WO2019110769A1

WO2019110769A1 - Compact lng production train and method

Info

Publication number: WO2019110769A1
Application number: PCT/EP2018/083886
Authority: WO
Inventors: Philip William MORLEY; Andries Kuivenhoven
Original assignee: Shell Internationale Research Maatschappij B.V.; Shell Oil Company
Priority date: 2017-12-07
Filing date: 2018-12-06
Publication date: 2019-06-13
Also published as: US20200309450A1; RU2020122311A; CA3083578A1; RU2020122311A3; AU2018380882B2; AU2018380882A1

Abstract

Disclosed is a liquefied natural gas production train, comprising at least one integrated process unit having a structural frame forming multiple process equipment floors. The at least one integrated process unit extends in vertical direction, wherein a height of the at least one integrated process unit is substantially equal to or larger than a width and a length of the at least one integrated process unit. The disclosure also provides a method of producing liquefied natural gas, using the LNG production train.

Description

COMPACT LNG PRODUCTION TRAIN AND METHOD

HELD OF THE INVENTION

The present invention is directed to a liquefied natural gas production train 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 APCI C3/MR™ or AP-X™ processes, the Phillips Optimized Cascade Process, the Linde Mixed Fluid Cascade process or the Shell Double Mixed Refrigerant or Parallel Mixed Refrigerant process.

Regardless of the choice of liquefaction technology, refrigerants are used to reduce the temperature of the treated gas to a temperature of around -l60°C to form LNG, resulting in warming of the refrigerant which must be compressed for recycle to the liquefaction process. The compressors used for this duty are traditionally gas turbines or electric motors depending on the power requirements and layout issues of a particular LNG production train. The coolers required for the various compression and heat exchanger operations associated with an LNG plant may be air coolers or water coolers arranged in a heat exchanger bank.

Prior art modularized LNG production trains have been closely based upon the design and layout of the more traditional stick-built LNG production trains. Until now, modularization has been conducted by slicing up an existing stick built LNG train design into transportable sections, leading to some compromises regarding the placement of the module boundaries. Prior art examples of modularization of a traditional air-cooled LNG train have relied on dividing the air-cooled heat exchanger bank into the smallest number of modules possible for a given size of air cooler within the air-cooled heat exchanger bank. To keep the overall plot size of the LNG production train to a minimum, it is known to arrange sub- sections of the air cooled heat exchanger bank over the top of each module so as to cover one hundred percent of the area defined by the base of said module with a view to making the air cooled heat exchanger bank as large as possible for a given module size. Having made the decision to fully cover each of the modules with a portion of the air-cooled heat exchanger bank, selected larger or taller pieces of process equipment operatively associated with each module, such as pressure vessels, compressors and the cryogenic heat exchanger are either stick built or constructed as separate modules which are designed to remain uncovered by the air-cooled heat exchanger bank.

The overall footprint of such modularized LNG production plants is large because sufficient plot space needs to be allocated to allow for covered modules incorporating the air-cooled heat exchanger bank to be positioned in a straight line mnning along the central longitudinal axis of the LNG production train with the uncovered modules being offset from the central longitudinal axis and located on one side or the other side of the centrally located air-cooled heat exchanger bank. This prior art design has several disadvantages. A high number of interconnections are required across the modules between the air-cooled heat exchanger bank covered modules and the associated equipment located on an adjacent uncovered module. The use of a large number of small modules inevitably requires that the air coolers within the air-cooled heat exchanger bank that are required to perform cooling duty for a particular module will need to span across at least two modules, preventing fluid circulation through the air coolers until these two modules are joined at the production location. These prior art designs rely on duplication of stmctural steel as there is inevitably a large amount of void space underneath the air- cooled heat exchanger bank in addition to the structural steel that is used for the uncovered spatially offset process equipment modules.

US-2014/053599-A1 discloses a liquefied natural gas production facility comprising a plurality of spaced-apart modules for installation at a production location to form a production train having a major axis and a minor axis, each module having a module base for mounting a plurality of plant equipment associated with a selected function assigned to said module, the module base having a major axis and a minor axis; and a plurality of heat exchangers arranged to run parallel to the major axis of the production train to form a heat exchanger bank having a major axis and a minor axis, wherein the major axis of the bank is parallel to the major axis of the train. A subset of the plurality of heat exchangers is arranged on a first level vertically offset from the base of at least one module to form a partially covered module, and wherein the major axis of the partially covered module is arranged to lie perpendicular to the major axis of the train when the partially covered module is installed at the production location. The heat exchanger bank has a footprint and the base of the partially covered module projects transversely outwardly beyond the footprint of the heat exchanger bank to provide an uncovered section of the module base on a first side of the heat exchanger bank. The uncovered section of the module base is sized for mounting a selected piece of process equipment. In another form, the heat exchanger bank has a footprint and the base of the partially covered module projects transversely outwardly beyond the footprint of the heat exchanger bank to provide a first uncovered section of the module base on a first side of the heat exchanger bank and a second uncovered side of the module base on a second side of the heat exchanger bank, wherein the first uncovered section is sized for mounting a first selected piece of process equipment and the second uncovered section is sized for mounting a second selected piece of process equipment.

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

Despite the many advantages and modular setup, the LNG production trains of US-2014/053599-A1 and US-2016/0010916-A1 still require a relatively large plot space. Also, capital expenditure is still relatively high.

In general, over the last one or two decades, LNG project costs (for instance when expressed in project costs per tonne per annum) have increased about 2 to 4 times in comparison to older LNG production facilities, older herein typically referring to plants constmcted before 1990. Typical Capex is currently in the range of USD l000-2000/tpa (or about 50 to 100 USD/tonne of LNG produced for a 20 years lifetime of the facility). Reasons for these increased costs of constmction are, for instance, one or more of the following. The time schedule for constmction is on average about 50% longer when compared to historic projects (e.g. constmcted before 1990). Costs of equipment (for instance compressors and heat exchangers) and raw material, such as steel and nickel, have doubled over time. In addition, many LNG facilities are planned to be built in, or have been built in countries having relatively high labor costs. Modularization, which for instance aimed to circumvent high labor costs by constmcting (modules of) facilities in a location having reduced costs of labor and subsequently move the preconstmcted modules to the LNG production location, has disappointed in practice, i.e. production costs remained relatively high compared to older facilities. Another factor which is sometimes mentioned is the reduced impact of innovation. LNG production trains typically have a significant impact on capital expenditure and plot space of an LNG production plant. Consequently, there remains a need to explore alternative designs for an LNG production train to improve on one or more of the disadvantages referenced above.

SUMMARY OF THE INVENTION

In one aspect, the present invention is directed to a liquefied natural gas production train, comprising at least one integrated process unit having a stmctural frame forming multiple process equipment floors. The multiple process equipment floors enable respective process equipment to be arranged vertically offset with respect to each other, allowing the footprint of each process unit to be relatively small.

In an embodiment, the at least one integrated process unit extends in vertical direction, wherein a height of the at least one integrated process unit is substantially equal to or larger than a width and a length of the at least one integrated process unit. The vertically built integrated process units extend in vertical direction, limiting the footprint. Limited footprint allows limiting capital expenditure, for instance by limiting constmction schedule overruns.

In another embodiment, the at least one integrated process unit extends in vertical direction, wherein a height of the at least one integrated process unit exceeds a width and a length of the at least one integrated process unit. The height of an integrated process unit may exceed the width and/or length thereof with a factor or at least 30%, or even 50% or more. Thus, integrated process units extend further in vertical direction (z) than in both horizontal directions (x, y).

In an embodiment, the stmctural frame of one or more of the at least one integrated process units being arranged on supports, the supports lifting a lower process floor a predetermined distance above ground. Lifting the lower process floor above ground level allows gravity draining of process sections. It also allows to limit required drainage points, as subsequent pieces of process equipment in a process section may all drain to the same drainage location. Drainage points may be shared with larger process equipment, such as cryogenic heat exchangers or compressors, which may be located at ground level. A limited number of drainage points at ground level is safer and may speed up restarting the liquefaction train after a shutdown. The predetermined distance may be in the order of 1 to 5 meters. In an embodiment, the at least one integrated process unit are connected to one or more pieces of process equipment arranged on the ground adjacent to the respective integrated process unit.

In an embodiment, the at least one integrated process unit comprising interconnected compact building blocks, each compact building block comprising one or more pieces of selected process equipment.

In another embodiment, the structural frame is provided with sets of building block rails, each set of building block rails being adapted for holding a corresponding compact building block; and the compact building blocks are provided with a runner device for moving the respective compact building block over a corresponding set of building block rails. The runner device may comprise rollers, skids, and/or sliders.

In yet another embodiment, the compact building blocks being provided with a removable transport frame for protecting the compact building block during transport. The transport frame may be sized to fit in a freight container.

In another embodiment, the compact building blocks in the at least one integrated process unit are arranged both horizontally and vertically displaced with respect to each other.

In an embodiment, the at least one integrated process unit comprising at least one process section comprising at least two or more pieces of process equipment interconnected by downward sloping pipe segments. The process section can be provided with a purging system connected to a secondary inlet of the process section. The process section can be provided with a vacuum system for the removal of hydrocarbons or other process streams, the vacuum system being connected to a gravitationally lower end of the process section. An outlet of the vacuum system may be connected to a flare and/or a vent to atmosphere. The gravitationally lower end of the process section can be provided with a liquid outlet with dedicated valve.

In an embodiment, the LNG production train comprises:

i) a pretreatment section for pre-treating a natural gas feed stream to produce a pre-treated natural gas stream;

ii) a first refrigerant compression section for pre-cooling the pre-treated natural gas stream to produce a pre-cooled gas stream and a first refrigerant vapor stream which is compressed therein; iii) a first refrigerant condenser section for condensing the first refrigerant vapor stream to produce a compressed first refrigerant stream for recycle to the first refrigerant compression section;

iv) a liquefaction section for further cooling the pre-cooled gas stream in a main cryogenic heat exchanger operatively associated with the liquefaction section through indirect heat exchange with a second refrigerant to produce a liquefied natural gas product stream and a second refrigerant vapor stream; and,

v) a second refrigerant compression section for compressing the second refrigerant vapor stream to produce a compressed second refrigerant stream for recycle to the liquefaction section.

In yet another embodiment, a single integrated process unit including at least part of at least two or more of the first refrigerant compression section, the first refrigerant condenser section, the liquefaction section, and the second refrigerant compression section.

In an embodiment, air cooled heat exchangers are provided on top of the at least one integrated process unit, the air cooled heat exchangers covering the entire integrated process unit including process equipment therein.

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

BRIEF DESCRIPTION OF THE DRAWINGS

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

Figure 1 shows a perspective view of a conventional stick-built LNG production train;

Figure 2 shows a top view of a conventional modular built LNG production train;

Figure 3 shows a perspective front view of an embodiment of an LNG production train according to the disclosure;

Figure 4 shows a perspective rear view of the embodiment of Figure 3 ;

Figure 5 shows a perspective view of another embodiment of an LNG production train according to the disclosure; Figure 6 shows a diagram of a method of operating at least two LNG production trains;

Figures 7-9 show respective side, top and front views of a method of operating an LNG production train;

Figure 10 shows a diagram of a method of operating an LNG production train;

Figure 11 shows a diagram of a conventional process section;

Figure 12 shows a diagram of an embodiment of a process section according to the disclosure;

Figure 13 shows a diagram of another conventional process section;

Figure 14 shows a diagram of another embodiment of a process section according to the disclosure;

Figure 15 shows a diagram of a conventional valve section in a conventional LNG production train;

Figure 16 shows an embodiment of a valve section according to the disclosure;

Figure 17 shows a diagram of a conventional pressure vessel section;

Figure 18 shows a diagram of an embodiment of a pressure vessel section according to the disclosure;

Figure 19 shows a diagram of a conventional column type process equipment section;

Figure 20 shows a diagram of an embodiment of a column type process equipment section according to the disclosure;

Figure 21 shows a perspective view of a compact building block provided with a transport frame.

DETAILED DESCRIPTION OF THE INVENTION

Certain terms used herein are defined as follows:

The term "LNG" refers to liquefied natural gas.

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

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

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

The term "stick-built" refers to an LNG production train which has sections built in subsequent order at the production location. Herein, stick-built is similar to conventional construction. Both refer to construction of a production train or another section of a plant predominantly at a production location. Herein, production location is the location of the plant itself.

In contrast, the term "module" refers to a section of a plant that may be preassembled at a construction or assembly location remote from the production location. Each module is typically designed to be transported from the construction or assembly location to the production location by towing or on floating barges or by land using, for instance, rail or truck. After each module is moved from the construction or assembly location to the production location, the module is positioned in a suitable pre-determined orientation to suit the needs of a given LNG production facility.

The term "building block" or "compact building block" refers to a part of a section of an LNG production train or plant that can be replaced relatively easily and with minimal interference with other parts or blocks of the production train or respective process section. This method of replacement may be referred to as plug- and-play. The building block may be assembled on the production location, or may be preassembled at a construction or assembly location remote from the production location. At the production location, the plant may be constructed by connecting building blocks to each other and to other process equipment in a predetermined manner.

Many of the building blocks may be relatively small, typically having a size comparable to, or fitting in a standard freight container (e.g. a 40 or 45 foot container). Thus, each building block may be designed to be transported from a maintenance location or assembly location to the production location and vice versa on floating barges or by land using, for instance, rail or truck. After each building block is moved from the maintenance or assembly location to the production location, the renovated or new block can replace a functioning block of the plant having a corresponding functionality, allowing the functioning block to be removed for maintenance. The latter may be referred to, or covered by the term“plug and play”.

In general terms, a process for liquefying a natural gas stream typically comprises certain process steps, embedded in subsequent sections of an LNG production train. Figures 1 to 3 show a few different conventional LNG production trains, including the typical sections.

Figure 1 shows an example of a liquefied natural gas (LNG) production train 1. The production train is a stick-built train, wherein all sections are arranged substantially one after the other. The production train 1 has a substantially longitudinal form, all section being arranged in longitudinal direction. The train 1 typically comprises subsequent sections for performing, at least, the process steps of: i) pre-treating a natural gas feed stream in a pretreatment section 10 to produce a pre-treated natural gas stream;

ii) pre-cooling the pre-treated natural gas stream in a first refrigerant compression section 12 to produce a pre-cooled gas stream and a first refrigerant vapor stream which is compressed therein;

iii) condensing the first refrigerant vapor stream in a first refrigerant condenser section 14 to produce a compressed first refrigerant stream for recycle to step ii); iv) further cooling the pre-cooled gas stream in a main cryogenic heat exchanger 16 operatively associated with a liquefaction section 18 through indirect heat exchange with a second refrigerant to produce a liquefied natural gas product stream 20 and a second refrigerant vapor stream; and,

v) compressing the second refrigerant vapor stream in a second refrigerant compression module 22 to produce a compressed second refrigerant stream for recycle to step iv).

In addition, the train typically comprises a pipe rack 24 extending in longitudinal direction along the length of the production train 1. Air cooled heat exchangers 26 are typically arranged on top of the pipe rack, to allow the release of heat rejected by the natural gas during cooling - which is cooled from ambient to cryogenic temperatures - to the environment.

For additional details of the cooling process and the respective sections of the LNG production train, reference is made to, for instance, one or more of LTS-6370910 (discloses aspects of one particular cooling process, the double mixed refrigerant process (DMR)), US-6389844 (discloses a parallel mixed refrigerant process), US- 2015/0300731, US-7152431 and US-9396854 (process to remove contaminants).

The production train 1 shown in Figure 1 has typical dimensions indicated by length Ll and width Wl, the length being significantly longer (for instance at least twice as long) than the width. Said length and width define a substantially longitudinal area, which may be referred to as the area inside the battery limit (ISBL). An LNG plant typically comprises other sections in addition to the LNG production train 1, which are located outside the battery limit (OSBL). Examples are the one or more LNG storage tanks 24 for storing the produced LNG 20. Also, the plant typically comprises sections for supply of natural gas and for offloading of the LNG, for instance a jetty for transferring LNG to an LNG carrier vessel.

Figure 2 shows an example of a prior art modular production train 2, with the above-referenced basic sections indicated. Herein, the respective sections 10, 12, 14, 18 and 22 of the train are comprised in corresponding modules 40, 42, 44, 46, and 48. Thus, prior art LNG production train 2 comprises the following modules:

a) a pretreatment module (40);

b) a first refrigerant compression module (42), in this example, a propane compression module;

c) a first refrigerant condenser module (44), in this example, a propane condenser module;

d) a liquefaction module (46); and,

e) a second refrigerant compression module (48).

Respective modules have covered sections covered by the air cooled heat exchangers 26, and uncovered sections 50. Process equipment is arranged on the uncovered sections of the respective modules. The covered sections do not comprise process equipment.

As example only, the first refrigerant may be propane while the second refrigerant may be a mixed refrigerant hydrocarbon mixture. This type of process is known as the propane pre-cooled mixed refrigerant, or C3MR process. Other processes, as mentioned in the introduction above, are equally conceivable. When using propane, or another hydrocarbon or mixture of hydrocarbons, as the first refrigerant, care is to be taken to ensure that the propane or mixture of hydrocarbons does not leak, because these are highly flammable. Using the process of the prior art, the process equipment required for propane compression is grouped together within a propane compression module to facilitate the pre-commissioning and commissioning of that module having all of the accessories that are needed to circulate fluid through the compressor at the production location. To further improve safety, the main rotating equipment associated with the propane compression circuit is placed on an uncovered section 50 of one of the plurality of modules, i.e. on a section of the modules not covered by air cooled heat exchangers 26, rather than underneath a plurality of air-cooled heat exchangers 26 arranged on an elevated level.

Although the width of the modularized LNG production train 2 may be a bit smaller than the width W 1 of the stick-built train 1 shown in Fig. 1, the length L2 of the train 2 (Fig. 2) is substantially similar to the length Ll of train 1 (Fig. 1).

In an alternative prior art modularized LNG production train (not shown, but see for instance US -2016/0010916), respective modules 40-48 may be arranged side- by-side rather than in subsequent order. Despite the potential advantages this may provide, the total footprint of the train remains the same as the footprint of the production train 2 shown in Fig. 2.

As a result, although the overall footprint (ISBL) of the modularized train 2 (Fig. 2) may be a bit smaller than the footprint of the stick-built train 1 (Fig. 1), in practice the capital expenditure turns out to be almost the same or even higher than the capital expenditure for a conventional stick-built train 1. As capital expenditure is - eventually - one of the most important deciding factors to indicate if and when an LNG production plant will break even, a plant with stick built LNG production trains is often more cost effective.

Applicant has found that, for instance, a significant cost factor in constmcting LNG plants is related to the actual preparation of the site. Preparation herein may include, but is not limited to, one or more of removing soil, arranging appropriate foundations, creating concrete base structures to hold process equipment and/or other sections of the facility. For instance the time schedule for the preparation of the site and the creation of the concrete base stmctures typically overruns, for instance with a factor of 50% or more. Cement need to dry after being poured in the correct place to form the concrete base, and drying of the cement slurry in practice typically takes longer than scheduled. Overruns of the construction schedule may lead to additional costs or delayed income due to, for instance, costs of equipment rental, labor costs, hiring of contractors, reduced net present value of the project due to delayed commencement of sales and/or potential claims for damages in supply contracts. In fact, these costs may be one of the most important causes of the increased capital expenditures of LNG production plants compared to older plants constructed prior to 1990.

In the history of onshore plant constmction, both pre-fabricated modules and stick built trains have been used extensively. The general view is that, unless local labor costs are unusually high and/or productivity is particularly low, a plant with stick built LNG production trains results in the lowest costs, albeit a longer production schedule and the most exposure to local influences and potential quality issues. The classic modular approach generally is seen to lead to a shorter overall production schedule and better quality of the LNG production train, yet at the expense of higher capital expenditure. This higher cost is mainly attributable to the required structural steel and the transportation cost of the modules.

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

To overcome these disadvantages, the applicant proposes a combination of unconventional and bold measures. As the measures and features described below are mutually beneficial, one or more thereof in combination may enable to dramatically bring down capital expenditure. The LNG production train of the disclosure can be built faster and at lower cost.

An embodiment of a liquefied natural gas production train 3 according to the present disclosure comprises one or more integrated process units 100, 110. One integrated process unit may combine multiple functional sections of the LNG production train. The integrated process unit(s) herein extends in horizontal or longitudinal direction, but also in vertical direction. This means that respective pieces of process equipment of the train which are comprised in the same integrated process unit may be arranged side-by-side, but also above each other on respective process equipment floors.

In the embodiment shown in Figs. 3 and 4, the LNG production train 3 comprises, for example, two integrated process units 100, 110. The first integrated process unit 100 may have multiple levels or process equipment floors 101, 102, 103 respectively, arranged on top of each other. The second integrated process unit 110 may have multiple levels 111, 112, 113 respectively, arranged on top of each other. The phrase multiple levels herein may imply at least two levels. The production units 100, 110 may have at least three or four levels, or more. Thus, the integrated process units 100, 110 of the LNG production train of the present disclosure may provide a stacked constmction. Herein, selected pieces of equipment may be arranged not only side by side, but potentially also vertically separated at a different vertical level in the same integrated process unit, thus limiting the area of the base of said unit. The plot size of the train will be limited accordingly. The integrated process units 100, 110 of the LNG production train 3 thus extend both in horizontal, longitudinal but also in vertical direction. The integrated process units form generally three dimensional structures.

For instance, the first integrated process unit 100 may comprise the entire gas pre-treatment section 10. The second integrated process unit 110 may comprise the refrigeration section. Herein, a pre-cooler 114 for precooling refrigerant may be arranged on a side of the integrated process unit 110. A main cryogenic heat exchanger 116 may be arranged on another side of the unit 110. The train may have a pipe rack 24, to hold pipes, for instance for providing natural gas to the train and for guiding liquefied natural gas to a storage tank (comparable to the facilities in Figs. 1 and 2).

The train may, for instance, comprise a scrub column 118 to remove heavy hydrocarbons from the natural gas before liquefaction thereof in the main cryogenic heat exchanger 116. Removal of heavy hydrocarbons, such as C6+ from natural gas is done prior to cryogenic liquefaction in order to prevent freeze-out of these components in the cryogenic heat exchanger 116. Traditionally, cryogenic methods such as passing feed gas through a scrub column 118 or a front-end NGL extraction unit (not shown) have been employed for this purpose. Adsorption-based separation processes are an alternative method to strip trace heavy hydrocarbons from natural gas. Adsorption may be a good alternative for the scrub column for certain feed gas streams such as lean natural gas containing relatively low amounts of C2-C4, yet significant amounts of C6+. Lately, several sources of natural gas, such as shale gas, coal-bed methane, etc., report lean feed gas of this nature. Although not shown, instead of the scrub column 118, an adsorption-unit or a front-end NGL extraction unit may be included in one of units 100 or 110.

Other pieces of equipment may be arranged at one of the various vertical levels of one of the units 100, 110, to render the design as compact as possible and to minimize the length of piping to interconnect said equipment. The units each have a mechanical support stmcture 122, to support the plurality of levels or process equipment floors 101-103, 111-113 respectively.

The mechanical support structure, or stmctural frame 122, may comprise a number of columns 126 extending in vertical direction interconnected by beams 128 extending in horizontal direction. The beams 128 and columns 126 support the respective process equipment floors.

The stmctural frame 122 of one or more of the integrated process units 100,

110 may be arranged on supports 115. The supports may be, for instance, blocks, column beams, or pillars. The supports 115 lift a lower process floor 101, 111 of the respective process unit 100, 110 a predetermined distance above ground 119. This may create a space 117 between the ground and the lower process floor. In a practical embodiment, the predetermined distance may be in the order of 0.5 to 5 meters or more. In practice, the predetermined distance may be in the order of 1 to 3 meters.

As described above, the integrated process units 100, 110 may be connected to one or more pieces of process equipment arranged on the ground 119 adjacent to the respective integrated process unit, such as the pre-cooler 114 and/or the cryogenic heat exchanger 116. The vertical elevation of the lower process equipment floor 101,

111 provided by the supports 115 assists draining of process sections using gravity. This may limit the requirement for pumps. The gravity draining also assists to limit the total number of drainage points (for instance as required when the LNG production process is stopped). The vertical elevation allows optimizing draining of process equipment sections by gravity, using a relatively limited number of drainage points. For more detail in this respect, please see the description below regarding Fig.

12.

In an embodiment, the train 3 may comprise one or more water cooled heat exchangers 124 to cool process streams and allow the LNG production train to get rid of the heat removed from the natural gas feed stream. In the stacked structure of the train 3, multiple water cooled heat exchangers may be arranged at various levels and throughout one of more of the integrated process units 100, 110. Thus, the heat exchangers 124 can be arranged relatively close to the related equipment and/or process stream which needs cooling, to limit, for instance, the length of piping, the related amount of steel and the number of connections and valves. Also, the water cooled heat exchangers 124 allow the integrated process units to be relatively compact.

The water cooled heat exchangers may, for instance, use seawater for cooling, which allows for a cost effective and efficient means of heat rejection. Options include once-through seawater cooling, a direct method of seawater cooling. Such method is suitable to be used for main shell and tube heat exchangers, including a refrigerant condenser, a sub-cooler and compressor coolers. The train may also include some smaller heat exchangers, which may employ an indirect, or closed loop system whereby the seawater (in a first loop) is used to cool fresh water (in a second loop) through the use of plate and frame exchangers. It may be preferred to select indirect seawater cooling for all the heat transfer services, including the refrigerant condenser and coolers, and avoid direct seawater completely.

Figure 5 shows an embodiment of an TNG production train 4 for the production of LNG, comprising three integrated process units 100, 110, and 120. The third integrated process unit 120 may comprise one or more compressor units. For instance, the third integrated process unit 120 may comprise, at least, a first compressor unit for compressing a first refrigerant stream. Optionally, the third process unit 120 may comprise at least a second compressor unit for compressing a second refrigerant stream. For details of an exemplary cooling process, including a compressor for a mixed refrigerant stream and the connections thereof with respect to other process equipment, reference is made to, for instance, patent application US20120103011. In an embodiment, the fan driven air coolers 26 can be arranged on top of one or more of the integrated process units. The train 4 comprises a number of integrated process units 100, 110, 120. Each unit comprises a mechanical support structure 122 comprising a plurality of process equipment floors or levels 101-103, 111-113. At least part of the process equipment for the cooling of a natural gas feed stream, or process gas stream, is arranged on the plurality of process equipment floors.

The process equipment comprises, at least, the cryogenic heat exchanger 116 wherein the process gas stream is indirectly heat exchanged against a refrigerant stream to produce cryogenically cooled LNG. Heat removed from the process gas stream is absorbed by the refrigerant stream. The pre-cooler 114 for precooling refrigerant and the main cryogenic heat exchanger 116 may be arranged alongside and connected to the integrated process unit 110.

In the embodiment of Fig. 5, the process equipment of the train 4 comprises at least an air draft cooler 26 arranged to establish indirect heat exchange between ambient air and, at least, a refrigerant stream leaving the cryogenic heat exchanger 116. In use, said refrigerant stream has been warmed due to the heat that has been absorbed from the process gas stream. Herein, heat from the warmed refrigerant stream is rejected to the ambient air. The air draft cooler 26 may comprise a fan to induce an air draft into the mechanical support stmcture 122, typically from the sides, and through the air draft cooler 26 in a direction away from the mechanical support structure, typically upwards.

With the embodiment of Figure 5, in the train 4 invention the process equipment and the air coolers 26 can all be shop built into the integrated process unit. Thus, the process equipment does not have to be connected to the air coolers 26 on site. In use, the air coolers 26 cause a current of relatively cool air around

predetermined heat exchangers and other process equipment located near the respective air cooler 26. Safety is guaranteed because as a result of the air current it becomes more difficult to accumulate an ignitable gas mixture in the integrated process unit, in case of a gas leak.

In the embodiment of Figure 5, the air coolers 26 are arranged at the uppermost process equipment floor, covering the respective process unit 100, 110, 120.

Although part of the process equipment, in particular the cryogenic heat exchanger 116, may be placed alongside an integrated process unit, the majority of the remainder of the process equipment is arranged inside one of the multi-leveled process units 100, 110. Said units in turn are substantially covered by air cooled heat exchangers 26 over their entire area in top view, also covering the pieces of process equipment arranged in the respective integrated process unit.

In a practical embodiment, the required total area covered by the air coolers may be in the order of 1900 m2 for an LNG production capacity of about 2 MTPA. This may be within the available bay area on top of the Gas Processing unit 100 and the Liquefaction unit 110. Part of the air coolers 26 may have to be fitter on top of the compressor unit 120. The area covered by air coolers 26 on top of the compressor unit 120 may be in the order of 550 m2, leaving scope for further capacity increase of LNG production.

A reduction in the area required for air coolers could involve fans providing relatively high air velocity - for instance using Whizz-Wheel® fans by Bronswerk Heat Transfer (The Netherlands). Alternatively, a reduction in aircooler area could be obtained by applying fans with groovy fins as supplied by GEA Group

Aktiengesellschaft (Germany). Thus, the required aircooler area can be fitted on a fourth process equipment floor 104, on top of the integrated process units 100, 110, 120 for an LNG production capacity up to at least 2 MTPA, as exemplified above.

In a practical embodiment - for instance of the production trains 3 or 4 - the integrated process units 100, 110 may have a size (length, width, height) in the order of 20m x 20m x 30m per unit. Height of a unit 100, 110 may be in the order of 20m to 40m or more. Height herein is defined as the distance in vertical direction between ground level 119 and a highest end of a respective unit. Both the LNG production train 3 and 4 may have a total length L3 in the order of 60-70m for a train having a capacity of about 1.5 to 2.5 mtpa. For comparison, a stick-built LNG production train 1 having a comparable capacity would typically have a length LI exceeding 200 m. Also, the width W3 of the production train 3 of the disclosure may be reduced with respect to the width W1 of a stick-built train because respective processing equipment can be arranged in a vertically stacked arrangement with respect to each other.

The integrated process units 100, 110 provide a vertically built LNG production train. Herein, a height H3 of one or more of the integrated process units 100, 110 is substantially equal to or larger than a width W 100 and/or a length L100, LI 10 of the respective integrated process unit 100, 110. In an embodiment, the height H3 of at least one of the integrated process units 100, 110 may exceed the width W100 and the length L100, LI 10 of the respective integrated process unit 100, 110. The height H3 of at least one of the integrated process units 100, 110 may, for instance, exceed the width W 100 and/or the length L100, LI 10 of the respective integrated process unit 100, 110 with a factor of about 30% or more. The height H3 may be, for instance, about 150% or more of the width W100 and the length L100,

LI 10 of an integrated process unit.

The production train 3 of the disclosure is also suitable for larger capacities, up to 4 to 5 mtpa or more per LNG production train. Cost savings may be even larger, as test runs and modelling have indicated that economies of scale apply to provide additional benefit. An optimal cost versus efficiency is achieved in the 4 to 5 mtpa capacity range.

The plot size (length L3 x width W3) of the LNG production train of the disclosure, inside the battery limit, may be about two times smaller than the plot size required for a conventional stick-built train (LI x Wl) having the same capacity (expressed in mtpa). In a practical embodiment, the required plot size may be even smaller, for instance at least three times smaller. In a practical embodiment, plot size of the LNG production train of the disclosure may be up to three to four times smaller than the plot size of a conventional LNG production train having the same capacity. The smaller plot size reduces capital expenditure. For instance, it provides savings associated with corresponding reductions in time required to prepare the production site, time to arrange appropriate foundations and base structures for the integrated process units. Also, the overshoot of the preparations will be reduced or substantially obviated entirely.

As shown in Fig. 6, in an embodiment, the integrated process units may each be assembled from a multitude of compact building blocks 150. Respective building blocks may be arranged side-by-side and also on top of each other. Each compact building block may comprise one or more pieces of selected process equipment. Each building block 150 forms a part of an integrated process unit 100, 110. The train 3 uses relatively small and compact equipment, selected to suit plant sections made up of the relatively compact building blocks 150 rather than adopting the prior art approach of relying on economy of scale.

In other words, each integrated process unit 100, 110, 120 is comprised of a number of compact building blocks 150. The sizes of respective building blocks may differ, depending on the size of respective pieces of equipment. Yet, the compact building blocks have a size which can be relatively easily transported.

As an example, Fig. 6 shows a first LNG production train 3A and a second TNG production train 3B, each comprising two integrated process units 100, 110 in accordance with the embodiments shown in, for instance, Figures 3-4 or 5. The integrated process units may be assembled using a number of interconnected building blocks 150. One of the building blocks, a scrub column block 160, may comprise the scrub column 118 and some associated pieces of equipment. For transport, the building block may be provided with a protective support frame 162. The support frame 162 typically comprises a number of interconnected stmctural beams, for instance made of steel or a corresponding high strength material, to form a substantially box shaped block 160. At an upper end, the support frame of a building block may be provided with suitable connectors for lifting, such as hoisting or rigging hooks 164.

The support frame 162 of one particular building block can be linked to corresponding support frames of adjacent building blocks 150 of the respective integrated process unit. Combined, the support frames of the building blocks 150 of the integrated unit form the support structure 122 of the integrated unit.

Figs. 7, 8 and 9 show respective side, top and front views of an embodiment of integrated compressor unit 120, comprising at least one compressor 170. The compressor, for instance a compressor for a (mixed) refrigerant, may be powered by an electrical generator 172, which in turn is driven by the output shaft of a gas turbine 174. In an exemplary embodiment, the gas turbine 174 may be included in a dedicated compact building block, indicated as gas turbine block 180. Like the scrub column block 160 (Fig. 6), the gas turbine block 180 may include some additional pieces of equipment associated with the functioning of the gas turbine 174. Also, the gas turbine block 180 may be provided with a support frame 162, typically at least enclosing the outer sides of the gas turbine block. Figs. 7-9 show exemplary steps Sl to S5 for removing a compact building block, such as gas turbine block 180. Placing a compact building block 150 in an integrated process unit may follow substantially the same steps, but in reverse order. In a first step SI, a crane 178, for instance a gantry crane, is moved into position above the selected building block. In a second step S2, the selected building block, in the example of Fig. 7 the gas turbine block 180, is hoisted upward (for instance using the hoisting hooks 164 and cables). In a third step S3, the crane moves the building block in horizontal direction away from the integrated process unit. In fourth step S4, the building block 150 is lowered to ground level to be transported for maintenance in a fifth step S5.

The compact building blocks allow more flexibility in the operation of the LNG train of the disclosure. For instance, as for instance indicated in Figs. 6 and 10, a compact building block 150 (comprising certain process equipment, for instance scrub column block 160 or gas turbine block 180) may be removed from the production train 3 for maintenance. As the building blocks are designed for easy transportation, for instance per ship 200, the maintenance may be done at a remote location. Such remote location may include a maintenance shop 202 and/or the factory 204 of the original equipment manufacturer (OEM) of the respective piece of process equipment.

When removing a building block for maintenance, another building block providing the same functionality may be inserted in the respective integrated process unit. If the production location is provided with at least two production trains, for instance a first production train 3 A and a second production train 3B (Fig. 6), this enables run-or-maintain type operation. This includes periodical maintenance at set time intervals, which if set appropriately will significantly limit downtime of the train by limiting or entirely obviating the tripping of process equipment.

The periodical maintenance may include, for instance, a set time period for removing one or more pre-selected building blocks 150 from the first production train 3A for maintenance. A set of spare compact building blocks may be provided, comprising new or renovated building blocks having the same functionality and process equipment as the building blocks of the respective production train. After removing the building blocks from a production train for maintenance, the building blocks can be replaced with the equivalent spare building blocks. By selecting the interval for maintenance for each building block 150 appropriately, the number of spare parts required may be significantly reduced. For a conventional stick-built train 1 (Fig. 1), typically the operation would include at least one spare part for virtually every piece of process equipment. The operation in accordance with the present disclosure allows operating an LNG production train having at least two or more trains 3, with only a single spare piece of process equipment. For instance, only a single set of spare compact building blocks may be sufficient. After maintenance, the maintained and renovated building blocks are returned to the production location. There, the renovated building block can replace the corresponding building block in the second train 3B. Operation for an LNG production plant having three or more LNG production trains will generally be similar, but will typically provide an even greater cost improvement, because a single set of spare parts or spare pieces of process equipment may be sufficient for reliable operation of all three LNG production trains.

In a practical embodiment, periodical maintenance for an LNG production facility according to the present disclosure may include, for instance, a set yearly maintenance period for each train 3 A, 3B, etc. The maintenance period, or turn around period, may be in the order of one to two weeks. During the maintenance period, the respective train to be maintained will be shut down. A selected number of pre-determined process equipment will be replaced with new or maintained process equipment building blocks providing the same functionality. The process equipment may be included in compact building blocks. Some of the process equipment may be replaced during every maintenance period, while other pieces of process equipment or valves may be replaced only once every two to four years. For instance, while preventative testing for safeguarding against equipment trips will be done every maintenance period, some process equipment may be tested and/or replaced only every second or third maintenance period, or less. For example:

- Every turn-around (yearly): Safeguarding testing; Amine filter; Gas Turbine; Generator; Transformers; Variable frequency drive;

- Every other tum-around (bi-yearly): Pump maintenance;

- Every third tum-around (every three years or less): Relief valve testing; Cleaning the amine section; Mercury removal section; Compressors; Molsieves; Switching valves. The overall layout of the production train 3 of the present invention, comprising for instance gas treating unit 100 and liquefaction unit 110, may be designed for modularization. This means that each building block 150 may be designed as a module, suitable to be constructed at a remote fabrication location and transportable to the production location. Herein, each integrated process unit 100,

110 may itself be assembled by connecting the respective building blocks, forming a plug-and-play type integrated stmcture, wherein building blocks can be connected and replaced for maintenance relatively easily.

The LNG production trains 3 or 4 of the present disclosure allow operation based on the principle of "run or maintain", as exemplified above. This mode of operation may obviates in the order of thousands of isolations, such as valves, that are traditionally installed to enable "hot" maintenance in a mnning plant (i.e. under the most difficult and hazardous circumstances). Hot maintenance herein refers to a reactive type maintenance, wherein parts and pieces of equipment are only replaced if and when they fail. This requires a multitude of spares on site, while also requiring replacement of equipment in a plant which has not yet fully cooled down from process conditions, hence the term "hot" maintenance. In a nutshell, the LNG production train of the present disclosure can achieve run-or-maintain type operation by combining one or more of the following elements:

- Elimination of the vast majority of operational problems by full automation;

- Simplify automation by removing process permutations (reducing the number of spares; reducing complexity of the train);

- Reduce design complexity by elimination of problems at root (for instance caused by human operators).

In addition to, and in combination with, the above described features of the LNG production train of the present disclosure, costs of the LNG plant are limited by setting a very strict cost target. In an exemplary embodiment, in the order of USD 200-300/tpa ISBL is deemed achievable. Thus, capital costs of the LNG production train of the present disclosure can be limited to the same level or lower as the costs of conventional LNG production trains of decades ago. Leatures and embodiments of the present disclosure can be applied in combination, and/or can be applied to other equipment and processes of the LNG production plant at large, adding to cost limitations. This concept is for instance possible by avoiding the usual cost creep. For instance, conventionally it was often argued that additional equipment is required to achieve safety and reliability goals. Yet, surprisingly, the applicant found that in most cases this reasoning is flawed. The additional equipment and complexity of the design and plant operations become the actual cause of incidents and unreliability. The simpler a design of the LNG production train is, the fewer failure modes the train has. As a result, operation is fundamentally safer and more reliable. These principles must be actively guarded during all phases of design because the natural tendency is to revert to classic complicated designs. The embodiments described below improve simplicity of the design, and thus limit costs while also improving process safety and significantly increasing uptime. The embodiments described below can, for instance, be combined with the vertical stacked design of the embodiments of integrated process units of trains 3 and 4. Alone or in combination, the features and embodiments of an LNG production train disclosed herein may ultimately allow for highly automated batch operation of the LNG production train.

It should be stressed that the LNG production industry, due to the inherent danger of processing explosive materials, has a strong focus on reliability, but conventionally this has resulted in a relatively conservative approach to plant design. In practice, this boils down to a strong preference for proven technology. In this context, the present disclosure provides significant improvements and potential break though ideas, ultimately enabling the industry to remain cost effective.

Numerous studies around Abnormal Situations (such as equipment trips and plant down time) mostly point to the same root causes. As a typical example, research by the Abnormal Situation Management (ASM) consortium has found that about 70% of "abnormal situations" and "unreliability" is caused by human error, either due to direct mistakes (40%), and/or to conscious or unconscious mistreatment of equipment (30% of total). This situation is expected to worsen in the future, due to an aging population and (too) limited supply of technical staff, having the right technical qualification. Thus, in combination with embodiments described herein, the LNG production train of the disclosure aims to remove human operators from direct control of the train and associated LNG production process, and to almost completely remove human operators from "decision making" in the line of command between business and the process equipment. In conventional operation, equipment failure is almost exclusively referred to as "Technical Failure". However, in practice almost all failures are the consequence of human choices, either directly or indirectly, consciously or unconsciously. It is human choice to properly commission, operate within limits, maintain, lubricate and so on. However, as an example, pump damage because it ran dry cannot be classified as genuine technical failure, as it would have been prevented if the pump would have been operated within its design limits. In short, equipment generally does not fail outside normal design limits, it typically gets killed. Although this is the root cause of the vast majority of equipment failures and trips, this is generally not taken into account. Without a large step-change (for instance, automated operation and a facility enabling automated operation), this conventional practice will continue.

An achievable aim is, for instance, operation wherein one or more of the LNG production trains disclosed herein is automated, such that the LNG production trains only require the presence of a small number, for instance one to three, operators during office hours (about 40 hours per week). The remaining time (128 hours per week), the production site can be unmanned. Off site and remote (for instance in a nearby town, maybe even at home, or in a major research center), there may be an operator on duty, equipped with a pager or similar device. In case of a plant trip (for instance caused by lightning strikes to disrupt power to equipment), the operator on duty can poll the plant status by means of a computer or tablet PC via a secured internet connection. Full and autonomous automated operation has proven to be far superior to any form of human control. It provides the best results in combination with hardware that has been specifically designed for it, as the embodiments of an LNG production train as disclosed herein.

As on-site organization will be almost entirely obviated, the monitoring, supervision and servicing of the facilities may be arranged through a Regional (or Global) Service Centre (RSC). There is no control room at the LNG production location in the traditional sense. Neither will offices be installed. Such RSC is envisaged as a cost-effective office space in existing Technology Centers, for instance the research centers of Applicant in Amsterdam (NL), Calgary (CA), or Houston (US). Here, abundant engineering support is already available. This would not only significantly simplify organizational barriers, but also create a more intimate involvement of "designers" with the end product. Additionally, this will be an almost natural environment for growing and developing the desired engineer-type of operations staff. Thus, the automated remote operation of the TNG production train of the invention may obviate local organizations and the associated overhead, buildings, etc. This improves cost-effective operation.

Redundancy can be provided by linking two or more RSCs via a network connection. This operating philosophy assumes that a (potentially large) number of TNG liquefaction facilities are monitored by an engineer position (for instance just one engineer) on a 24/7 basis from a remote location. Monitoring will not require continuous attention, but may be based on "one traffic light per facility", indicating either ok or not-ok, potentially with an intermediate (amber) indication.

To accommodate (near) zero-human presence at the production location, the TNG production train of the disclosure may have no isolation between equipment and no installed spares, as elucidated below. Maintenance shall be fully predictive and campaign based. For the avoidance of doubt, there shall be no designed breakdown ("run to failure") maintenance whatsoever. Maintenance shall be based on "plug and play" replacement (see for instance Fig. 6). There shall in principle be no "in situ repair" of parts or equipment; these will be replaced with fully maintained or new parts during the turnaround or maintenance period.

Fig. 11 shows a detail of a typical conventional train, with consecutive exemplary pieces of process equipment 210, 212, 214. Each piece of process equipment is provided with a dedicated relief system 220, 222, 224, connected to a common relief line 226. The process equipment is connected via horizontal pipe sections with dedicated valves 234, 236, with valves 230, 232 at the inlet and oulet of the exemplary process.

Such traditional designs are typically segmented and provided with numerous hose connections and vents to flare or atmosphere for safety. Removing

hydrocarbons is usually done by piston-purging with nitrogen, hooked up by hoses or by a fixed connection. Sometimes some form of heating up the purge gas is provided. Interconnecting piping typically spans relatively large horizontal distances, and is notoriously difficult to decontaminate (for instance, empty in case of an emergency). The piston purging requires large amounts of purge gas, which leads to constructing large nitrogen units to enable this. It typically takes several days and does not reach all extremities of the plant, sometimes leaving pockets of gas or liquid behind. It is not unusual to see continued gas-freeing still going on to halfway a shutdown, while managing the associated risks is complex. As a result, status change from running to stop and vice versa is relatively time consuming, with associated risks of incomplete purge.

Fig. 12 shows an embodiment of the process section 238 according to the disclosure, comprising the exemplary pieces of process equipment 210, 212, 214. Herein, said pieces of process equipment are interconnected by sloping pipe segments 235, 237. The downward sloping pipe segments 235, 237 are continuous and without valves. A purging system 242 may be connected to a secondary inlet of the process section, via a valve 244. At a gravitationally lower end of the process section, the process section may be provided with a vacuum system 246 via valve 252 to remove hydrocarbons or other process streams from the system. The lower end may also be provided with a liquid outlet 256 with dedicated valve 254. The vacuum system 246 may be connected to a flare 248 and/or a vent to atmosphere 250.

The embodiment of Fig. 12 provides a relatively compact, vertically oriented design without segmentation by valves between adjacent pieces of equipment. Preferably, the process equipment is connected via a downward sloping pipe, to allow draining by gravity. In an emergency, or during maintenance, liquid can be removed under (sub-atmospheric) pressure by the vacuum system 246. In a practical embodiment, the TNG production train may be provided with fluid outlets of the vacuum system located substantially at ground level, allowing relatively easy and simple maintenance. Also, the total number of such fluid outlets can be relatively limited.

In a practical embodiment, hydrocarbons can be removed from the process section by pulling vacuum (by opening valve 252). A suitable vacuum herein is, for instance, below 1 bara down to about 0.1 bara. Pulling vacuum multiple times, for instance about three times, can be combined with purging (filling the system and pipes 235, 237) with nitrogen in between. The embodiment of Fig. 12 allows to achieve a situation with about 0.1 vol% hydrocarbon or less in the process section shown in a relatively short time period. Short time period herein may be within 6 hours or less. This is far below the lower explosion limit, in other words a safe situation. After the last evacuation, air may be let into the process section. The embodiment has the additional benefit that the procedure obviates analytical equipment, as the adequacy is simply guaranteed by the process conditions. The process to remove hydrocarbons from the system ensures removal of hydrocarbons below the explosion safety limit, even in the smallest comers of the process section. The nitrogen demand is only a fraction of the piston purging method of the conventional system shown in Fig. 11.

In a practical embodiment, the TNG production train of the disclosure can be purged using about 500 m3 of gaseous nitrogen per flush (or about 1 m3 of liquid nitrogen). This can be supplied by a standard evaporator unit from for instance Tinde or Air Products. A threefold purge, guaranteeing very low hydrocarbon residue in the system, would require about l500m3 of gaseous nitrogen. The nitrogen would be delivered in, for instance, about 4 to 6 hours. This is achievable using, for instance, a relatively small Tinde evaporator (e.g. T 40-12F4T). The exemplary embodiment shows that this method enables fast removal of hydrocarbons from the system. The method obviates the requirement for a capex intensive large-volume nitrogen plant.

In an embodiment, the vacuum system 246 may also allow for water removal from the process section by applying deep vacuum (for instance down to about 10 mbar). In the TNG production train of the disclosure, this would be applicable for drying out after hydrostatic testing, or for a dry-out after a turnaround. Tests have indicated that water can be removed in about two days, as opposed to the usual nitrogen purging methods spanning about 2 to 3 weeks.

The vacuum system 246 may also allow leak testing prior to start up, by means of vacuum (for instance of about 0.1 bara). This is a fast and effective method to confirm that there are no leaks. As opposed to pressure testing, the vacuum method is not influenced by typical temperature-induced pressure swings, and is generally very sensitive. In combination with a fully welded design, it will speed up plant commissioning significantly.

In a practical embodiment, for instance the integrated liquefaction unit 110 (Fig. 3, 4) of the TNG production train 3 may be provided with (only) in the order of 7 to 8 relief systems 240 (for emergencies only such as fire or lightning). This is a significant limitation compared to the 300 to 400 relief devices 220, 222 in conventional plant designs. The embodiment of Fig. 12, in combination with the relatively compact and vertically oriented structures of the LNG production train 3 (Fig. 3), allow relatively rapid status changes (between operating and stopped) by dropping out liquids and removing remaining gas by vacuum. This is virtually impossible if parts of the train are horizontally spread out over a large area, such as the stick built train 1. In such case the interconnecting horizontal lines cannot, or only at great cost, be laid on slope over the relatively long horizontal distances involved. Decontamination of such systems is notoriously difficult, in particular if liquid remnants must be evaporated. Traditionally, this leads to complicated and lengthy piston purging procedures. In turn this leads to more valves in the design and to overall time loss and increased operational risk and complexity. Using gravity for draining, as with the embodiment of Fig. 12, is relatively easy and simple. The integrated process units 100, 110 of the present disclosure, wherein some equipment may be stacked on top of each other and the integrated process units 100, 110 may itself be elevated with respect to ground level by supports 115, will enable gravity draining. Interconnecting lines may be either vertical, or horizontal but sloping downward. The relatively short horizontal distances between subsequent pieces of equipment allow interconnecting piping to be laid sloping downward. In turn, this limits the number of draining points (252, 254) to only a few low points to drop out liquids, followed by complete removal of remaining hydrocarbons by vacuum.

In an embodiment, the LNG production train of the present disclosure aims to limit design complexity and simplify hardware. As exemplified in Fig. 13, in conventional LNG production facilities it is standard practice to install spares (260B, 262B) of process equipment in parallel with the main piece of process equipment (260 A, 262 A). Herein, the spare can take over if the main part trips, by switching the required valves 264 accordingly.

However, contrary to popular belief, installed spares (such as pumps) for properly operated and monitored equipment do not increase uptime. On the other hand, the spared systems significantly increase complexity, both with respect to hardware and in operating procedures. Moreover, automation of the myriad of possible permutations of spared systems is complex.

The simple exemplary embodiment shown in Fig. 14 indicates how the LNG production train of the present disclosure obviates spares and associated hardware such as valves. A first piece of process equipment 260 is directly connected, via piping 266, to a second piece of process equipment 262.

A special case of sparing is the bypass around control valves 270, shown in Fig. 15, conventionally included in an LNG production train. Fig. 15 shows a control valve 270, with block valves 272 to block the regular flow and direct it via bypass valve 275. This setup requires many welded connections 274 (indicated by dots; about 20 welded connections in a typical conventional bypass arrangement). As a result, the setup has many potential leak paths 276 (indicated by circles; about 18 leak paths in a typical conventional bypass arrangement).

The bypass is intended to enable reactively swapping a particular control valve 270 when it fails, while continuing the TNG production process. If this is required however, it is usually only in cases where proper, predictive maintenance has not been done. Besides, in practice, it turns out that it is substantially impossible to control a flow manually via the bypass valve 275 (by a human operator at the radio, 24 hours per day every day until the control valve 270 has been replaced) due to small changes in process dynamics. Also, isolating the control valve 270 under pressure is, in practice, often impossible due to leaking or non-moving block-valves 272. In operational reality, successfully removing and replacing one of the control valves 270 "on the run" is exceptionally rare. Moreover, the bypass arrangement shown in Fig. 15 may be and often is abused to enable to run the process outside the design operating window.

In an embodiment, the TNG production train of the disclosure is provided with control valves 270 without bypass arrangement (Fig. 16). This limits the number of welded connections 274 (for instance to about four) and the potential leak paths (for instance only one). This results in a reduction of direct costs for hardware (not only the manual valves, but also plot space, steel structure, provisions for accessibility, etc.). Yet it also results in indirect savings, as a bypass valve 276 generally incurs an additional flow rate requirement on the control valve 270 for safeguarding purposes, typically about 50% additional flow on top of a maximum flow rating of the control valve 270. This propagates into inflated design of other process equipment as well, for instance relief systems 220 (shown in Fig. 11). Removing the bypass on control valves in combination with automated operation and/or the run or maintain philosophy elucidated above limits capital expenditure while at the same time improving operational security (no trips; operating within design limits) and overall uptime (due to automated operation and the run or maintain philosophy).

As another example, pressure vessels 280 for process fluids in conventional facilities are typically provided with a double or triple set of relief valve stmctures. See Fig. 17. The relief valve structure functions as a safety valve, connecting the pressure vessel 280 to a flare 282 if the pressure inside the pressure vessel exceeds a safety threshold. The conventional relief valve structure typically comprises about eight valves 284-298.

In the TNG production train of the disclosure, relief valves are not spared. A pressure vessel 280 is provided with a single relief valve structure connected to the flare 282. The relief valve structure may have, for instance, about three valves 286, 288, 292. See Fig. 18.

The operating concept described above ensures that process variations are more limited with respect to conventional operation. Due to the run or maintain mode of operation, a typical accident due to accidental lifting of relief valves will be obviated. The "run or maintain" philosophy guarantees an annual opportunity to replace relief valves for testing and re-certification. The facility of the disclosure thus allows the design to be simplified, whereas all risks associated to "hot swapping" are eliminated.

Conventionally, column type process equipment 300 is provided with a reboiler 306 and associated pump 308 (Fig. 19). Typical combinations of reflux drum 306 and associated pump 308 usually involve significant amounts of complexity. Overhead vapor is typically condensed in a cooler 304, typically an air cooled heat exchanger. The cooled and condensed liquid is supplied from the heat exchanger 304 as a liquid to a condenser vessel 302. The liquid is pumped back into the column 300 by pump 310.

In an improved embodiment, shown in Fig. 20, the condenser vessel 302 is arranged above the column 300. The condenser vessel 302 may be integrated in the top part of the column. Herein, a cooling heat exchanger 316 is arranged at a gravitationally higher level than the condenser vessel 302. Warmed vapor will rise from the column to the heat exchanger 316, while cooler recondensed liquid will drop, by gravity, from the heat exchanger 316 to the condenser vessel 302.

Thus, reboiler pumps 310 can be eliminated. Optionally, the condenser vessel 302 may be connected to the top of the column 300 via a thermosiphon 314. In cases where 100% reflux is required (typical knock-back arrangements), the liquid stream from the overhead condenser 302 (which may be arranged at the top level of the integrated process units 100, 110. See Figs. 3, 4) can be routed back into the vessel 300, which is arranged in the same column shell as the condenser vessel 302. The small pressure differential across the condenser can be broken by a simple gravity- based siphon 314. Alternatively, the condenser vessel can be connected to the column 300 via a dip tube from column top to the top tray like a downcomer.

If the gas/liquid mixture from the overhead condenser 302 can be sufficiently separated inside the condenser 302, the top vessel might be eliminated as well. If some of the liquid must be removed from the process (for instance water control), a simple draw-off tray might be applied.

In addition, the concept of Gas plant in a Bottle, as marketed by Ortloff Engineers Ltd. (Texas, USA), for instance for the demethaniser. Such integration of heat- and mass-transfer into a single pressure shell greatly simplifies plant complexity and floor space.

In an embodiment, relatively small and compact equipment is selected to suit the plant sections made up of relatively compact building blocks. This replaced the conventional approach of relying on economy of scale, in particular for stick-built plants. Instead, smaller, more intensive equipment has been selected in order to be able to fit more items inside respective building blocks 150 of a limited size and weight. Using smaller units and keeping selected pieces of equipment integrated in the same building block, minimizes the number of piping connections to be made at the site of the production location.

As an example, Fig. 21 shows an amine filter unit 320 as a compact building block 150, provided with a support frame 162. In a practical embodiment, the amine filter 322 is enclosed by a support frame 162 having a size substantially compatible with, or fitting in, a standard (for instance 20 feet) freight container. The support frame 162 can hold a single vessel 322. Thus, the filter forms a "cartridge", suitable for plug and play type application. Connections are standardized and limited as much as possible. Optionally, a small circulation pump (not shown) may be integrated in the frame 162, to be maintained at every cartridge swap. If fitted in a low-pressure part of the system, such cartridge or compact building block 150 can be replaced in a matter of hours, and cost effectively transported by a standard truck and/or container ship to the original equipment manufacturer (OEM) or service center (Fig. 10).

In an embodiment, selected pieces of process equipment, such as the gas turbine and refrigerant compressor, can be included in a separate integrated process unit 120. This for instance enables the compression system to be fully tested up to a nitrogen test run stage at the construction or assembly location. The extra level of commissioning and testing at the construction or assembly location is beneficial in reducing the amount of carry-over work that has to be done at a significantly higher labor rate at the production site. The variable speed nature of the aero-derivative gas turbines simplifies the compressor start-up and eliminates the need to depressurize refrigerant. Removing the need for starter/helper motors for gas turbines used in prior art LNG trains also significantly reduces the maximum electrical power demand of the TNG train of the present disclosure and helps to limit the size of the compact building blocks 150.

As described above, the TNG production train 3, 4 of the present disclosure is suitable for operation in a normally unmanned mode. During tum-around, the train is manned and checked by operators. The TNG production trains of the disclosure allow automated start-up from maintenance to normal operation, and automated shut down for maintenance.

In the start-up procedure it is important to define the moment, at which the unit is handed over from the tum-around crew to operations. At this point the unit may be unmanned and the automatic start-up procedure takes over. As an example of startup of the gas treatment unit 100, it is assumed that the unit is handed over dry and leakage tested. Automatic startup, operation, and shutdown will be described. Other process sections of the TNG production train 3 or 4 may be likewise automated.

The first step to be reviewed is oxygen freeing of the unit. It is proposed to execute this task by pulling a vacuum on the unit and then fill the unit with nitrogen (see Fig. 12). Solvent is filled next. Ramping up of solvent, regenerator temperature and feed-gas flow can be achieved by sequences in the control system.

At this point the system can switch into normal operation and allow advanced process control loops to take over the optimization of the system in order to achieve the required treated gas specifications. A slow ramp up of the treated gas flow for the first one or two days of operation might be required. Similar sequences can be applied for startup of the unit after a short stop. The system will need to have the required diagnostic tools to judge from which step in the startup procedure the sequence needs to be initiated. Potential parts of the diagnostic tools could be pressures and temperature in absorber, flash and regenerator and solvent levels.

Operator rounds may be done to detect undesired conditions and allow timely intervention. Issues like local instruments readings, leakages or vibration noise at a pump are typical issues to check during a round. A number of these can be detected by additional instrumentation like:

- Liquid detection, or leak detection, on drain points 256, 254 in the liquid containment under the unit;

- Camera systems, which allow for monitoring of critical areas. The camara systems may record video data of preselected critical areas, and provide the video data to a monitoring system. The monitoring system may be provided with an algorithm to detect aberrations in the video data, which may for instance correspond to a potential leak. If the algorithm detects a potential leak in the video data, the monitoring system raises an alarm. Herein, the video camera may be coupled to an Analytic Video Monitoring System for Automated Real-Time Detection and Alarm Generation in Industrial Applications, such as marketed by IntelliView Technologies (Calgary, Alberta, Canada). An alternative automatic video monitoring system is marketed by FLIR Systems, Inc. (UK);

- Noise detection systems, which may trigger zoom-in by the camera system. Noise detection systems herein may include sound sensors (microphones) to detect sounds, coupled to a monitoring algorithm to raise an alarm in case unwanted sounds are detected;

- Vibration monitoring using sensors. Herein, the sensors to monitor vibration may include vibration sensors to detect vibrations, coupled to a monitoring algorithm to raise an alarm in case the detected vibrations exceed a predetermined safety threshold.

Additional robotic systems could be employed for special monitoring tasks.

Again referring to the gas treatment unit 100 as an example, shutdown of the LNG production process may be at least partly automated. Several levels of shut downs can be defined. In a first step of shutdown, only the feed gas flow would be shut in. No special additions to the design are required to restart.

In a next step of shutdown, a reboiler and amine circulation would be stopped. In order to recover from this state, a sequence, which re-establishes the amine circulation and ramps up the duty to the reboiler in line with ramping up the feed gas may be required.

For a full shut down in preparation for a maintenance period or turn-around, the following sequence may be suitable:

- Close gas supply and discharge line. Circulation of the solvent and operation of the regenerator can continue for a certain time to ensure regeneration of the solvent.

- Shut down of the reboiler. When the acid gas flow has decreased, close acid gas discharge. Stop the condenser and reflux system.

- Continue circulation of the amine until the whole solvent has been cooled down.

- Shut down solvent coolers.

- Pump-out of solvent via the booster pump into the amine storage tank.

- Upon reaching LZA-LL on the main amine levels, drain out the solvent.

Automatic draining of, for instance, solvent may be done using automatic valves 254 on drain connections 256 from the vessels and low points. During draining, nitrogen 242 may be admitted into the system or process section 238 to maintain an inert atmosphere. Therefore, in an embodiment the system includes a permanently hooked up nitrogen connection 242. In order to empty the process section 238, the process section can be slightly pressurized with gas to push out liquid. Automatic flushing of the system with demineralized water is an optional additional step.

The arrangement of the process equipment across each integrated process unit in the illustrated embodiments may be optimized to provide integrated process units of total weight in the order of 2000 to 8000 tons, preferably 3000 to 4000 tons. The capacity of the train is around 2 to 5 million tons per annum (mtpa) of LNG production. If a higher capacity is desired at a particular production location, two or more LNG production trains may be provided in combination. By way of example, two trains 3 A, 3B according to the present disclosure may be arranged at a production location to provide an overall LNG production capacity of, for instance, 4 to 10 mtpa.

The production location can be onshore, offshore on a floating facility, offshore on a fixed facility, or a barge-mounted or grounded facility. By way of example, the compact building blocks may be floated-in using steel or concrete gravity based structures with integrated LNG storage, loading and boil-off gas re-liquefaction functionality. Gas may be supplied to the production location via a (subsea) pipeline.

The LNG plant may further include optional treatment steps such as product purification steps (for instance helium removal, nitrogen removal, mercury removal) and non-methane product production steps (de-ethanizing, de-propanizing, sulphur recovery) if desired. The natural gas feed stream may be produced at and obtained from a natural gas or petroleum reservoir. As an alternative, the natural gas feed stream may also be obtained from another source, also including a synthetic source such as a Fischer-Tropsch process wherein methane is produced from synthesis gas.

The present disclosure involves a number of technologies and a step out operational and maintenance philosophy to allow for a significant reduction in CAPEX. Capital expenditure may be in the order of 30% compared to CAPEX of a typically stick built LNG production train (i.e. a cost reduction of about 70%). The step out operational philosophy may be referred to as“remote operation” or “normally unmanned installation”.

Remote operation allows a particular part of the plant (such as the processing units) to be operated from a distance. This in turn allows staff to be located and to work in and from, for instance, an urban area rather than from a remote area. This allows for a cost reduction related to facilities for staff, and in addition reduced operating costs. Also, this may significantly increase job satisfaction for staff while also limiting staff turnover.

The step out maintenance philosophy may be referred to as run or maintain.

The mn or maintain operation involves the removal of installed spares and the surrounding valves and piping and consequently allows for a reduction in construction scope and associated costs.

The“frugal” concept per embodiments disclosed above revolve around replacing a century-old petroleum industry design approach that is geared to "keep mnning at all times" and "operating by (fallible) humans". This traditional, so far unchallenged hybrid is inherently error-prone and leads to increasingly complicated and costly plant designs and associated organizational practices. In the order of 80% of the trips and downtime in the LNG industry may be the result of human error. The “frugal” design philosophy combines one or more features of the embodiments described above. The concept is particularly beneficial for newly built, small and mid-sized LNG facilities (in the order of 1 to 3 mtpa, for instance about 2 to 2.5 mtpa per train) are ideally suited for the Fmgal class of operations. The concept disclosed herein may comprise:

- Run the facility using a run or maintain (Either operate or maintain) schedule. This schedule comprises the step of periodical maintenance including replacement of selected hardware for offline renovating. This obviates the need for thousands of hardware provisions and associated opportunities to induce incidents. The design includes means to provide very rapid transitions between the operational state and a fully product free state;

- Remove human error and related process upsets by application of Fully Autonomous Process Control, to enable a process design in the simplest possible way;

- Enhanced Process Safety by reducing or eliminating flammable inventory and physically separating the human operators from hazard (unmanned operation).

It is stressed, that although the concepts of the embodiments described above introduce simplicity in the design and operation of the LNG facility, actual implementation is a significant organizational challenge in an industry heavily reliant on proven technology concepts due to risk avoidance because of the combination of handling vast amounts of flammable or even explosive material (hydrocarbons) and significant upfront investment (in the order of billions of USD per project).

Yet, the estimated benefits of the application of one or more of the concepts and embodiments described above, alone or in various combinations, may provide up to:

- CAPEX reduction up to -40% on a USD/tpa basis (compared to facilities constructed in the last decade);

- Further CAPEX reduction through staged investment (staged installation of multiple relatively simple trains to together form a larger plant; - OPEX reduction up to -50% (compared to facilities constructed in the last decade) due to a reduction or elimination of local organizations and the unmanned concept;

- Faster construction and deployment (within planned schedule) due to "plug and play" of compact building blocks. Reduction of unforeseen delay and additional work;

- An improvement of process safety by up to 1 to 3 orders of magnitude (due to non-flammable refrigerants, elimination of opportunities to create incidents, almost complete elimination of personnel on site).

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

The following examples of certain aspects of some embodiments are given to facilitate a better understanding of the present invention. In no way should these examples be read to limit, or define, the scope of the invention.

Claims

What is claimed is:

1. Liquefied natural gas production train, comprising at least one integrated process unit having a stmctural frame forming multiple process equipment floors.

2. The LNG production train of claim 1, the at least one integrated process unit extending in vertical direction, wherein a height of the at least one integrated process unit is substantially equal to or larger than a width and a length of the at least one integrated process unit.

3. The LNG production train of claim 1, the at least one integrated process unit extending in vertical direction, wherein a height of the at least one integrated process unit exceeds a width and a length of the at least one integrated process unit.

4. The LNG production train of any of claims 1 to 3, the structural frameof at least one of the at least one integrated process units being arranged on supports, the supports lifting a lower process floor a predetermined distance above ground.

5. The LNG production train of claim 4, the predetermined distance being in the order of 1 to 5 meters.

6. The LNG production train of one of the previous claims, the at least one integrated process unit being connected to one or more pieces of process equipment arranged on the ground adjacent to the respective integrated process unit.

7. The LNG production train of one of the previous claims, the at least one integrated process unit comprising interconnected compact building blocks, each compact building block comprising one or more pieces of selected process equipment.

8. The LNG production train of claim 7,

the structural frame being provided with sets of building block rails, each set of building block rails being adapted for holding a corresponding compact building block; and

the compact building blocks being provided with a mnner device for moving the respective compact building block over a corresponding set of building block rails.

9. The LNG production train of claim 8, the mnner device comprising rollers, skids, and/or sliders.

10. The LNG production train of 7, the compact building blocks being provided with a removable transport frame for protecting the compact building block during transport.

11. The LNG production train of claim 10, the transport frame being sized to fit in a freight container.

12. The LNG production train of claim 7, the multiple process equipment floors of the at least one integrated process unit each being provided with at least one of the compact building blocks.

13. The LNG production train claim 7, the compact building blocks in the at least one integrated process unit being arranged both horizontally and vertically displaced with respect to each other.

14. The LNG production train of any of claims 1 to 13, the at least one integrated process unit comprising at least one process section comprising at least two or more pieces of process equipment interconnected by downward sloping pipe.

15. The LNG production train of claim 14, the process section being provided with a purging system connected to a secondary inlet of the process section.

16. The LNG production train of claim 14, the process section being provided with a vacuum system for the removal of hydrocarbons or other process streams, the vacuum system being connected to a gravitationally lower end of the process section.

17. The LNG production train of claim 16, an outlet of the vacuum system being connected to a flare and/or a vent to atmosphere.

18. The LNG production train of claim 16, the gravitationally lower end of the process section being provided with a liquid outlet with dedicated valve.

19. The LNG production train of any of the previous claims, comprising:

ii) a first refrigerant compression section for pre-cooling the pre-treated natural gas stream to produce a pre-cooled gas stream and a first refrigerant vapor stream which is compressed therein;

iii) a first refrigerant condenser section for condensing the first refrigerant vapor stream to produce a compressed first refrigerant stream for recycle to the first refrigerant compression section; iv) a liquefaction section for further cooling the pre-cooled gas stream in a main cryogenic heat exchanger operatively associated with the liquefaction section through indirect heat exchange with a second refrigerant to produce a liquefied natural gas product stream and a second refrigerant vapor stream; and,

20. The LNG production train of claim 16, a single integrated process unit including at least part of at least two or more of the first refrigerant compression section, the first refrigerant condenser section, the liquefaction section, and the second refrigerant compression section.

21. The LNG production train of any of the previous claims, wherein air cooled heat exchangers are provided on top of the at least one integrated process unit, the air cooled heat exchangers covering the entire integrated process unit including process equipment therein.

22. Method of producing liquefied natural gas, using an LNG production train according to any of the claims 1 to 21.