger 10 near the top of the heat exchanger 10. The expanded refrigerant cools the conduits 16d, 24b and 80, 82 inside the heat exchanger 10.

In the embodiment of Fig. 2B, natural gas from the mercury-removal bed may be pre-cooled using pre-cooled Mixed Refrigerant (PMR) in a Single stage Coil Wound Heat Exchanger (CWHE). The PMR is compressed in a single stage compressor 14 with interstage water-cooling in cooler 17. At normal operating conditions, a minimum of 10°C superheat is maintained at the inlet 316 of the compressor 2nd stage (outlet of interstage cooler 17) to prevent risk of condensation at the PMR circuit. A knock-out drum has been obviated at the outlet of the interstage cooler 17 in order to reduce capital expenditure. The PMR compressor 14 with interstage cooling offers an additional advantage, because it offers less scope at the target production and reduces specific power and specific GHG emissions.

The embodiments of Figure 2 A and 2B are particularly advantageous for a modular LNG facility. The single heat exchanger 10 in the precool loop 4 limits both equipment count, equipment weight, and piping. The NGL removal is relatively simple, requiring only a single separator 140. Separator 140 may be a scrub column separator if the feed gas is relatively rich, i.e. comprises relatively a lot of natural gas liquids. The liquefaction scheme of Fig. 2B is relatively low on equipment count. These advantages may be better appreciated in the light of the description herein below.

In a practical embodiment, the heat exchangers in the precool loop 4 and main liquefaction loop 6 are based on coil wound heat exchangers (CWHE). Alternatively, one or more of the heat exchangers 10, 12, 20 may be replaced with Plate Fin heat exchangers (PFHE).

The refrigerant compressors (PMR compressor 22 and MR compressor(s) 14) can be driven by an efficient aeroderivative gas turbine or alternatively by an electric motor. The driver selection, however, does not change the overall layout of the MML train.

A particularly beneficial layout for a system 200 according to the present disclosure is shown in Figures 3, 4 and 5. The system 200 is a liquefaction train having a modular setup. The system comprises four modules 210, 220, 230, 240 for treating and liquefying the feed gas. Modules or sections 250 and 260 comprise the respective refrigerant compressors and associated drivers. Figure 4 shows the system 200 wherein the drivers of the compressors are gas turbines. In Figure 5, drivers of the compressors are (variable speed) electrical motors.

An inside battery limit (ISBL) scope 202 of the system 200 comprises a number of modules. The modules include, for instance, four process modules. First module 210 is, for instance, an acid gas removal unit (AGRU). The AGRU typically comprises an absorber for flushing the gas with a liquid solvent. For details, reference is made to, for instance, WO2016150827. The absorber 212 may comprise a column type absorber placed next to and connected to the first module 210. Other process units, such as a unit 214 comprising a solvent drain drum and/or pump, may also be arranged next to and connected to the first module. These latter equipment components can also be placed inside the respective module.

A second module 220 may comprise a dehydration unit 222 and/or a mercury removal unit 224. The dehydration unit typically comprises a number of, for instance three, molecular sieve units (molsieves) 226. Alternatively, the Mercury removal unit (single vessel) may be arranged in the AGRU module 210. For details, see for instance US20180311609 or US8521310.

Third module 230 may comprise a liquefaction unit. Compressors 14 and 22 for the precool cycle and the main cooling cycle respectively may be positioned on opposite sides of the third module. See Figures 4 and 5. The precool compressor 14 may be provided with a first waste heat recovery unit 232. The main compressor 22 may be provided with a second waste heat recovery unit 234.

The first precool heat exchanger 10 may be positioned on the same side of the third module as the pre-cool compressor unit 14. The optional second precool heat exchanger 12 may be arranged next to the first precool heat exchanger 10. The main heat exchanger 20 may be arranged on the opposite side of the third module, typically on the same side as the main refrigerant compressor 22. Substantially all other equipment relating to the liquefaction system (such as the exemplary systems shown in Figures 1 and 2) is included in the third module 230. The precool heat exchanger 10, 12 and the main heat exchanger 20 are connected to the liquefaction module 230 and the respective compressors 14, 22 via piping (not shown in Figures 3-5, but indicated in Figures 1-2).

As shown in Fig. 4, the first and second compressor 14, 22 may be connected to a motor. The motor may be a gas turbine 232, 234.

As shown in Fig. 5A, the first and second compressor 14, 22 may be connected to respective first and second electric motors 260, 262. The electric motors may, respectively, be connected to a first and second variable speed drive unit (VSD) 264, 266. The variable speed drive units 264, 266 may be connected to respective first and second harmonic filters 268, 270. Each electric motor unit may be provided with a dedicated first and second transformer unit 272, 274 respectively.

A fourth module 240 may comprise equipment for condensate stabilization, heat transfer fluid (HTF) and at least one closed cooling water unit (explained in more detail below). Condensate stabilization herein refers to equipment for processing NGLs removed from the feed gas. Some of the NGLs may for instance in part be used as refrigerant make-up. In part the NGLs may be prepared for sale as product.

Additional equipment shown in Figures 3, 4 and 5A includes, for instance, transformers 250 for control of electricity provided to the system 200. An incinerator 252 may be provided to consume remaining hydrocarbons in the CO2 rich gas from the AGRU regenerator column. The latter includes, for instance, overflow of hydrocarbons in case of equipment failure or flash gas. The modules 210, 220 and 240 may be arranged adjacent to one another, the respective sides of one module engaging the side of the respective adjacent module. The liquefaction module or third module 230 with the respective compressors 14, 22 on opposite sides may be arranged longitudinally aligned with the modules 210, 220, 240. In a preferred embodiment, the conduits and the pipe rack 280 extend through the modules 210, 220, 230 and 240. The integrated pipe rack is included in the module weights (as referenced herein, for instance herein below).

The system 200 may comprise a pipe rack 280. The pipe rack supports and guides pipes or conduits 282, for instance for feeding and removing process streams to and from the respective modules 210 to 240.

In a practical embodiment, the pipe rack guides the pipes 282 to one of the modules, for instance to the fourth module 240, and extends through the inside of said module. The pipe rack 280 and the associated conduits 282 may extend through the inside of the modules, for instance through the modules 240, 220 and 210 respectively. See for instance Figure 3, which shows conduits 282 extending into the fourth module 240.

The module 230 may be arranged adjacent to the modules 240, 220 and 210. The latter modules together form a first series of interconnected modules. The third module, with the first compressor 14 and the second compressor 22 on opposite sides, may form a second series. The compressors may be modularized. Alternatively, the compressors 14 and 22 may be 'stick-built' (i.e. arranged and provided with cabling and piping onsite). Conduits for respective process streams may extend from the first series of modules to the third module 230 of the second series. Also, the heat exchangers 10, 12 and 20, which typically are coil wound heat exchangers, may be included in a dedicated module. Alternatively, these heat exchangers may be stick built.

Traditionally, LNG trains have a dedicated pipe-rack extending on the side and along the length of the LNG train and its equipment. The latter generally holds for both stick-built and modular built LNG trains. All individual process units are typically connected to the pipe rack. The system 200 applies an integrated pipe rack 280 which runs through at least two or the modules, preferably through at least three modules. This will enable the majority of the hookups between process units and piperack to be completed in the fabrication yard (i.e. remotely) and reduces the number of hookups required at the production location which in turn reduces the number of construction hours at the production site.

Figure 5B shows a practical embodiment of a water cycle 360 for cooling water. The cooling water is supplied and routed through the system 200 via associated conduits. At least part of the water conduits is arranged on the pipe rack 280. The number of hook ups 362 for cooling water required on site between parts of the conduits pre-arranged in the modules and other conduits is relatively limited. Prearranged herein means conduits included in the respective modules. Other conduits herein may refer to conduits in another module or conduits external to the respective module. In the example of Fig. 5B, the number of hook-ups or interconnections 362 is limited to about five to seven. For comparison, a comparable modular facility having a pipe rack extending along the side of the modules would at least require 18 hookups.

Figure 5C shows a practical embodiment of a gas cycle 370 for feed gas up to the rundown of LNG. Along the cycle, the gas is supplied and routed through the system 200 via associated conduits. At least part of the gas conduits is arranged on the pipe rack 280. The number of hook ups 372 for feed gas required on site between parts of the conduits pre-arranged in the modules and other conduits is relatively limited. In the example of Fig. 5C, the number of hook-ups or interconnections 372 is limited to about 10 to 11. For comparison, a comparable modular facility having a pipe rack extending along the side of the modules would at least require 16 hookups.

Similar reductions of required hook ups are achieved for other process streams. The latter may include, for instance, a cycle for so-called heat transfer fluid, for which the number of interconnections on site between the modules and other conduits is limited from about 13 to less than seven. Thus, the layout and composition of the system of the present disclosure reduced hookups and consequently the time required onsite to connect respective prefabricated modules and construct the system 200.

Each module comprises one or more full process units. In other words, all equipment associated with a respective process unit is only comprised in one of the modules, with caveat that selected equipment may be arranged on the side of, i.e. outside, the respective module (see, for instance, Figures 3-5). For instance, the Acid Gas Removal Unit (AGRU) is in a single module 210, the Dehydration Unit (DHU) and Hg removal bed may be a single module 220, the Liquefaction unit (including precool cycle 4 and main cooling cycle 6) is in a single module 230. And the condensate stabilization unit (or fractionation unit) is in a single unit 240, potentially combined with some utilities (such as closed cooling water expansion vessel and associated pumps, and Heat Transfer fluid expansion vessel and associated pumps). This minimizes interconnections and hookups between respective modules, which in turn minimizes site work at the construction site to construct the facility. It also enables maximum pre-commissioning and commissioning at the fabrication yard again with the objective to minimize the hours at site. The latter may basically include preparing all equipment and instrumentation for the operations phase. Commissioning means making systems ready for production of LNG.

As an alternative to the layout shown in Figures 3 to 5 A, it is for instance possible to combine two modules into one. For instance, the AGRU module 210 and the dehydration unit 220 may be combined in a larger single module (not shown). This will further reduce the number of hookups on site. The weight of the single module however will exceed the weight of each module 210, 220 individually. Base case is that a single process unit is included in one module and is not split over two or more modules.

In a practical embodiment, predetermined equipment is arranged outside the modules. For instance, long lead items will be arranged outside modules. Long-lead herein refers to items which take relatively long to construct and/or to get delivered. For instance, the main liquefaction heat exchangers 10, 12, 20 and the carbondioxide (CO2) absorber column 212 are typically the heaviest pieces of process equipment and are arranged outside the respective process modules to maintain the optimum module weight. In addition, the main liquefaction heat exchangers 10, 20 and CO2 absorber column 212 are long lead items that would determine the critical path of the process modules, so installing them separately reduces the module delivery schedule.

In a practical embodiment, the liquefaction capacity per train or system 200 is between 2 to 4 MTPA. Although larger train sizes do have the advantage of a relatively low equipment count for a given capacity, larger trains typically suffer from very large and heavy equipment with associated large diameter pipes. The combination increases the footprint, equipment weight and module weight (per unit of capacity in MTPA). By selecting a smaller train size, the equipment density in the module can be increased significantly. Relatively low capacity liquefaction trains have the benefit of small equipment and associated small diameter pipes. Relatively low capacity liquefaction trains typically have as a disadvantage an increased number of equipment, instrumentation, valves and other bulks for a given capacity, which tend to increase the capital expenditure. It also becomes impractical to operate so many trains for a given capacity. Bulks herein may relate to all kinds of smaller pieces of equipment, such as relief valves, drain systems, etc. required for safe operation of the LNG train. Models have indicated that modular built LNG trains having a capacity in the range of 2 to 4 MTPA have the lowest capital expenditure for the same total capacity of all trains combined.

As an example, Fig. 6 indicates results of modelling of the total equipment weight depending on the capacity of size of each respective train. Total equipment weight herein refers to the weight of all equipment combined for all liquefaction trains (i.e. within battery limit) for a certain total capacity. Line 400 indicates modelled results for the system of the present di sclosure. Line 402 herein is a reference, relating to a state-of-the-art liquefaction project. Both lines 400 and 402 relate to a total capacity of all trains combined of 14 mtpa.

The figure shows the total equipment weight required for a 14 MTPA facility as a function of the liquefaction train size. Two effects are apparent: 1) smaller trains (and hence more trains) do reduce the overall equipment weight, contrary what is normally assumed in industry, and 2) For an equal train size, total equipment weight for a facility according to the disclosure is significantly smaller than the total equipm ent weight of the reference modular LNG plant.

By applying a mid-scale concept rather than a large-scale concept, the total equipment weight per MTPA will decrease. This weight reduction is for instance driven by pressure vessels (and equipment that can be considered as such) as they represent the highest weight fraction of total installed weight and provide the highest weight reduction when downscaling. Overall, by constructing two trains each having half the capacity of a single larger train, the weight of equipment in all modules combined can be reduced. As an example, the selection of four smaller modules of 3.5 mtpa each provides a reduction of the total equipment weight of about 27% with respect to two trains having a 7 mtpa capacity each. Combining smaller trains with substantially all other measures as disclosed herein provides a further reduction in equipment weight in the order of 73%. A strong impact on the latter weight reduction is due to selection of light weight equipment, such as PCHEs, see for instance Figure 7 and the related description below.

In an embodiment, the system 200 of the disclosure uses water for cooling a process stream rather than air. Cooling process stream herein relates to, for instance, coolers 15, 17, 23, and 25 (see Fig. 2). Conventionally, LNG liquefaction facilities have generally been based on air cooling. In other words, coolers 17, 23 and 15, 25 have typically been implemented using air coolers (fans), which are typically relatively large and heavy. The system 200 of the present disclosure applies water cooling. Cooling using water as a coolant enables relatively compact and light heat transfer equipment and increases the process efficiency. Improved process efficiency in turn reduces overall green-house gas emissions for a given LNG capacity.

In a practical embodiment one or more of the coolers 15, 17, 23, 25 (Fig. 2) are so-called printed circuit heat exchangers (PCHE). In a preferred embodiment, all coolers 15, 17, 23, 25 (Fig. 2) are so-called printed circuit heat exchangers (PCHE). Conventional LNG facilities, especially facilities located on-shore, typically use air coolers. In conventional water-cooled on-shore LNG facilities, shell-and-tube heat exchangers would be selected as water coolers in view of significantly lower capital expenditure for equipment for the same capacity. However, Applicant has found that printed circuit heat exchangers provide significant benefits to the modular concept of system 200. As shown in Figure 7, an exemplary printed circuit heat exchanger 420 can be up to 85% smaller and lighter than a shell-and-tube heat exchanger having the same cooling capacity. Printed Circuit Heat Exchangers may be sourced from, for instance, companies such as Heatric (a division of Meggitt (UK) Limited) and Alfa Laval Corporate AB (Sweden). Yet, Applicant has found that the selection of PCHEs in the modular concept of system 200 provides additional benefits above and beyond the size of the heat exchangers itself. As described in more detail below, in combination with some or all of the features of embodiments described herein, these additional benefits make up for the additional capital expenditure for PCHEs. As a result, capital costs for the entire system 200 are significantly reduced with respect to conventional liquefaction systems, including modular systems. Figure 8 herein indicates a relation between a number of parameters for a selected module i (i being an integer ranging from 1 up to the total number of modules in a facility):

- Mechanical weight or mass Mini [in kg]: Combined weight of all equipment in a respective module i, excluding structural steel and conduits (430).

- Mechanical density Dim [in kg/m³]: Density of all equipment within the volume Vi of module i.

- Module volume Vi = Mrm/Drm (432) [in m³]: Total volume of module i. Structural density Dsi [in kg/m³]: Density of all items to provide structural support included in module i(such as columns, beams, steel structures, basically a structural frame).

Structural weight or mass Msi (434) = Vi * Dsi: Weight of all items to provide structural support to module i.

- Piping density Dpi [in kg/m³] (436): Density of pipes and conduits in module i, for instance for connecting the equipment in the module to respective process streams.

- Piping weight Mpi [kg] = Vi * Dpi: weight of all pipes and conduits in module i.

- Electrical and Instrumentation density Dei [in kg/m³]: Density of electrical equipment (such as cables, transformers) and instrumentation (such as temperature sensors, pressure sensors, flow meters and control valves) in module i.

- Electrical and Instrumentation weight Mei (438) = Vi * Dei: Weight of electrical and instrumentation equipment in module i.

- Mmodi / Mrm = 1 + (Dsi + Dpi + Dei) / Drm: Weight of module i divided by the mechanical weight in module i. I.e. the ratio between module weight and mechanical weight for module i.

Based on the above, applicant found a number of interlinking effects which reinforce each other. The embodiments as disclosed herein use these interlinking effects to provide optimal results for a modular setup. For instance, by reducing the weight of indivi dual pieces of equipment (Mm), the corresponding weight of required piping (Mpi), structural (MsQ and electrical & instrumentation weight (Mei) is also reduced. See Fig. 8. At constant densities, these weight reductions will inherently lead to a decrease of respective module volume Vi. The volume of respective modules (Vi) can decrease even further, due to the use of smaller (more compact) equipment. Viz, with Vi=Mmi/Dmi, with smaller equipment the mechanical weight decreases while the mechanical density of equipment in a module increases, leading to a smaller volume per module. Together, the lower volume and increased compactness (Dmi) provide a mutually reinforcing effect decreasing the weight of piping, structural steel and Electrical and Instrumentation (E&I) for a respective module. See for instance 436.

Optionally, the printed circuit heat exchangers included in the system 200 of the disclosure may be provided according to the setup and used according to the method as disclosed in US20200182552. This embodiment provides a further reduction in weight and size of the heat exchangers. Consequently, also the piping density and weight is reduced even more. Said further reduction in size and/or weight may be in the order of 20 to 45% (compared to state-of-the-art printed circuit heat exchangers), depending on specifics. As explained with respect to Fig. 8, weight reduction provides significant benefits, including cost reduction, well exceeding the extra costs of selecting printed circuit heat exchangers for at least some but preferably all of the coolers included in the system 200. Said coolers may include at least all coolers as included in the precool refrigerant cycle 4 and/or the main refrigerant cycle 6.

The selection of relatively light equipment, in particular the application of Printed Circuit Heat Exchangers (PCHE) for water cooling instead of the conventional shell-and-tube heat exchangers significantly reduces the size and weight of heat transfer equipment in the LNG train, and the volume and weight of associated conduits. In the system 200 of the disclosure, a majority of the heat exchangers for cooling a process stream with respect to a temperature of the environment (also referred to as ambient temperature, or ambient) are based on PCHEs. Said temperature of the environment is typically transferred via a medium such as air or water. The phrase majority herein does allow to include a few aircoolers as well. A few herein indicates that the number of air coolers is significantly less than the number of water coolers, for instance about 10% of the total at most, or preferably about 5% at most (in number and/or in cooling capacity). Figure 9 indicates examples of the dependence of module weight to equipment weight ratio (on the vertical axis) with respect to equipment weight only (on the horizontal axis) for respective modules individually. Module weight herein includes the total weight of a module, including both equipment and structural components (such as a steel support frame). Mechanical equipment weight herein is the same as just equipment weight, both referring to the equipment weight of all equipment combined in a respective module.

Fig. 9 indicates a ratio of module weight to equipment weight in the module and the relation thereof to just the module weight. Herein, module weight is the total weight of a respective module. Equipment weight is the total weight of all equipment in the respective module, without constructional elements (elements which are for support). Mechanical equipment weight is the same as equipment weight.

The plot of Figure 9 includes entries 450 for modules of the system of the present disclosure, entries 452 for respective modules of a number of reference projects, and entries 454 for process modules of a floating LNG project. Line of best fit 460 is fitted to the entries 450, 454. Line 462 is fitted to the entries 452.

Fig. 8 and the related description above indicated a formula for the ratio between total module weight - including all structural and support structures - and the total weight of only the equipment in the respective module: Mmodi/Mmi = 1+ [(Dsi+Dpi+Dei)/DmiJ. Fig. 9 shows a graphical example, indicating that the piping density and structural density have a negative impact on the ratio (i.e. increasing the ratio), while the equipment density reduces the ratio. Using the specific selection as described with respect to embodiments disclosed herein, the system 200 of the present disclosure enables to increase the equipment density significantly, leading to more compact modules requiring less space. This has been achieved while maintaining overall module density substantially the same as historical projects warranting similar congestion and therefore similar operational space, maintenance space and safety distances between equipment. See for instance the table below for an example of the system 200 compared to a state-of-the-art modular reference project:

Herein, Module density (Dmod) = Ds (structural density) + Dp (piping density) + Dm (mechanical density) + De (density of 'e&i', i.e. electrical and instrumentation; this relates to electrical cables and equipment such as controllers and transformers).

The required module volume is determined by, for instance, the equipment types, equipment count, equipment size and equipment spacing, amount of piping and number of mini FARs and substations. Maximization of high-density equipment like PCHEs plays a relatively big role. The weight of PCHEs is significantly lower than the weight of shell-and-tube heat exchangers which are used conventionally. The weight may be about a factor 5 lower. Also, the volume of PCHEs is smaller (more than a factor five), resulting in increased equipment density. There is also an impact on piping due to reducti on of parallel configurations.

As can be seen in the table above, the structural density and piping density are fairly constant, implying structural weight and piping weight scale proportionally with module volume. This seems reasonable as bigger modules require more steel for support structures, such as beams and columns, to support its own weight. Similarly, bigger modules will have equipment arranged spaced apart more, leading to an increase in piping weight.

The graph of Figure 9 with two lines 460, 462 shows two effects: a) For modules with lower equipment weight, the slope of both curves starts to increase. This indicates that the impact of equipment weight on total module weight decreases. For lower equipment weight, total module weight is determined more by piping, structural weight and other disciplines (for instance, mechanical density decreases). b) As shown in Figure 9, the system 200 of the disclosure has a significantly lower ratio of Mmodi/Mmi than a reference project of a modular built LNG facility, indicating that the system 200 has an increased mechanical density. Preferably, the maximum weight of each module 210, 220, 230, 240 is limited to a predetermined maximum threshold. In a practical embodiment, said threshold, also referred to as the maximum module weight, is about 5000 or 6000 tonnes. Line 456 in Fig. 9 provides an estimation of the 5000 tonnes per module upper threshold. Larger or heavier modules suffer from a relative increase in construction steel with respect to equipment weight. Construction steel refers to the steel and other components required to provide structural strength to a respective module.

Modules exceeding said threshold will typically increase fabrication time in the yard, with more manhours, which will typically increase the overall project schedule of the project. See Fig. 10. The maximum 5000 or 6000 metric tonnes of module weight also simplifies transport, as a relatively large number of vessels or barges is available that can transport modules up to said threshold.

Figure 10 shows the time it takes to fabricate a module (vertical axis) plotted in dependence of the total weight of the respective module (horizontal axis). Entries 480, 482, 484, and 486 respectively indicate data points for practical embodiments of the modules 210, 220, 230 and 240 of the system 200 of the disclosure. Please note that data points close to each other may relate to modules having a different function, but the general trend and trend line can be construed. First reference data entries 490 relate to a first reference project. Second reference data entries 492 relate to a second reference project.

The graph of Fig. 10 indicates a correlation, indicated by line 494, between the fabrication time for a respective module and the (total) weight of said module. So, in practice, modules having a lower overall weight can be constructed faster than heavier modules. Using the example of Figure 6, it is possible to compare the production of multiple trains having a smaller capacity per train (e.g. 2 times 3.5 mtpa) with another single liquefaction train having larger modules and the same overall capacity (e.g. 7 mtpa). For the construction of four modules (together being comprised in a liquefaction train having a 3.5 mtpa capacity), a significant part of fabrication of respective modules of the two trains can happen in parallel. As a result, the two trains can be fabricated faster than a single larger train having the same total capacity. As the fabrication schedule of two full trains according to the disclosure, as represented by system 200, will be shorter than a single large state of the art modular train having the same capacity. Hence, first LNG production will be earlier. Fig. 11 shows a cooling system 500, as included in a preferred embodiment of the system 200 of the disclosure. Herein, the PCHEs 502, 504, 506 are included in respective primary cooling loops 512, 514, 516. PCHEs 502, 504, 506 herein indicate a combination of all heat exchangers in the liquefaction train 200 (see, for instance, Figures 1, 2A, 2B) which cool with respect to a temperature derived from ambient. The heat exchangers are preferably printed circuit heat exchangers. Although Fig. 11 only shows the PCHEs schematically, the PCHEs in a respective liquefaction train can be connected to the primary cooling loop in series or in parallel. Preferably the coolers are connected in parallel. Some PCHE heat exchangers in the water loop 502, 504 can be connected in series, whereas said series may be connected in parallel to other PCHE heat exchangers or series of PCHE heat exchangers.

The primary cooling loops 512, 514, 516 may cycle a first coolant, for instance comprising clean water. Clean herein refers to the absence of impurities in the water. The clean water herein may refer to softened water or demineralized water. Also included in the clean water may be additives, such as a corrosion inhibitor and antifreeze. Anti-freeze herein may comprise glycol. The water purity of the clean water may typically be in accordance with an accepted standard, such as EN 12952-12, EN 12953-10, VGB-M 407, or VGB-S-010-T-00. Softened water herein refers to water wherein following a water softening process calcium (Ca), magnesium (Mg), and certain other metal cations have been removed. Said cations may have been replaced, for instance with Na (sodium). In a broader sense, the term demineralized water may be understood to also include reverse osmosis permeate. The demineralized water or permeate may have an electrical conductivity of for example

30 pS/cm. Alternatively, the clean water may be de-ionized water with an electrical conductivity of about 0.2 to 20 pS/cm, or so-called ultra-pure water with an electrical conductivity of 0.055 pS/cm at most. The whole purpose of the clean water in the closed loop is that the fouling of the PCHEs and that scaling of calcium or magnesium carbonates in the PCHEs is prevented. The softened water, soft water, or demineralized water reduces or eliminates scale build-up in the PCHEs.

The primary cooling loops 512, 514, 516 may each be regarded as a Clean Closed Cooling water (CCW) loop. As an example, see Fig. 11, water loops 512, 514 are related to two separate liquefaction trains 200. Cooling loop 516 is, as an example, related to heat exchangers 506 not included in a liquefaction train, but elsewhere in the liquefaction facility.

The closed water-cooling loops 512, 514, 516 may comprise pumps 520, 522, 526 for pumping water around the respective loop. The respective pumps can pump the water towards the PCHEs 502, 504, 506. Each loop may comprise an expansion vessel 530, 532, 536 for receiving the water output from the heat exchangers 502, 504, 506. Heat exchangers 540, 542, 546 receive the warmed water from the vessels 530, 532, 536 for cooling thereof. In a practical embodiment, the heat exchangers 540, 542, 546 are Plate and Frame Heat Exchangers.

The primary cooling loops 512, 514, 516 can in turn be cooled with respect to a second coolant of a secondary cooling system 550. The second coolant may be cycled in a loop, wherein the system 550 can be regarded as a secondary cooling loop 550. When cycled in a secondary cooling loop, the second coolant may comprise seawater or water from cooling towers. Alternatively, the second coolant may be air. In the latter case, the secondary heat exchangers 540, 542 include air coolers, and the secondary cooling system 550 is formed by said air coolers.

The secondary loop 550 may comprise a first header 552 for providing the second coolant to the respective heat exchangers 540, 542, 546 via associated conduits 554, 556, 558. Warmed second coolant from the heat exchangers 540, 542, 546 may be collected at a second header 560. From the second header 560, warm second coolant may be provided to a cooler, such as at least one cooling tower or spray tower 570. A first pump 572 can circulate the second coolant in the secondary cooling loop 550. A make-up system 580 may typically be provided to provide additional secondary coolant to top up lost coolant or to add fresh water 582 to control the composition of the coolant. The makeup system may comprise a second pump 584 to pump fresh water 582 from a well or other source to the loop 550, for instance to the cooling tower 570.

It is understood that the second coolant can be selected from a group consisting of water from a cooling tower system, sea water, air, or a combination thereof. That is, cooling tower 570 can be replaced or supplemented with sea water or air.

Fig. 11 also shows ISBL 592 of an LNG production facility which comprises multiple trains 200 as shown. As shown in Fig. 11, the ISBL units in ISBL 592 comprises primary cooling loops 512, 514, and 516 and the associated equipment shown. While not shown, it is understood that ISBL 592 further comprises the ISBL equipment from each train 200, such as the ISBL units illustrated as part of ISBL 202, such as those shown in Figs. 4 and 5 A, and consecutive cooling cycles 4 and 6 and the associated equipment, such as those shown in Figs. 1 and 2A. When a particular train 200 is operating and producing liquefied natural gas, the modules produce at least one process stream 596, 598, 600 that can be cooled further against an ambient temperature. For instance, the first and second mixed refrigerants from the cooling cycles that are connected to the liquefaction module can also be cooled against an ambient temperature. As described, train 200 comprises a primary cooling loop 512, 514, 516 to cool at least a process stream 596, 598, 600 from each module 210, and the first mixed refrigerant and the second mixed refrigerant against a first coolant comprising clean water, preferably consisting essentially of clean water. The primary cooling loop 512, 514, 516 is a closed clean water cooling loop and the cooling is against an ambient temperature. Train 200 comprises a first plurality of heat exchangers through which the primary cooling loop 512, 514, 516 extends. The cooling by the primary cooling loop 512, 514, 516 is via heat exchange in at least the first plurality of heat exchangers with respect to the first coolant. More than 50% of the first plurality of heat exchangers are printed circuit heat exchangers 502, 504, 506 which are are adapted to provide at least 80% of the cooling against the ambient temperature. The remaining less than 20% of the cooling duty against ambient temperature can be done using other types of heat exchangers such as ACHEs.

For the sake of simplicity, Fig. 11 shows streams 596, 598, and 600 for each respective train 200 for illustrative purposes of the applicable process streams from the modules and the first and second mixed refrigerants of the particular train 200, as well as any other process streams desirable to be cooled against an ambient temperature via primary cooling loop 512, 514, or 516, respectively. Streams 596, 598, and 600 extend through PCHEs 502, 504, and 506, respectively, which represent the more than 50% of the first plurality of heat exchangers through which the primary loop of a particular train 200 extends to provide cooling against an ambient temperature. The less than 50% of the first plurality of heat exchangers through which the primary loop extends can be other types of heat exchangers, such as ACHEs. It is understood that for the sake of simplicity, Fig. 11 depicts only one PCHE 502, 504, or 506 for a particular train 200, but that train can have any suitable number of PCHEs according to aspects of the facility and systems described herein. That is, train 200 can comprise 10 heat exchangers to cool against ambient, at least six of which would be PCHEs through which the primary cooling loop of train 200 (e.g., 512, 514, or 516) extends, and the at least six PCHEs provide at least 80% of cooling duty with respect to an ambient temperature for that train 200. Other trains 200 can have different numbers of heat exchangers for cooling against an ambient temperature consistent with the features described herein, depending on the particular design and/or specification as known to one of ordinary skills.

FIG. 11 shows a preferred embodiment where the cooling against an ambient temperature by the primary cooling loop 512, 514, or 516 is via secondary loop 550 where the thermal energy from ISBL 592 from the process streams and first and second mixed refrigerants of a respective train 200 is carried by the first coolant is transferred to secondary loop 550 in OSBL 594 and dissipated in OSBL 594. The thermal energy transfer from the primary cooling loop 512, 514, 516 to secondary loop 550 is via heat exchange against the second coolant in a second plurality of heat exchangers 540, 542, or 546 through which secondary cooling loop 550 extends.

Secondary cooling loop 550 comprises a suitable cooler to cool the second coolant against ambient temperature. For example, the cooler can be cooling tower 570 as depicted and described herein. While not shown, it is understood that cooling against an ambient temperature by the primary cooling loop 512, 514, 516 can be done without secondary cooling loop 550, such as by routing the first coolant through ACHEs that are located in the OSBL 594.

As provided, the embodiment depicted in Fig. 11 enables the moving of at least 80% of thermal energy from ISBL 592 to the OSBL 594 for dissipation against the ambient temperature in OSBL 594. This is in contrast with other types of heat exchangers, such as ACHEs, particularly ACHEs that are placed on top of ISBL units. Unlike train 200 described herein, a train with banks of ACHEs to provide the majority of cooling duty against an ambient temperature dissipates the thermal energy removed by the banks of ACHEs to the environment or ambient in the ISBL rather than in the OSBL, such as OSBL 594, as described herein By enabling dissipation of thermal energy in OSBL 594 in certain embodiments, the present disclosure to allows for a design of compact ISBL modules that are not limited by the size of the ACHE banks. Also, when heat dissipation occurs in the OSBL, there is flexibility around the mechanism through which that dissipation is achieved, such as through sea water, cooling towers, or air, without impacting the designs or configurations of the ISBL units, thereby allowing for train designs or aspects of train designs to be replicated from facility to facility.

Minimization of installed spares and valves. Traditional practice includes installing spared equipment such as pumps and their associated piping, valves and instrumentation in the respective modules. In other words, conventional modules used to comprise spare second versions of selected pieces of equipment, ready to be connected and used when a first version of said equipment failed. In the concept of the present disclosure, (some or all) equipment spares have been warehoused instead of installing them. These pieces of equipment are designed as ‘Plug and Play’ for easy removal and re-installation during a period of maintenance, also referred to as turnaround. Also, installation of bypass valves has been rationalized to significantly reduce the number of valves in a process unit. This approach enables the compactness of each module in the system 200 and further reduces the module weight for each respective module. For specifics and details, reference is made to, for instance, the disclosure of WO2019110770.

In the system of the disclosure, arrangement of equipment has been optimized. Optimizing the arrangement of equipment in the process modules 210-240 herein implies, for instance, that distance and piping requirement between respective pieces of equipment has been minimized. This in turn reduces the piping weight and module weight for each module 210 to 240. Reference is made to Figure 8.

Optionally, an additional and significant weight reduction for a respective module can be achieved by applying, for instance:

1. Single stage PMR instead of two-stage PMR. 'Single stage DMR' herein refers to a DMR liquefaction process with a single heat exchanger in the precool cycle 4 (as shown in, for instance, Fig. 2). ’Two-stage PMR' herein refers to a DMR liquefaction process comprising two consecutive heat exchangers in the precool cycle 4, each operation at a different internal pressure (as shown, for instance, in Fig. 1). Application of the single stage PMR process provides the potential to obviate a relatively heavy HP PMR suction drum (not shown), while adding a relatively light interstage cooler 17.

2. Obviating a PMR sub-cooler (relatively low impact on overall efficiency).

3. Obviating an HMR expander (i.e. no active expander at position 29 in Fig. 1-2; has relatively low impact on overall efficiency; can be replaced with expansion valve or JT valve)

4. Obviating an intercooling system on the AGRU absorber (and associated equipment). See, for instance, WO2016150827 for an intercooler on the AGRU absorber.

5. Use of PCHE’s with Closed cooling water system instead of shell-and-tube heat exchangers with open loop cooling water system (see Figure 8).

6. Run or maintain philosophy (as described in WO2019/110770), with less installed spares as a result, for instance: a. Series compressor configuration instead of parallel; b. No sparing of AGRU Charge pump; c. No sparing of AGRU Booster pump; d. No sparing of HTF pump; e. No sparing of Closed Cooling water pumps; and f Single Stabilizer overhead compressor (and associated equipment).

The following examples are provided to facilitate a better understanding of the leap forward provided by the system according to the present disclosure. In no way should these examples be construed to limit, or define, the scope of the invention.

Figures 12A to 12C provide plan views of exemplary liquefaction systems 200 to scale and for the same total capacity, to allow a comparison of footprint. The capacity is, for instance, about 7 mtpa for each of the facilities shown in Figures 12A, 12B and 12C.

Herein, Figure 12A shows two liquefaction systems 600 using state of the art C3MR liquefaction technology. Systems 600 have a width W1 and a length LI. Total width of the two systems 600 is W2 = 2*W 1.

Fig. 12B shows a liquefaction system 650 using state of the art DMR liquefaction technology. System 650 has a width W3 and a length L2. Total area covered by the system 650 is about 60% of the area covered by the two systems 600 in Fig. 12A. Fig. 12C shows two liquefaction systems 200 according to the present disclosure. Systems 200 have a width W4 smaller that the width W3 of the system 650. Systems 200 have a length L3. Herein, L2 equals about 2*L3. Total area covered by the system 200 is about 40% of the area covered by the two systems 600 in Fig. 12A.

Figure 13 shows facility 670 for the production of liquefied natural gas, comprising a number of liquefaction trains. The facility 670 comprises, for instance, two modular liquefaction trains 650 (see Figure 12B). The facility 670 may comprise four liquefaction systems 200 according to the present disclosure (see, for instance, Figure 12C). Figure 13 allows a side by side comparison of systems 200 and 650, allowing to put the saving in area (footprint) as mentioned with respect to Figures 12A to 12C into perspective. For the same area available for two reference systems 650 side by side, having a total width of 2 times W3, the system 200 of the present disclosure allows to arrange four systems 200 in a matrix. The latter would still leave additional space to place two additional systems 200 on the same area required for two state-of-the-art liquefaction trains 650. In other words, a facility comprising one or more liquefaction trains 200 in accordance with the present disclosure allows to increase the LNG production capacity per area with about 50%.

In an exemplary embodiment, system 200 compares favorably with respect to state-of-the-art modular facilities. Exemplary parameters are indicated in the table below.

With respect to the information included in the table above: System 200 with electric drivers for the compressors produces somewhat more per year due to higher availability and because electric drives power output is less dependent on the ambient temperature compared to gas turbine drives. The greenhouse gas (GHG) generation excludes GHG production of power generation. Overall, despite the smaller modules, a facility comprising a number of systems 200 according to the disclosure still requires fewer modules overall, with each process unit in one module, and fewer site hook-ups. Due to four smaller modular trains, the facility comprising four systems 200 includes more pieces of equipment in total, but each piece of equipment is smaller and lighter. And lighter modules reduce transportation costs. Also, heavier modules take longer to fabricate. The total number of fabrication yard hours to construct the modules reduces with almost 20%. The remaining expensive construction hours at the production site reduce with about 26%. The reduction in number of hours to construct both in the yard and on site is due to, for instance, the lower weight for each module weights and fewer site hookups, representing a significant cost saving.

As indicated in the table above, the number of pieces of equipment for all liquefaction trains combined increases with respect to a reference system. Also, the costs of certain individual pieces of equipment may be more expensive. For instance, Printed Circuit Heat Exchangers are more expensive than traditional Shell and Tube heat exchangers. However, equipment costs are only about 10% of the total installed costs. Thus, even though the costs to buy heat exchangers increases (for instance due to application of PCHEs), that contribution to the total installed costs is relatively low, substantially negligible. Consequently, the total procurement costs, i.e. the costs to obtain equipment, piping and bulk material (such as valves, etc.) is approximately the same for the system of the present disclosure and several reference projects as referred to herein. The total procurement costs represent approximately 20% of the total installed costs of a modular built LNG project. However, the total installed costs of the liquefaction systems according to the present disclosure is about 15 to 20% lower than the total costs to construct a conventional facility including relatively large modular LNG trains. Installed costs herein refer to capital expenditure to build the facility, including all liquefaction trains.

Figure 14 provides another comparison of plot space or footprint between a side-by-side arrangement of two systems 200 according to the invention, with a series of common utility units 750 arranged between the two systems 200. The utility units may include, for instance, an MLA unit 760 (Marine Loading Arms, i.e. arms for offloading cargo to a vessel), a fractionation unit 770, and a power generation unit 780. The setup may have a width W5 and a length L5. The setup of two systems 200 is compared with an exemplary state of the art and modular built liquefaction facility 700 having the same LNG production capacity.

As graphically shown in Figures 12 to 14, the system 200 of the present disclosure provides a significant reduction in plot space or footprint with respect to conventional facilities. Footprint reduction with respect to a stick-built facility may be in the order of 50 to 60%. Footprint reduction with respect to a state-of-the-art modular built facility may be in the order of 30 to 40%.

Another graphical representation of the significant reduction in footprint is provided in Figure 15. Herein, the ISBL area of the system 200 is indicated per unit of capacity (typically in mtpa) and compared to a range of conventional liquefaction facilities. Said facilities include both modular built facilities and stick-built facilities. The system 200 of the disclosure can require down to about 30% the area per mtpa of a conventional liquefaction facility (area herein is the inside battery limit area).

As indicated before, see for instance Figures 9 to 15, the system 200 of the disclosure provides significant advantages with respect to weight reduction and footprint reduction. With respect to other measures, the system 200 of the disclosure compared favorably with conventional liquefaction facilities also. See below.

As exemplified in Figure 16, a practical embodiment of the system 200 of the disclosure has a significantly lower green-house gas intensity than virtually any other conventional liquefaction facility. Greenhouse gas intensity herein is calculated excluding (bar 800) and including (bar 802) the total electrical power requirements, for instance generated by a typical combined cycle powerplant. Figure 17 indicates the equipment count per unit of production (typically in mtpa) compared to conventional facilities. Although the capacity for each train of system 200 individually is typically smaller compared to some traditional large (base load) liquefaction trains, the number of pieces of equipment per mtpa still benchmarks top quartile.

Figure 18 indicates the module weight per unit of production compared to traditional modular built LNG trains. Module weight is a key indicator for total installed costs and the figure shows that the system 200 of the present disclosure benchmarks “best in class”.

The system of the present disclosure provides significant cost savings, as it deals with substantially all aspects linked to capital expenditure of modular built facilities. For off-shore LNG plants and offshore gas production systems, modular built used to be the norm, as offshore used to have a strong focus on available plot space and weight reduction. For instance, water cooling has been used for cooling in offshore LNG production. The system of the present disclosure recognizes that despite abundant plot space and availability of air for cooling, for onshore modular LNG facilities implementing water cooling in combination with relatively light and small equipment, such as printed circuit heat exchangers, provides significant cost savings. The system and method of the current disclosure combine features and layout, and modular construction, to achieve optimal benefit and reduction of capital expenditure above and beyond state-of-the-art modular construction for onshore facilities.

The design of the system 200 of the present disclosure is agnostic for compressors drive. The driver of the precool compressor 14 and main compressor 22 may be for instance a gas turbine or an electric motor. The site layout and arrangement of modules remains substantially the same.

Summarizing the above, over the last 10-15 years, the LNG industry has seen a shift from traditional stick-built LNG export projects towards modular-built projects. The main driver behind this trend is to move construction work offsite to a fabrication yard where the modular process units are built in a more controlled environment benefiting from higher productivity, lower labor rates, better quality, fewer safety incidents and - as a result - more competitive, repeatable and predictable cost and schedule outcomes. If not applied as a design philosophy from the start, modular construction may however be disadvantaged by complex and expensive logistics, less efficient operations and maintenance and underutilization of local content opportunities.

Applicant's Modular LNG concept as disclosed herein combines and integrates various technologies, thus addressing not just one or two, but substantially all levers impacting the capital expenditure to fabricate and build a facility comprising modular built LNG trains. As a result, the facility of the disclosure allows to significantly reduce the costs of a facility including modular built LNG trains for a comparable total capacity. The facility according to the disclosure can have a comparable or better efficiency than conventional facilities, with best in class GHG emissions.

This is achieved by:

• Using DMR liquefaction technology and a selection of other low-weight, compact equipment, challenging the number of installed spares and reconfiguring the internal module layout and location of the main pipe rack.

• A conscious choice to apply water cooling, reducing the equipment weight and therefore module weights significantly and reducing the specific GHG emissions.

• Comprising at least one or more full process units inside a respective module. A process unit herein relates to a unit to perform a specific step of a liquefaction process, such as acid gas removal, dehydration, condensate stabilization. This enables to maximize pre-commissioning at the fabrication yard and minimizing interconnections and hookups between respective modules and hence minimizing work at the production location to interconnect the modules and construct the liquefaction train.

• Optimizing the capacity of each liquefaction train to between 2 to 4 MTPA. Larger trains suffer from large and heavy equipment and large bore piping. Smaller trains may suffer from interconnection inefficiencies for a given larger capacity.

• Offering essential configuration options with limited overall design impact. For instance, the refrigerant compressors can be driven by aeroderivative gas turbines or by electric motors. The choice does not change the overall layout of the LNG train of the disclosure.

• The design caters for a wide feed gas composition range and therefore enabling standardization and repeatability across multiple locations - with further potential benefits if using the same fabrication yards, contractors and main equipment vendors.

Comparison with other Modular LNG built trains indicate a 40 to 50% reduction in equipment weight, module weight and plot requirement (normalized per MTPA of installed capacity) and approximately 20% reduction in site construction hours as well as fabrication yard hours. Combined, this reduces the costs of the modular built LNG trains according to embodiments described herein with 20% or more with respect to conventional liquefaction systems, including modular built systems. The facility of the disclosure enables significant additional future savings at project portfolio level.

The present disclosure is not limited to the embodiments as described above and the appended claims. Many modifications are conceivable within the scope of the appended claims. Features of respective embodiments may be combined.

Claims

C L A I M S

1. A facility for the production of liquefied natural gas comprising:

- an inside battery limit (ISBL) (592) comprising a liquefaction train (200), wherein the liquefaction train (200) comprises

(a) a plurality of modules (210, 220, 230, 240) wherein each module being adapted to perform at least one process step associated with liquefied natural gas production, the plurality of modules comprising a first module (210) for acid gas removal; a second module (220) comprising a dehydration unit (222); a third module (230), being the liquefaction module; and a fourth module (240) comprising equipment for processing of natural gas liquids.

(b) a first mixed refrigerant cycle (4) comprising a first mixed refrigerant and a second mixed refrigerant cycle (6) comprising a second mixed refrigerant connected to the liquefaction module (230) for cooling a gas stream to produce the liquefied natural gas;

(c) a primary cooling loop (512, 514, 516) to cool at least a process stream (596, 598, 600) from each module and the first mixed refrigerant and the second mixed refrigerant against a first coolant comprising clean water, wherein the primary cooling loop (512, 514, 516) is a closed clean water cooling loop and the cooling is against an ambient temperature; and

(d) a first plurality of heat exchangers through which the primary cooling loop extends, wherein the cooling by the primary cooling loop is via heat exchange in at least the first plurality of heat exchangers with respect to the first coolant, wherein more than 50% of the first plurality of heat exchangers are printed circuit heat exchangers (502, 504, 506) and wherein the printed circuit heat exchangers are adapted to provide at least 80% of the cooling against the ambient temperature.

2. The facility of claim 1, wherein the liquefaction train (200) further comprises a second plurality of heat exchangers (540, 542, 546) through which the primary cooling loop extend to cool the first coolant by heat exchange with a second coolant, the facility further comprising: - an outside battery limit (OSBL) (594) comprising a cooler (570) for cooling against the ambient temperature; and

- a secondary cooling loop (550) extending through the second plurality of heat exchangers (540, 542, 546) and the cooler (570) to cool the second coolant against ambient temperature, thereby enabling moving of thermal energy from the ISBL (592) to the OSBL (594) for dissipation in the OSBL against the ambient temperature.

3. The facility of claim 2, wherein the second coolant comprising water from a cooling tower system, sea water, or air.

4. The facility of any previous claims, wherein each of the plurality of modules of the liquefaction train has a predetermined maximum weight threshold.

5. The facility of claim 4 wherein the predetermined maximum weight threshold is 6000 tonnes.

6. The facility of any previous claims, wherein for the liquefaction train, the first module (210) having a first side engaging a first side of the second module (220), and the second module (220) having a second side opposite the first side engaging a first side of the fourth module (240).

7. The facility of claim 6, wherein the liquefaction train further comprises a first module series comprising the first module (210) engaging the second module (220) engaging the fourth module (240), the first module series being aligned with and arranged adjacent to a second module series comprising the third module (230) arranged between the first compressor (14) on one side and the second compressor (22) on the opposite side.

8. The facility of any of previous claims, wherein the liquefaction train (200) further comprises:

- a first compressor (14) arranged on a first side of the liquefaction module (230) and connected to the first mixed refrigerant cycle for compressing the first mixed refrigerant; and

- a second compressor (22) arranged on a second side of the liquefaction module (230), the second side being opposite to the first side, and connected to the second mixed refrigerant cycle for compressing the second mixed refrigerant.

9. The facility of any of previous claims, wherein the liquefaction train (200) further comprises:

- a pre-cool heat exchanger (10, 12) arranged on the first side of the third module (230) and connected to the first mixed refrigerant cycle for pre-cooling the gas stream in heat exchange with respect to the first mixed refrigerant; and

- a main heat exchanger (20) arranged on the second side of the third module (230), the second side being opposite to the first side, and connected to the second mixed refrigerant cycle for at least partially liquefying the pre-cooled gas stream in heat exchange with respect to the second mixed refrigerant.

10. The facility of any previous claims, wherein the liquefaction train (200) further comprises a pipe-rack (280) for supporting conduits (282), the pipe-rack extending through at least the first module (210), the second module (220) and the fourth module (240).

11. The facility of any one of the previous claims, wherein the first mixed refrigerant cycle (4) comprises a single precool heat exchanger (10).

12. The facility of claim 11, wherein the first mixed refrigerant cycle (4) further comprises a compressor intercooler (17) adapted to cool first mixed refrigerant compressed by the first compressor (14) without condensing the first mixed refrigerant, an outlet of the compressor intercooler being connected to a subsequent stage of the first compressor (14).

13. The facility of any one of the previous claims, wherein the liquefaction train (200) has a capacity of production of liquefied natural gas in the range of about 2 to 4 MTPA.

14. A method comprising the step of producing liquefied natural gas using a facility according to any one of the claims 1 to 13.