JP6800977B2 - Precooling of natural gas by high pressure compression and expansion - Google Patents

Description

[Cross-reference to related applications]
This application is in the interest of US Provisional Patent Application No. 62 / 266,985, filed December 14, 2015, entitled "Precooling Natural Gas by High Pressure Compression and Expansion," which is incorporated herein by reference in its entirety. Is to insist.

This application, all having a common inventor and transferee, was filed on the same date as this specification, and its disclosure is incorporated herein by reference in its entirety, "using liquefied nitrogen. US Provisional Patent Application No. 62 / 266,976 entitled "Methods and Systems for Separating Nitrogen from Liquefied Natural Gas", US Provisional Patent entitled "Expansion-based LNG Production Process Enhanced by Liquid Nitrogen" Related to Application No. 62 / 266,979 and US Provisional Patent Application No. 62 / 266,983 entitled "Method of Liquefied Natural Gas on an LNG Carrier Retaining Liquid Nitrogen". ..

The present invention relates to the liquefaction of natural gas to form liquefied natural gas (LNG), more specifically the construction and / or maintenance of major facilities and / or the environmental impact of conventional LNG plants. Concerning the production of LNG in remote or sensitive areas that may be harmful.

LNG production is a rapidly growing means of supplying natural gas from locations with abundant supply of natural gas to remote locations with strong demand for natural gas. Traditional LNG production cycles include a) initial treatment of natural gas resources to remove contaminants such as water, sulfur compounds, and carbon dioxide, b) self-freezing, external freezing, dilute oils, and more. Separation of some heavy hydrocarbon gases such as propane, butane, pentane, etc. by possible methods, c) Natural by practically external freezing to form liquefied natural gas at near atmospheric pressure and about -160 ° C. Gas refrigeration, d) Transportation of LNG products to market locations by ship or tanker designed for this purpose, e) Regasification plant for pressurized natural gas that can be distributed to natural gas consumers Includes repressurization and regasification of LNG in. Stage (c) of the conventional LNG cycle usually requires the use of a large refrigeration compressor, often powered by a large gas turbine driver that emits substantial carbon and other emissions. Billions of US dollars and large capital investments in large infrastructure are required as part of the liquefaction plant. The conventional LNG cycle step (e) is generally the step of repressurizing LNG to the required pressure using a cryogenic pump and then finally exchanging heat with seawater through an intermediate fluid. Includes the step of regasifying LNG to pressurized natural gas by burning a portion of natural gas to heat and evaporate the LNG.

Although LNG production is generally known, technological improvements can still provide significant opportunities for LNG producers when maintaining their leading position in the LNG industry. For example, floating LNG (FLNG) is a relatively new technical option for producing LNG. This technique involves the construction of gas treatment and liquefaction facilities on floating structures such as barges or ships. FLNG is a technical solution for monetizing offshore residual gas that cannot economically build a gas pipeline to the coast. FLNG is also increasingly considered for onshore and coastal gas fields located in remote, environmentally sensitive, and / or politically difficult areas. This technique has certain advantages over traditional onshore LNG in that it has a reduced environmental footprint at the production site. The technology will also allow projects to be delivered faster and at lower cost, as most of the LNG facilities will be built at shipyards with lower wages and reduced risk of contract conclusion.

FLNG has several advantages over traditional onshore LNG, but significant technical problems remain in the application of the technology. For example, FLNG structures need to provide the same level of gas treatment and liquefaction in less than a quarter of the area or space that is often considered available for onshore LNG plants. For this reason, there is a need to develop technologies that reduce the footprint of liquefaction facilities while maintaining their capacity, thereby reducing overall project costs. Several liquefaction techniques have been proposed for use in the FLNG project. Leading techniques include a single mixed refrigerant (SMR) step, a double mixed refrigerant (DMR) step, and an expander-based (or expanded) step.

Unlike the DMR process, the SMR process has the advantage of adapting all equipment and bulk associated with the complete liquefaction process within a single FLNG module. The SMR liquefaction module is placed on the upper deck of the FLNG structure as a complete SMR train. This "in-box LNG" concept is preferred for delivery of FLNG projects as it allows testing and commissioning of SMR trains at locations different from where the FLNG structure is constructed. It can also make it possible to reduce labor costs, as it reduces working hours at shipyards, where wages tend to be higher than wages in traditional production yards. The SMR process has the additional advantage of being a relatively efficient, simple, and compact refrigerant process when compared to other mixed refrigerant processes. In addition, the SMR liquefaction process is typically 15% to 20% more efficient than the inflator-based liquefaction process.

The choice of SMR process for LNG liquefaction within the FLNG project has its advantages, but the SMR process has some drawbacks. For example, the required use and storage of flammable refrigerants such as propane significantly enhances the loss prevention problem for FLNG. The SMR process is also limited in capacity, which increases the number of trains required to reach the desired LNG production. For these reasons and others, a significant amount of upper deck space and weight is required for the SMR train. Since upper deck space and weight are significant drivers for FLNG project costs, there is a need to improve the SMR liquefaction process to further reduce upper deck space, weight, and complexity, thereby improving project economics. Remaining.

The inflator-based process has several advantages that make it well suited for FING projects. The most significant advantage is that this technique provides liquefaction without the need for external hydrocarbon refrigerants. Eliminating liquid hydrocarbon refrigerant inventories such as propane storage significantly reduces safety concerns regarding FLNG projects. An additional advantage of the expander-based process over the mixed refrigerant process is that the expander-based process is less sensitive to offshore motion because the main refrigerant remains mostly in the gas phase. However, the application of expander-based processes to FLNG projects with LNG production of over 2 million tonnes (MTA) per year has shown to be less attractive than the use of mixed refrigerant processes. The capacity of the inflator-based process train is typically less than 1.5 MTA. In contrast, a mixed refrigerant process train, such as a known dual mixed refrigerant process, can have a train capacity of greater than 5 MTA. The size of the inflator-based process train is limited because the refrigerant remains mostly vapor throughout the process and the refrigerant absorbs energy through its sensible heat. For this reason, the volumetric flow rate of the refrigerant is large throughout the process, and the size and piping of the heat exchangers are proportionally larger than those of the mixed refrigerant process. In addition, the stretcher horsepower size limitation results in a parallel rotating machine as the capacity of the inflator-based process train increases. The production rate of FLNG projects using inflator-based processes can be greater than 2 MTA if multiple inflator-based trains are allowed. For example, for a 6MTA FLNG project, a parallel expander-based process train of 6 or 7 or more may be sufficient to achieve the required production. However, total equipment, complexity, and cost all increase with multiple inflator trains. In addition to this, when multiple trains are required for the expander-based process, while the mixed refrigerant process can obtain the required production rate with one or two trains, compared to the mixed refrigerant process. The assumed process simplicity of the inflator-based process begins to be questioned. For these reasons, there is a need to develop a high LNG production capacity FLNG liquefaction process that has the advantages of an inflator-based process. There is a further need to develop FLNG technology solutions that can better address the challenges that ship movement poses to gas processing.

U.S. Pat. No. 6,421,302 describes a supply gas expander-based process in which two independent closed freezing loops are used to cool the supply gas to form an LNG. In the embodiment, the first closed freezing loop uses a supply gas or a component of the supply gas as a refrigerant. Nitrogen gas is used as a refrigerant for the second closed freezing loop. This technique requires smaller equipment and upper deck space than a double-loop nitrogen inflator-based process. For example, the volumetric flow rate of the refrigerant into the low pressure compressor can be reduced by 20 to 50% with this technique compared to a double loop nitrogen expander based process. However, this technique is still limited to capacities less than 1.5 MTA.

U.S. Pat. No. 8,616,012 describes a feed gas expander-based process in which the feed gas is used as a refrigerant in a closed freezing loop. Within this closed freezing loop, the refrigerant is compressed to a pressure greater than or equal to 1,500 psia (10,340 kPa), or more preferably greater than 2,500 psia (17,240 kPA). The refrigerant is then cooled and expanded to reach a very low temperature. This cooled refrigerant is used in the heat exchanger to cool the supply gas from warm to extremely low temperatures. The subcooled freezing loop is then used to further cool the supply gas to form LNG. In one embodiment, the subcool freezing loop is a closed loop with flush gas used as a refrigerant. This supply gas expander-based process has the advantage of not being limited to a train capacity range of less than 1 MTA. A train size of about 6 MTA is considered. However, this technique has the drawbacks of high total number of equipment and increased complexity due to its requirements for two independent freezing loops and compression of the feed gas. In addition, high pressure operation also means that the equipment and piping will be much heavier than those in other inflator-based processes.

GB 2,486,036 describes a feed gas inflator-based process that is an open loop refrigeration cycle that includes a precooling inflator loop and a liquefied inflator loop that uses the expanded gas phase to liquefy natural gas. There is. According to this document, the inclusion of a liquefied expander in the process significantly reduces the proportion of recycled gas and the overall required freezing power. This technique has the advantage of being simpler than the other techniques as it uses only one type of refrigerant in a single compression string. However, this technique is still limited to capacities less than 1.5 MTA, which requires the use of non-standard equipment liquefied expanders for LNG production. This technique has also been shown to be less efficient than other techniques for liquefaction of dilute natural gas.

U.S. Pat. No. 7,386,996 describes an inflator-based process with a pre-cooling and freezing process that precedes a main inflator-based cooling circuit. The pre-cooling and freezing process involves a cascaded carbon dioxide refrigeration circuit. Carbon dioxide refrigeration circuits are predominantly at three pressure levels: a high pressure level that provides warm end cooling, a medium pressure level that provides intermediate temperature cooling, and a low pressure level that provides cold end cooling for the carbon dioxide refrigeration circuit. The supply gas and the refrigerant gas of the inflator-based cooling circuit can be cooled. This technique is more efficient and has a higher production capacity than inflator-based processes that lack a precooling step. This technique has additional advantages for FLNG applications as the precooling and refrigerating circuit uses carbon dioxide as the refrigerant instead of the hydrocarbon refrigerant. However, the carbon dioxide refrigeration circuit introduces additional refrigerant and a substantial amount of extra equipment at the cost of additional complexity to the liquefaction process. For LNG applications, the carbon dioxide refrigeration circuit can be sized to be within its own module and provide precooling for multiple inflator-based processes. This arrangement has the drawback of requiring a significant amount of pipe connection between the precooling module and the main inflator-based process module. The "in-box LNG" advantage discussed above is no longer realized.

US Provisional Patent Application No. 62 / 266,976 US Provisional Patent Application No. 62 / 266,979 US Provisional Patent Application No. 62 / 266,983 U.S. Pat. No. 6,421,302 U.S. Pat. No. 8,616,012 GB 2,486,036 U.S. Pat. No. 7,386,996

That is, there remains a need to develop a precooling process that does not require additional refrigerant and does not introduce a significant amount of extra equipment into the LNG liquefaction process. There is an additional need to develop a precooling process that can be placed in the same module as the liquefaction module. Such a precooling process in combination with an SMR process or an inflator-based process is considered to be particularly suitable for FLNG applications where upper deck space and weight have a significant impact on project economics. There remains a specific need to develop an LNG production process that has the advantages of an inflator-based process, plus a high LNG production capacity without significantly increasing the facility footprint. There is a further need to develop FLNG technology solutions that can better address the challenges that ship movement has for gas processing. Such a high capacity inflator-based liquefaction process is considered to be particularly suitable for FLNG applications where the inherent safety and simplicity of the inflator-based liquefaction process are highly valued.

The present invention provides a method for producing liquefied natural gas (LNG). Natural gas streams are provided from the supply of natural gas. The natural gas stream can be compressed to a pressure of at least 2,000 psia in at least two series-arranged compressors to form a compressed natural gas stream. The compressed natural gas stream can form a cooled cooled compressed natural gas stream. A cooled compressed natural gas stream expands within at least one work-producing natural gas expander to a pressure of less than 3,000 psia and no greater than the pressure at which at least two series-arranged compressors compress the natural gas stream to that extent. It is possible to form a chilled natural gas stream. The chilled natural gas stream can then be liquefied.

The present invention also provides an apparatus for liquefaction of natural gas. At least two series-arranged compressors compress the natural gas stream to a pressure greater than 2,000 psia, thereby forming a compressed natural gas stream. The cooling element cools the compressed natural gas stream to form a cooled compressed natural gas stream. At least one work-producing inflator expands the cooled compressed natural gas stream to a pressure less than 3,000 psia and not greater than the pressure at which at least two series-arranged compressors compress the natural gas stream to that extent. Form a chilled natural gas stream. The liquefaction train liquefies a chilled natural gas stream.

The present invention further provides a floating LNG structure. At least two series-arranged compressors compress the natural gas stream to a pressure greater than 2,000 psia, thereby forming a compressed natural gas stream. The cooling element cools the compressed natural gas stream to form a cooled compressed natural gas stream. At least one work-producing inflator expands the cooled compressed natural gas stream to a pressure less than 3,000 psia and not greater than the pressure at which at least two series-arranged compressors compress the natural gas stream to that extent. Form a chilled natural gas stream. The liquefaction train liquefies a chilled natural gas stream.

FIG. 6 is a schematic representation of a high pressure compression and expansion (HPCE) module according to the disclosed aspects. It is a graph which shows the heating and cooling curves for an inflator-based freezing process. It is a schematic diagram which shows the arrangement of the shingled refrigerant (SMR) liquefaction module by a known principle. It is the schematic which shows the arrangement of the SMR liquefaction module by the aspect to be disclosed. It is the schematic of the HPCE module by the aspect to disclose. It is the schematic of the HPCE module and the supply gas inflator-based liquefaction module according to the disclosed aspect. It is a flowchart of the method of liquefying natural gas to form LNG by the aspect disclosed.

Various specific embodiments, embodiments, and versions, including the definitions adopted herein, are described herein below. Those skilled in the art will appreciate that such embodiments, embodiments, and versions are merely exemplary and that the present invention can be practiced using other methods. Any reference to the "invention" may refer to one or more of embodiments defined by the claims, but not necessarily all. The use of headings is for convenience purposes only and does not limit the scope of the invention. For purposes of clarity and simplification, similar reference numbers in some figures represent similar items, stages, or structures and may not be described in detail in all figures.

All numerical values in the detailed description and claims of the present specification are modified by "about" or "approximate" display values to take into account experimental errors and variations expected by those skilled in the art.

As used herein, the term "compressor" means a machine that increases the pressure of a gas by applying work. A "compressor" or "refrigerant compressor" includes any unit, device, or device capable of increasing the pressure of a gas stream. This includes compressors with a single compression step or stage, or compressors with multi-stage compression or stages, or especially multi-stage compressors in a single casing or shell. The compressed evaporated stream can be provided to the compressor at various pressures. Some stages or stages of the cooling process may involve two or three or more compressors in parallel, in series, or both. The present invention is not limited by the type or arrangement or layout of one or more compressors, especially in any refrigerant circuit.

As used herein, "cooling" broadly refers to lowering and / or lowering the temperature and / or internal energy of a substance by any suitable desired or necessary amount. Cooling is at least about 1 ° C, at least about 5 ° C, at least about 10 ° C, at least about 15 ° C, at least about 25 ° C, at least about 35 ° C, or at least about 50 ° C, or at least about 75 ° C, or at least about 85 ° C. , Or at least about 95 ° C, or at least about 100 ° C. Cooling can use any suitable heat sink such as steam generation, hot water heating, cooling water, air, refrigerant, other processing streams (integration), and combinations thereof. One or more sources of cooling can be combined and / or cascaded to reach the desired outlet temperature. The cooling stage can use a cooling unit with any suitable device and / or equipment. Depending on some embodiments, cooling can include indirect heat exchange, along with one or more heat exchangers and the like. Alternatively, cooling can use evaporative (heat of vaporization) cooling and / or direct heat exchange, such as liquid sprayed directly into the processing stream.

As used herein, the term "expansion device" is used to reduce the pressure of a fluid in a line (eg, a liquid stream, a vapor stream, or a polyphase stream containing both liquid and vapor). Refers to one or more suitable devices. Unless a particular type of inflatable device is specifically defined, the inflatable device may be (1) at least partially by isentropic means, or (2) at least partially by isentropic means. Yes, or it may be a combination of both (3) isentropic means and isentropic means. Suitable devices for enthalpy expansion of natural gas are known in the art and are generally not limited to, for example, valves, control valves, "Joule-Thomson (JT)" valves, or Venturi. Includes aperture devices that activate manually or automatically, such as devices. Suitable devices for isentropic expansion of natural gas are known in the art and generally include equipment such as expanders or turbo expanders that extract or derive work from such expansions. Suitable devices for isentropic expansion of liquid streams are known in the art and are generally of inflators, hydraulic inflators, liquid turbines, or turbo inflators that extract or derive work from such expansions. Including equipment such as. An example of a combination of both isentropic and isoenthalpy means could be a parallel "Joule-Thomson" valve and turbo expander, which uses either the JT valve and the turbo expander alone. Provide the ability to use either or both at the same time. Equal enthalpy or isotropic expansion can be performed in a total liquid phase, a total vapor phase, or a mixed phase, from a vapor stream or liquid stream to a polyphase stream (a stream having both a vapor phase and a liquid phase), or a stream thereof. It can be done so as to facilitate the phase change to a single phase stream different from the initial phase. In the description of the drawings herein, references to more than one inflatable device in every drawing do not necessarily mean that each inflatable device is of the same type or size.

The term "gas" is used synonymously with "vapor" and is defined as a substance or mixture of substances in a gaseous state that distinguishes it from a liquid or solid state. Similarly, the term "liquid means a substance or mixture of substances in a liquid state that distinguishes it from a gaseous or solid state.

"Heat exchanger" means any device in the broad sense that can transfer thermal or cold energy from one medium to another, such as between at least two different fluids. Heat exchangers include "direct heat exchange" and "indirect heat exchange". Therefore, the heat exchangers are parallel or backflow heat exchangers, indirect heat exchangers (eg, spiral wound heat exchangers, or plate fin heat exchangers such as braided aluminum plate fin types), direct contact heat exchangers, With any suitable design such as shell-and-tube heat exchangers, spirals, hairpins, cores, core-and-kettles, printed circuits, double pipes, or any other type of known heat exchanger. can do. A "heat exchanger" also allows the passage of one or more streams through it, affecting the direct or indirect heat exchanger between one or more lines of refrigerant and one or more supply streams. Refers to any column, tower, unit, or other arrangement that has come to give.

As used herein, the term "indirect heat exchange" means the introduction of two fluids into a heat exchange relationship without any physical contact, or the mixing of fluids with each other. Core-in-kettle heat exchangers and brazed aluminum plate fin heat exchangers are examples of equipment that facilitates indirect heat exchange.

As used herein, the term "natural gas" refers to a multi-component gas obtained from a crude oil well (accompanying gas) or from an underground gas-bearing formation (non-accompanying gas). The composition and pressure of natural gas can vary significantly. A typical natural gas stream contains methane (C ₁ ) as a significant component. Natural gas streams may also contain ethane (C ₂ ), higher molecular weight hydrocarbons, and one or more acid gases. Natural gas may also contain small amounts of contaminants such as water, nitrogen, iron sulfide, wax, and crude oil.

Certain embodiments and features have been described using a set of numerical upper bounds and a set of numerical lower bounds. It must be acknowledged that the range from any lower limit to any upper limit is considered unless otherwise instructed. All numbers are "approx." Or "approximate" indications, taking into account experimental errors and variations expected by those skilled in the art.

All patents, test procedures, and other documents cited in this application are complete by citation to all administrative jurisdictions where such disclosure is not contrary to this application and where such incorporation is permitted. It is built into.

Aspects disclosed herein describe a process for precooling natural gas relative to the liquefaction process of LNG production by adding high pressure compression and high pressure expansion steps to the supply gas. More specifically, the present invention describes a step in which the pretreated natural gas is compressed to a pressure greater than 2,000 psia (13,790 kPA) or more preferably greater than 3,000 psia (20,680 kPA). .. The hot compressed gas is cooled by exchanging heat with the environment to form a compressed pretreatment gas. The compressed pretreatment gas forms a cold pretreatment gas that is nearly issentropically expanded to a pressure of less than 3,000 psia (20,680 kPA) or more preferably less than 2,000 psia (13,790 kPA). Here, the pressure of the cold pretreatment gas is smaller than the pressure of the compression pretreatment gas. The chilled pretreatment gas can be directed to one or more SMR liquefaction trains, or the chilled pretreatment gas is one or more expander-based liquefaction trains where the gas is further cooled to form an LNG. Can be turned to.

FIG. 1 is a diagram illustrating an embodiment of a precooling step. The precooling step is referred to herein as high pressure compression and expansion (HPCE) step 100. The HPCE step 100 may include a pretreated natural gas stream 104 and a first compressor 102 forming an intermediate pressure gas stream 106. The intermediate pressure gas stream 106 can flow through a first heat exchanger 108 that is cooled by the intermediate pressure gas stream 106 indirectly exchanging heat with the environment to form a cooling intermediate pressure gas stream 110. .. The first heat exchanger 108 can be an air-cooled heat exchanger or a water-cooled heat exchanger. The cooled intermediate pressure gas stream 110 can then be compressed in the second compressor 112 to form the high pressure gas stream 114. The pressure of the high pressure gas stream 114 can be greater than 2,000 psia (13,790 kPA), or more preferably greater than 3,000 psia (20,680 kPA). The high pressure gas stream 114 can flow through a second heat exchanger 116 that is cooled by the high pressure gas stream 114 indirectly exchanging heat with the environment to form a cooling intermediate pressure gas stream 118. The second heat exchanger 116 can be an air-cooled heat exchanger or a water-cooled heat exchanger. The cooling high pressure gas stream 118 can then form a pretreated gas stream 122 that has been expanded and cooled in the inflator 120. The pressure of the chilled pretreatment gas stream 122 can be less than 3,000 psia (20,680 kPA), or more preferably less than 2,000 psia (13,790 kPA), and the pressure of the chilled pretreatment gas stream 122 is , Less than the pressure of the cooling high pressure gas stream 118. In a preferred embodiment, the second compressor 112 can be driven solely by shaft power generated by the inflator 120, as shown by the dashed line 124.

In aspects, the SMR liquefaction step can be enhanced by the addition of an HPCE step upstream of the SMR liquefaction step. More specifically, in this embodiment, the pretreated natural gas can be compressed to a pressure greater than 2,000 psia (13,790 kPA), or more preferably greater than 3,000 psia (20,680 kPA). .. The high temperature compressed gas is then cooled by indirectly exchanging heat with the environment to form a compression pretreatment gas. Next, the compressed pretreatment gas is a pretreatment gas that has been expanded and cooled to a pressure of less than 3,000 psia (20,680 kPA), or more preferably a pressure of less than 2,000 psia (13,790 kPA). The pressure of the chilled pretreatment gas is lower than the pressure of the compressed pretreatment gas. The chilled pretreatment gas is then directed to a plurality of SMR liquefaction trains in which the chilled pretreatment gas is further cooled to form an LNG.

The combination of SMR train and HPCE has several advantages over the conventional SMR process in which the pretreated natural gas is delivered directly to the SMR liquefaction train. For example, precooling of natural gas using the HPCE process allows an increase in LNG production in the SMR train for given horsepower in the SMR train. As described in connection with FIGS. 3 and 4, each SMR train powered by a gas turbine having an output of about 50 megawatts (MW) is one of five trains each producing LNG at 1.5 MTA. The capacity increase of 0.9 MTA can be reduced to four trains, each with. For this given example, the HPCE module substantially replaces one of the SMR modules. Replacing the SMR module with an HPCE module is advantageous because the HPCE module is expected to be smaller, lighter, and significantly cheaper than the SMR module. Like the SMR module, the HPCE module can have a gas turbine of comparable size to provide compressed power, which will also have an equal amount of air or water cooler. However, unlike the SMR module, the HPCE module does not have an expensive main low temperature heat exchanger. Containers and pipes associated with refrigerant flow within the SMR module are excluded in the HPCE module. Moreover, there are no expensive cold pipes in the HPCE module and all fluid streams remain single phase in the HPCE module.

Another advantage is that the number of SMR trains is reduced by one, which reduces the storage required for the refrigerant. Similarly, most of the warm temperature at which the gas is cooled is generated in the HPCE module, so that the heavy hydrocarbon component of the mixed refrigerant can be reduced. For example, the propane component of the mixed refrigerant can be eliminated without any significant reduction in the efficiency of the SMR process.

Another advantage is that for the SMR process, which accepts the cold pretreatment gas from the HPCE process, the volumetric flow rate of the evaporative refrigerant in the SMR process is more than 25% smaller than that of the conventional SMR process, which accepts the warm pretreatment gas. It means that you can do it. The lower volume flow of the refrigerant can reduce the size of the main cold heat exchanger and the size of the low pressure mixed refrigerant compressor. The lower volumetric flow rate of the refrigerant is due to its higher vapor pressure compared to that of the conventional SMR process.

The known propane pre-cooling mixed freezing and double mixed freezing (DMR) steps can be considered as versions of the SMR step in combination with the pre-cooling and freezing circuit, but are significant between such steps and the embodiments disclosed in the present invention. There is a big difference. For example, a known process uses a cascade propane refrigeration circuit or a warm-end mixed refrigerant to precool the gas. Both of these known steps have the advantage of providing 5% to 15% higher efficiency than the SMR step. Moreover, the capacity of single liquefaction trains using those known steps can be significantly greater than that of single SMR trains. However, the precooling and refrigerating circuits of those techniques introduce additional refrigerants and significant amounts of extra equipment, thus at the cost of additional complexity for the liquefaction process. For example, the drawbacks of higher complexity and weight of DMR may outweigh its advantages of high efficiency and performance when deciding on either a DMR process or an SMR process for FLNG applications. Known processes consider adding a precooling process upstream of the SMR process when driven primarily by the need for higher thermal efficiency and higher LNG production capacity for a single train. The HPCE process in combination with the SMR process has not been previously achieved as it does not provide higher thermal efficiency than the refrigerant-based precooling process provides. As mentioned above, the thermal efficiency of the HPCE process with SMR is almost the same as that of the stand-alone SMR process. The disclosed aspects describe the precooling process, which seeks to reduce the weight and complexity of the liquefaction process rather than increasing thermal efficiency, which was the largest driver for the addition of precooling processes for onshore LNG applications in the past. It is considered new, at least in part. For newer applications of FLNG, the footprint, weight, and complexity of the liquefaction process are expected to be drivers that outweigh the project costs. Therefore, the disclosed aspects are of particular value.

In aspects, the inflator-based liquefaction step can be enhanced by the addition of an HPCE step upstream of the inflator-based step. More specifically, in this embodiment, the pretreated natural gas stream can be compressed to a pressure greater than 2,000 psia (13,790 kPA), or more preferably greater than 3,000 psia (20,680 kPA). it can. The high temperature compressed gas can then be cooled by exchanging heat with the environment to form a compressed pretreatment gas. The compressed pretreatment gas forms a cold pretreatment gas that is nearly isentropically expanded to a pressure of less than 3,000 psia (20,680 kPA), or more preferably less than 2,000 psia (13,790 kPA). The pressure of the cold pretreatment gas can be lower than the pressure of the compressed pretreatment gas. The cooled pretreatment gas is directed to an expander-based process in which the gas is further cooled to form LNG. In a preferred embodiment, the chilled pretreatment gas can be directed to a feed gas expander-based process.

FIG. 2 shows a typical temperature cooling curve 200 for an inflator-based liquefaction process. The hotter curve 202 is the temperature curve of the natural gas stream. The cooler curve 204 is a composite temperature curve of a cold cooling stream and a warm cooling stream. As shown, the cooling curve is marked by three temperature pinch points 206, 208, and 210. Each pinch point is a location in the heat exchanger where the combined heat capacity of the cooling stream is smaller than that of the natural gas stream. This imbalance of heat capacity between streams results in a reduction in temperature difference between cooling streams against a minimally permissible temperature difference that provides effective heat transfer coefficient. The lowest temperature pinch point 206 occurs where the colder of the two cooling streams, typically the colder cooling stream, enters the heat exchanger. An intermediate temperature pinch point 208 occurs where the second cooling stream, typically the warm cooling stream, enters the heat exchanger. A hot temperature pinch point 210 occurs where the cold and warm cooling streams exit the heat exchanger. The warm temperature pinch point 210 needs to have a high mass flow rate relative to the warmer cooling stream, which substantially increases the power requirements of the inflator-based process.

One proposed method for eliminating the hot temperature pinch point 210 is to precool the supply gas with an external refrigeration system such as a propane cooling system or a carbon dioxide cooling system. For example, US Pat. No. 7,386,996 eliminates warm temperature pinch points by using a precooling and freezing process that includes a cascaded carbon dioxide refrigeration circuit. This external pre-cooling and refrigeration system has the drawback of significantly increasing the complexity of the liquefaction process as it introduces an additional refrigerant system with all relevant equipment. Aspects disclosed herein are to precool the supply gas stream by compressing the supply gas to a pressure greater than 2,000 psia (12,790 kPA) and to cool the compressed supply gas stream to 3,000 psia (20). By expanding the compressed gas stream to a pressure of less than 690 kPA), the effect of the warm temperature pinch point 210 is mitigated, where the expansion pressure of the supply gas stream is less than the compression pressure of the supply gas stream. This step of cooling the feed gas stream results in a significant reduction in the required mass flow rate of the cooling stream in the inflator-based process. It also improves the thermodynamic efficiency of the inflator-based process without significantly increasing the total number of equipment and without the addition of external refrigerants.

In a preferred embodiment, the inflator-based process can be a feed gas inflator-based process. The supply gas inflator-based process can be an open loop supply gas process in which the recirculation loop includes a warm end inflator loop and a cold end inflator loop. The warm-end inflator can release the first cooling stream and the cold-end inflator can release the second cooling stream. The temperature of the first cooling stream is higher than the temperature of the second cooling stream. In some embodiments, the pressure in the first cooling stream is higher than the pressure in the second cooling stream. In another aspect, the cold-end expander releases a two-phase stream separated into a second cooling stream and a second pressurized LNG stream. Specifically, the generated natural gas stream can be processed to remove impurities such as water, heavy hydrocarbons, and acid gas, if present, to produce natural gas suitable for liquefaction. The treated natural gas can be directed to an HPCE process in which it is compressed to a pressure greater than 2,000 psia (12,790 kPA), or more preferably greater than 3,000 psia (20,680 kPA). The hot compressed gas can then be cooled by exchanging heat with the environment to form compressed natural gas. The compressed natural gas is expanded substantially equienotropically to a pressure of less than 3,000 psia (20,680 kPA), or more preferably less than 2,000 psia (12,790 kPA) to form refrigerated natural gas. Here, the pressure of the refrigerated natural gas is lower than the pressure of the compressed natural gas. The refrigerated natural gas can be completely liquefied by indirect heat exchange with the first cooling stream and the second cooling stream to produce a first pressurized LNG stream. The first pressurized LNG stream can be mixed with the second pressurized LNG stream to form a pressurized LNG stream. The pressurized LNG stream can be directed to at least one two-phase separation stage where the pressure of the pressurized LNG stream is reduced and the resulting two-phase stream is separated into a flash gas stream and an LNG product stream. The flash gas stream exchanges heat with the pressurized LNG stream and the refrigerated natural gas stream before being compressed with respect to the fuel gas and / or compressed to mix with the second cooling stream of the recirculation. be able to.

The combination of the supply gas inflator-based process and the HPCE process has several advantages over the conventional supply gas inflator-based process. Including the HPCE process with it can increase the efficiency of the supply gas expander-based process by 20-25%. Therefore, the supply gas expander process of the present invention has an efficiency approaching the efficiency of the SMR process while still providing the advantages of no external refrigerant, ease of operation, and reduction of the total number of devices. In addition, the refrigerant flow rate and the size of the recirculation compressor are expected to be significantly lower for the expander-based process combined with the HPCE process. For this reason, the production capacity of a single liquefaction train according to the disclosed embodiments can exceed the production capacity of a similarly sized conventional inflator-based liquefaction process by more than 50%.

FIG. 3 is a diagram illustrating the arrangement of the SMR liquefaction module with respect to the FLNG 300. The pretreated or otherwise suitable natural gas 302 can be evenly distributed between the five identical or nearly identical SMR liquefaction modules or trains 304, 306, 308, 310, 312. As an example, each SMR liquefaction module can receive approximately 50 MW of compression power from either a gas turbine or an electric motor (not shown) to drive the compressor of the SMR liquefaction module. Each SMR liquefaction module can produce about 1.5 MTA of LNG for a total stream daily production of about 7.5 MTA of LNG for FLNG applications.

FIG. 4 is a diagram illustrating the arrangement of the SMR liquefaction module or the HPCE module 404 having trains 406, 408, 410, 412 on the FLNG 400 according to the disclosed embodiment. The pretreated or otherwise suitable natural gas 402 can be directed to the HPCE module 404 to produce a cold pretreated gas stream 405. The HPCE module 404 can receive, for example, about 50 MW of compressed power from either a gas turbine or an electric motor (not shown) to drive one or more compressors in the HPCE module 404. The cold pretreatment gas can be evenly distributed among the four identical or nearly identical SMR liquefaction modules 406, 408, 410, 412. Each SMR liquefaction module can receive about 50 MW of compression power from either a gas turbine or an electric motor (not shown) to drive the compressor of each SMR liquefaction module. Each SMR liquefaction module is capable of producing about 1.9 MTA of LNG for a total stream daily production of about 7.6 MTA of LNG for FLNG applications.

FIG. 5 is a diagram illustrating an embodiment of the HPCE module 500 referred to in FIG. The natural gas stream 502, pretreated to remove impurities or otherwise suitable for liquefaction, is fed into the first compressor 504 to form the first intermediate pressure gas stream 506. The first intermediate pressure gas stream 506 forms a first intermediate pressure gas stream 510 that is cooled and cooled by the first intermediate pressure gas stream 506 indirectly exchanging heat with the environment. It can flow through the heat exchanger 508. The first heat exchanger 508 can be an air-cooled heat exchanger or a water-cooled heat exchanger. The cooled first intermediate pressure gas stream 510 can then be compressed in the second compressor 512 to form a second intermediate pressure gas stream 514. The second intermediate pressure gas stream 514 forms a second intermediate pressure gas stream 518 that is cooled and cooled by the second intermediate pressure gas stream 514 exchanging heat indirectly with the environment. It can flow through the heat exchanger 516. The second heat exchanger 516 can be an air-cooled heat exchanger or a water-cooled heat exchanger. The cooled second intermediate pressure gas stream 518 can then be compressed in the third compressor 520 to form the high pressure gas stream 522. The pressure of the high pressure gas stream 522 can be greater than 2,000 psia (13,790 kPA), or more preferably greater than 3,000 psia (20,680 kPA). The high pressure gas stream 522 can flow through a third heat exchanger 524 that forms a cooled and cooled high pressure gas stream 526 as the high pressure gas stream 522 indirectly exchanges heat with the environment. The third heat exchanger 524 can be an air-cooled heat exchanger or a water-cooled heat exchanger. The cooled high pressure gas stream 526 can then form a pretreated gas stream 530 that has been expanded and cooled in the compressor 528. The pressure of the cold pretreatment gas stream 530 can be less than 3,000 psia (20,680 kPA), or more preferably less than 2,000 psia (13,790 kPA), and the pressure of the cold pretreatment gas stream 530 is , Can be less than the pressure of the cooled high pressure gas stream 526. In some embodiments, the third compressor 520 can be driven solely by the shaft power generated by the inflator 528, as indicated by wire 532.

FIG. 6 is a diagram illustrating an HPCE step 601 combined with a supply gas expander-based LNG liquefaction step 600. Natural gas can be treated and, if present, impurities such as water, heavy hydrocarbons, and acid gases can be removed to produce a treated natural gas stream 602 suitable for liquefaction. The treated natural gas stream 602 can be mixed with the recirculated refrigerant gas stream 604 to form a combined stream 606. The combination stream 606 can be directed to the HPCE step 601 in which the combination stream 606 is compressed in the first compressor 608 to form an intermediate pressure gas stream 610. The intermediate pressure gas stream 610 flows through a first heat exchanger 612 that forms a cooled and cooled intermediate pressure gas stream 614 through which the intermediate pressure gas stream 610 exchanges heat indirectly with the environment. Can be done. The first heat exchanger 612 can be an air-cooled heat exchanger or a water-cooled heat exchanger. The cooled intermediate pressure gas stream 614 can then be compressed in the second compressor 616 to form the high pressure gas stream 618. The pressure of the high pressure gas stream 618 can be greater than 2,000 psia (13,790 kPA), or more preferably greater than 3,000 psia (20,680 kPA). The high pressure gas stream 618 can flow through a second heat exchanger 620 that forms a cooled and cooled high pressure gas stream 618 by the high pressure gas stream 618 indirectly exchanging heat with the environment. The second heat exchanger 620 can be an air-cooled heat exchanger or a water-cooled heat exchanger. The cooled high pressure gas stream 622 can then form a pretreated gas stream 626 that has been expanded and cooled in the HPCE inflator 624. The pressure of the cold pretreatment gas stream 626 is less than 3,000 psia (20,680 kPA), or more preferably less than 2,000 psia (13,790 kPA), where the pressure of the cold pretreatment gas stream 626 is , Less than the pressure of the cooled high pressure gas stream 622. In some embodiments, the second compressor 616 can be driven solely by the shaft power generated by the inflator 624, as represented by the dashed line 628.

As shown in FIG. 6, the chilled pretreatment gas stream 626 leaves HPCE step 601 and is directed to feed gas expander-based step 600. The chilled pretreatment gas stream 626 can be separated into a second chilled pretreatment gas stream 630, a first refrigerant stream 632, and a second refrigerant stream 634. The first refrigerant stream 632 can be expanded in the first inflator 636 to produce the first cooling stream 638. The first cooling stream 638 enters at least one cold heat exchanger 640, which cools this stream by exchanging heat with the second cold pretreatment gas stream 630 and the second refrigerant stream 634. The first cooling stream 638 exits at least one cold heat exchanger 640 as the first warm stream 642. The second refrigerant stream 634 can be cooled in at least one cold heat exchanger 640 and then expanded in the second expander 644 to produce a two-phase stream 646. The pressure of the two-phase stream 646 can be the same as or lower than the pressure of the first cooling stream 638. The two-phase stream 646 can be separated into its vapor component and its liquid component in the first two-phase separator 648 to form the second cooling stream 650 and the second pressurized LNG stream 652. The temperature of the first cooling stream 638 is higher than the temperature of the second cooling stream 650. The second cooling stream 650 enters at least one cold heat exchanger 640 in which it exchanges heat with the second cold pretreatment gas stream 630 and the second refrigerant stream 634 to cool this stream. The second cooling stream 650 exits at least one heat exchanger 640 as a second warm stream 642. The second cold pretreated natural gas stream 630 exchanges heat with the first cooling stream 638 and the second cooling stream 650 to produce a first pressurized LNG stream 656. The first pressurized LNG stream 656 can be depressurized in the hydraulic turbine 658 after exiting at least one heat exchanger 640. The first pressurized LNG stream 656 can be mixed with the second pressurized LNG stream 652 to form a combined pressurized LNG stream 660. The combined pressurized LNG stream 660 can be directed to a second two-phase separator 662 where the pressure of the combined pressurized LNG stream 660 is reduced, and the resulting two-phase stream is the end flush gas stream 664 and the product LNG stream 667. Is separated into. The end flush gas stream 664 can exchange heat with the first pressurized LNG stream 656 in the end flush gas heat exchanger 668 before directing the first pressurized LNG stream 656 to the hydraulic turbine 658. In addition to this, the end-flash gas stream 664 enters at least one cold heat exchanger 640 and exchanges heat with the second cold pretreatment gas stream 630 and the second refrigerant stream 634 to cool this stream. can do. The end flush gas stream 664 exits at least one heat exchanger 640 as a third warm stream 670. The third warm stream 670 can be compressed in the first recycled gas compressor 672 and exchanges heat with the environment in the first recirculating heat exchanger 674 to exchange heat with the first recycled gas stream. 676 can be formed. The first recycled gas stream 676 can be combined with the second warm stream 654 and at the same time be compressed in the second recycled gas compressor 678, the second recirculating heat exchanger 680. Within, heat can be exchanged with the environment to form a second recycled gas stream 682. The second recycled gas stream 682 can be combined with the first warm stream 642 and at the same time can be compressed in the third and fourth recycled gas compressors 684, 686 and the third recycled gas stream 682. The recirculating refrigerant gas stream 604 can be formed by exchanging heat with the environment in the circulating heat exchanger 688. The third recycled gas compressor 684 can be driven exclusively by the shaft power generated by the first inflator 636, as indicated by the dashed line 690. The fourth recycled gas compressor 686 can be driven exclusively by the shaft power generated by the second expander 644, as shown by the dashed line 692.

FIG. 7 shows a method 700 for producing LNG according to the disclosed embodiment. At block 702, the natural gas stream can be provided from the supply of natural gas. At block 704, the natural gas stream can be compressed to a pressure of at least 2,000 psia in at least two series-arranged compressors to form a compressed natural gas stream. At block 706, the compressed natural gas stream can be cooled to form a cooled compressed natural gas stream. At block 708, the cooled compressed natural gas stream is at least one work-generated natural gas expansion to a pressure less than 3,000 psia and no greater than the pressure at which at least two series-arranged compressors compress the natural gas stream to that extent. It is inflated in the vessel, which allows it to form a chilled natural gas stream. At block 710, a cold natural gas stream can be liquefied.

The disclosed embodiments may include any combination of methods and systems shown in the numbered paragraphs below. This should not be considered a complete list of all possible embodiments, as any number of variants can be considered from the above description.

1. 1. The step of providing the natural gas stream from the supply of natural gas and the step of compressing the natural gas stream to a pressure of at least 2,000 psia in at least two series-arranged compressors to form a compressed natural gas stream. The stage of cooling the compressed natural gas stream to form a cooled compressed natural gas stream, and at least to a pressure less than 3,000 psia and no greater than the pressure at which at least two series-arranged compressors compress the natural gas stream to that extent. Liquefied natural gas (LNG) that includes the steps of expanding a cooled compressed natural gas stream in a work-producing natural gas expander, thereby forming a chilled natural gas stream, and liquefying the chilled natural gas stream. How to produce.

2. 2. The step of liquefying a chilled natural gas stream is the method of paragraph 1 performed in one or more shingled refrigerant (SMR) liquefaction trains.

3. 3. The step of liquefying a chilled natural gas stream is the method of paragraph 1 performed in one or more inflator-based liquefaction modules.

4. The inflator-based liquefaction module is a nitrogen gas inflator-based liquefaction module according to the method of item 3.

5. The inflator-based liquefaction module is a supply gas inflator-based liquefaction module according to the method of item 3.

6. The method of item 5 where the supply gas inflator-based liquefaction module is an open-loop supply gas inflator-based liquefaction module.

7. The recirculating refrigerant stream in an open-loop feed gas expander-based process is a six-item method that is combined with a natural gas stream before the compression step.

8. The chilled natural gas stream is a first chilled natural gas stream, the method of which is a first chilled natural gas stream to a second chilled natural gas stream, a first refrigerant stream, and a second refrigerant. Item 7 method further including the step of separating into streams.

9. A first cooling stream having a first temperature is discharged from a warm-end inflator forming part of a gas inflator-based liquefaction module, and a second cooling stream having a second temperature is supplied. Item 7. The method of item 7, wherein the first temperature is higher than the second temperature, further including the step of discharging from the cold end expander forming a part of the inflator-based liquefaction module.

10. A step of expanding the first refrigerant stream in the warm end expander to generate the first cooling stream and a step of expanding the second refrigerant stream in the cold end expander to generate the second cooling stream. The method of item 9 further including.

11. A supply gas inflator with a step of discharging a first cooling stream having a first temperature from a warm-end inflator forming part of a supply gas inflator-based liquefaction module and a two-phase stream having a second temperature. Item 7. The method of item 7, wherein the first temperature is higher than the second temperature, further including the step of discharging from the cold end expander forming a part of the liquefaction module of the base.

12. A step of expanding the first refrigerant stream in the warm end expander to generate a first cooling stream and a step of expanding the second refrigerant stream in the cold end expander to generate a two-phase stream. Item 11 method including further.

13. The method of paragraph 11 further comprising the step of separating the two-phase stream into a second cooling stream and a first pressurized LNG stream.

14. The method according to any one of 9 to 13, wherein the pressure of the first cooling stream is the same as or similar to the pressure of the second cooling stream.

15. The method according to any one of 9 to 13, wherein the pressure of the first cooling stream is higher than the pressure of the second cooling stream.

16. The liquefaction step includes a step of cooling the second cold natural gas stream by exchanging heat with the first cooling stream and the second cooling stream to form a second pressurized LNG stream 9-13. Any method of the section.

17. Item 16. The method of item 16, wherein the second pressurized LNG stream is mixed with the first pressurized LNG stream before expanding the second pressurized LNG stream.

18. The step of reducing the pressure of the second pressurized LNG stream so that the second pressurized LNG stream receives at least one step of pressure reduction, and the end flush gas stream and the LNG stream of the depressurized second pressurized LNG stream. The method of item 16 further comprising the step of separating into.

19. Item 18. The method of paragraph 18, further comprising the step of cooling a second pressurized LNG stream and a second cold natural gas stream using an end flush gas stream.

20. The step of compressing the end flush gas stream after cooling the second pressurized LNG stream and the second cold natural gas stream using the end flush gas stream, and one or more recirculated refrigerant streams and compression ends. 19. The method of paragraph 19, further comprising the step of mixing the flash gas stream.

21. A step of compressing the endflash gas stream after cooling the second pressurized LNG stream and a second cold natural gas stream using the endflash gas stream, and a step of using the compressed endflash gas stream as fuel. The method of paragraph 19 further comprising.

22. The method of any of paragraphs 1-21, wherein the at least two compressors compress the natural gas stream to a pressure greater than 3,000 psia.

23. The method of any of paragraphs 1 to 22, wherein the natural gas inflator is a work-generated inflator that expands a cooled compressed natural gas stream to a pressure of less than 2,000 psia.

24. The method of any of items 1 to 23, wherein the natural gas expander is mechanically coupled to at least one compressor.

25. The method of any of items 1 to 24, wherein the step of cooling the compressed natural gas stream includes a step of cooling the compressed natural gas stream in at least one heat exchanger that exchanges heat with the environment.

26. One of at least two series-arranged compressors is any of the methods 1-25 driven by a natural gas inflator.

27. At least two series-arranged compressors include three series-arranged compressors, one of the three series-arranged compressors being driven by a natural gas inflator 1- Any method of paragraph 26.

28. The method according to any one of Items 1 to 27, further comprising a step of compressing, cooling, expanding, and liquefying on the upper deck of the floating LNG structure.

29. 28. The method of compressing, cooling, and expanding is performed within a single module on the upper deck of a floating LNG structure.

Compress the natural gas stream to a pressure greater than 30.2,000 psia, thereby cooling at least two series-arranged compressors configured to form the compressed natural gas stream and the compressed natural gas stream. Up to a pressure not greater than the pressure at which a cooling element configured to form a cooled compressed natural gas stream, and less than 3,000 psia and at least two series-arranged compressors compress the natural gas stream to that extent. A liquefaction train configured to liquefy a cooled natural gas stream with at least one work-generating inflator configured to expand the cooled compressed natural gas stream thereby forming a cooled natural gas stream. Equipment for liquefaction of natural gas, including.

31. The liquefaction train is a thirty-item device that includes one of a single mixed refrigerant (SMR) liquefaction module and an expander-based liquefaction module.

32. The inflator-based liquefaction module is one of a nitrogen gas inflator-based liquefaction module and a supply gas inflator-based liquefaction module, according to item 31.

33. The supply gas expander-based liquefaction module is the device of item 32, which is an open-loop supply gas expander-based liquefaction module.

34. Cold natural, further containing a recirculated refrigerant stream in an open-loop feed gas expander-based process combined with the natural gas stream before the natural gas stream is compressed by two or more series-arranged compressors. Item 33, wherein the gas stream is a first cold natural gas stream separated into a second cold natural gas stream, a first refrigerant stream, and a second refrigerant stream.

35. The supply gas inflator-based liquefaction module comprises a warm-end inflator configured to expand a first refrigerant stream to form a first cooling stream having a first temperature discharged from it. The first includes a second cooling stream having a second temperature and a cold-end expander configured to form one of a two-phase stream that expands and discharges a second refrigerant stream. The temperature of the device of item 34, which is higher than the second temperature.

36.2 The apparatus of 35, further comprising the step of separating the two-phase stream into a second cooling stream and a first pressurized LNG stream.

37. 35. 36. The device in which the pressure of the first cooling stream is the same as or similar to the pressure of the second cooling stream, or higher than the pressure of the second cooling stream.

38. A heat exchanger configured to cool a second cold natural gas stream to form a second pressurized LNG stream by exchanging heat with a first cooling stream and a second cooling stream. The device according to any one of 35 to 37, which further includes.

39. At least two compressors are devices of any of 30-38 that compress the natural gas stream to a pressure greater than 3,000 psia.

40. The device according to any one of 30 to 39, wherein the natural gas inflator is a work-generated inflator configured to inflate a cooled compressed natural gas stream to a pressure of less than 2,000 psia.

41. A natural gas expander is any device of any of 30-40 that is mechanically coupled to at least one compressor.

42. The device of any of 30-41, wherein the cooling element comprises a heat exchanger configured to cool the compressed natural gas stream by exchanging heat with the environment.

43. One of at least two series-arranged compressors is any device of any of items 30-42 driven by a natural gas inflator.

44. At least two series-arranged compressors include three series-arranged compressors, one of the three series-arranged compressors being driven by a natural gas inflator 30- The device of any of item 43.

45. The apparatus of any of items 30-44, wherein the at least two series-arranged compressors, cooling elements, at least one work-generating inflator, and liquefaction train are arranged on a floating LNG structure.

46. A 45-item device in which at least two series-arranged compressors, cooling elements, and at least one work-generating inflator are arranged in a single module on the upper deck of a floating LNG structure.

Cool the compressed natural gas stream with at least two series-arranged compressors configured to compress the natural gas stream to a pressure greater than 47.2,000 psia, thereby forming a compressed natural gas stream. Pressure not greater than the pressure with which the cooling elements configured to form a cooled compressed natural gas stream thereby compressing the natural gas stream to less than 3,000 psia and at least two series-arranged compressors. With at least one work-generating inflator configured to expand the cooled compressed natural gas stream up to, thereby forming a cooled natural gas stream, and a liquefaction train configured to liquefy the cooled natural gas stream. Floating LNG structure containing.

The above relates to aspects of the disclosure of the present invention, but other and yet other aspects of the disclosure can be devised without departing from its basic scope, the scope of which is the following claims. Determined by the range of.

Claims (21)

A method of producing liquefied natural gas (LNG)
The stage of providing a natural gas stream from the supply of natural gas,
A step of compressing the natural gas stream to a first pressure of at least 2,000 psia to form a compressed natural gas stream in at least two compressors arranged in series.
The stage of cooling the compressed natural gas stream to form a cooled compressed natural gas stream , and
At least the cooled compressed natural gas stream is compressed to a second pressure of less than 3,000 psia and not greater than the first pressure at which the at least two series-arranged compressors compress the natural gas stream. The stage of inflating in one work-producing natural gas inflator, thereby forming a first cold natural gas stream,
A step of separating the first cold natural gas stream into a second cold natural gas stream, a first refrigerant stream, and a second refrigerant stream.
A step of expanding the first refrigerant stream to generate a first cooling stream in a warm-end expander that forms part of an open-loop supply gas expander-based liquefaction module.
A step of expanding the second refrigerant stream in a cold-end inflator forming part of the open-loop supply gas expander-based liquefaction module to generate a second cooling stream.
A step of releasing the first cooling stream having a first temperature from the warm end expander,
The second cooling stream having a second temperature comprising the steps of releasing from the cold end expander, the first temperature, a higher stage than the second temperature,
In the open-loop feed gas expander based liquefaction module, it comprises the steps of liquefying the second cold natural gas stream by heat exchange with the first cooling stream and the second cooling stream,
The recirculated refrigerant stream , including the first cooling stream and the second cooling stream after heat exchange, is combined with the natural gas stream prior to the compression step.
A method characterized by that. A method of producing liquefied natural gas (LNG)
The stage of providing a natural gas stream from the supply of natural gas,
A step of compressing the natural gas stream to a first pressure of at least 2,000 psia to form a compressed natural gas stream in at least two compressors arranged in series.
The stage of cooling the compressed natural gas stream to form a cooled compressed natural gas stream , and
At least the cooled compressed natural gas stream is compressed to a second pressure of less than 3,000 psia and not greater than the first pressure at which the at least two series-arranged compressors compress the natural gas stream. The stage of inflating in one work-producing natural gas inflator, thereby forming a first cold natural gas stream,
A step of separating the first cold natural gas stream into a second cold natural gas stream, a first refrigerant stream, and a second refrigerant stream.
A step of expanding the first refrigerant stream to generate a first cooling stream in a warm-end expander that forms part of an open-loop supply gas expander-based liquefaction module.
A step of expanding the second refrigerant stream in the cold-end expander forming a part of the open-loop supply gas expander-based liquefaction module to generate a two-phase stream.
A step of releasing the first cooling stream having a first temperature from the warm end expander,
A step of separating the two-phase stream into a second cooling stream and a first pressurized LNG stream, and
The second cooling stream having a second temperature comprising the steps of releasing from the cold end expander, the first temperature, a higher stage than the second temperature,
In the open-loop feed gas expander based liquefaction module, it comprises the steps of liquefying the second cold natural gas stream by heat exchange with the first cooling stream and the second cooling stream,
The recirculated refrigerant stream, including the first cooling stream and the second cooling stream after heat exchange, is combined with the natural gas stream prior to the compression step.
A method characterized by that. The pressure of the first cooling stream
Same or similar to or similar to the pressure of the second cooling stream, or higher than the pressure of the second cooling stream.
One of them,
The method according to claim 1 or 2 . The liquefaction step cools the second cold natural gas stream by exchanging heat with the first cooling stream and the second cooling stream to form a second pressurized LNG stream. Including stages,
The method according to claim 2 . The second pressurized LNG stream is mixed with the first pressurized LNG stream before expanding the second pressurized LNG stream.
The method according to claim 4 . A step of reducing the pressure of the second pressurized LNG stream so that the second pressurized LNG stream receives a pressure drop of at least one stage.
A step of separating the decompressed second pressurized LNG stream into an end flush gas stream and an LNG stream, and
A step of cooling the second pressurized LNG stream and the second cold natural gas stream using the end flush gas stream further comprises.
The method according to claim 4. After cooling the second pressurized LNG stream and the second cold natural gas stream using the end flash gas stream, and compressing the end flash gas stream, wherein the compression end flash gas stream re Further including the step of mixing with the circulating refrigerant stream,
The method according to claim 6 . After cooling the second pressurized LNG stream and the second cold natural gas stream using the end flush gas stream, the end flash gas stream is compressed and the compressed end flash gas stream is used as fuel. Including further steps to use,
The method according to claim 6. The at least two compressors compress the natural gas stream to a pressure greater than 3,000 psia.
The method according to any one of claims 1 to 8 . The work-generated natural gas expander is configured to expand the cooled compressed natural gas stream to a pressure of less than 2,000 psia.
The method according to any one of claims 1 to 9 . The work-producing natural gas expander is mechanically coupled to at least one compressor.
The method according to any one of claims 1 to 9 . The step of cooling the compressed natural gas stream includes a step of cooling the compressed natural gas stream in at least one heat exchanger that exchanges heat with the environment.
The method according to any one of claims 1 to 11 . One of the at least two series-arranged compressors is driven by the work-producing natural gas expander.
The method according to any one of claims 1 to 12 . Further including a step of performing the compression step, a cooling step, an expansion step, and a liquefaction step on the upper deck of the floating LNG structure.
The method according to any one of claims 1 to 13 . The compressing, cooling, and expanding steps are performed within a single module on the upper deck of the floating LNG structure.
The method according to claim 14 . A device for liquefaction of natural gas
At least two series-arranged compressors configured to compress the natural gas stream to a first pressure greater than 2,000 psia, thereby forming a compressed natural gas stream.
A cooling element configured to cool the compressed natural gas stream and thereby form a cooled compressed natural gas stream.
The cooled compressed natural gas stream is expanded to a second pressure of less than 3,000 psia and not greater than the first pressure at which the at least two series-arranged compressors compress the natural gas stream. With at least one work-producing natural gas expander, configured to form a cold natural gas stream,
The chilled natural gas stream is the first chilled natural gas stream.
The device further
A means for separating the first chilled natural gas stream into a second chilled natural gas stream, a first refrigerant stream, and a second refrigerant stream.
Provided with equipment for liquefaction, configured to liquefy the cold natural gas stream.
The equipment for liquefaction includes an open-loop supply gas expander-based liquefaction module.
The device
Further comprising a recirculating refrigerant stream in the open-loop feed gas expander-based process that is combined with the natural gas stream before it is compressed by the two or three or more series-arranged compressors.
The open-loop supply gas expander-based liquefaction module
A warm-end inflator configured to expand the first refrigerant stream to form a first cooling stream having a first temperature discharged from the inflator.
A cold-end inflator configured to inflate the second refrigerant stream to form a second cooling stream having a second temperature discharged from the inflator.
A first heat exchanger configured to liquefy the second cold natural gas stream by heat exchange with the first cooling stream and the second cooling stream .
The first temperature is rather higher than the second temperature,
The recirculated refrigerant stream includes the heat exchanged first cooling stream and the second cooling stream .
A device characterized by that. A device for liquefaction of natural gas
At least two series-arranged compressors configured to compress the natural gas stream to a first pressure greater than 2,000 psia, thereby forming a compressed natural gas stream.
A cooling element configured to cool the compressed natural gas stream and thereby form a cooled compressed natural gas stream.
The cooled compressed natural gas stream is expanded to a second pressure of less than 3,000 psia and not greater than the first pressure at which the at least two series-arranged compressors compress the natural gas stream. With at least one work-producing natural gas expander, configured to form a cold natural gas stream,
The chilled natural gas stream is the first chilled natural gas stream.
The device further
A means for separating the first cold natural gas stream into a second cold natural gas stream, a first refrigerant stream, and a second refrigerant stream.
Provided with equipment for liquefaction, configured to liquefy the cold natural gas stream.
The equipment for liquefaction includes an open-loop supply gas expander-based liquefaction module.
The device
Further comprising a recirculating refrigerant stream in the open-loop feed gas expander-based process that is combined with the natural gas stream before it is compressed by the two or more series-arranged compressors.
The open-loop supply gas expander-based liquefaction module
A warm-end inflator configured to expand the first refrigerant stream to form a first cooling stream having a first temperature discharged from the inflator.
A cold-end inflator configured to expand the second refrigerant stream to form a two-phase stream having a second temperature discharged from the inflator.
A separator configured to separate the two-phase stream into a second cooling stream and a first pressurized LNG stream.
A first heat exchanger configured to liquefy the second cold natural gas stream by heat exchange between the first cooling stream and the second cooling stream.
With
The first temperature is higher than the second temperature.
The recirculated refrigerant stream includes the heat exchanged first cooling stream and the second cooling stream.
A device characterized by that. The work produced natural gas inflator is configured the cooling compressed natural gas stream to inflate to a pressure of less than 2,000 psia,
The device according to claim 16 or 17 . The cooling element comprises a second heat exchanger configured to cool the compressed natural gas stream by exchanging heat with the environment.
The apparatus according to any one of claims 16 to 18 . The at least two series-arranged compressors, the cooling element, the at least one work-producing natural gas expander, and the equipment for liquefaction are arranged on a floating LNG structure.
The apparatus according to any one of claims 16 to 19. The at least two series-arranged compressors, the cooling element, and the at least one work-producing natural gas inflator are arranged in a single module on the upper deck of the floating LNG structure.
The device according to claim 20.

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