阅读说明：本技术 双模式液化天然气（lng）液化器 (Dual mode Liquefied Natural Gas (LNG) liquefier ) 是由 N·M·普罗塞 R·M·凯莉 A·瓦泽 于 2020-05-15 设计创作，主要内容包括：本发明公开了一种双模式LNG液化器布置,该双模式LNG液化器布置能够被配置为在广义地表征为不具有涡轮膨胀的低压液氮添加LNG液化器的第一模式下或广义地表征为具有涡轮膨胀的低压液氮添加LNG液化器的第二模式下操作。(A dual mode LNG liquefier arrangement is configurable to operate in either a first mode broadly characterized as a low pressure liquid nitrogen addition LNG liquefier without turboexpansion or a second mode broadly characterized as a low pressure liquid nitrogen addition LNG liquefier with turboexpansion.)

1. A dual mode natural gas liquefier, comprising:

a heat exchanger having a plurality of cooling channels and a plurality of warming channels;

a natural gas inlet disposed on the heat exchanger and configured to receive a gaseous natural gas feed and distribute the natural gas through a plurality of cooling channels;

a natural gas outlet disposed on the heat exchanger and configured to discharge liquefied natural gas from the heat exchanger;

a liquid nitrogen inlet disposed on the heat exchanger and configured to receive a liquid nitrogen feed and distribute the liquid nitrogen through a plurality of warming channels;

a gaseous nitrogen outlet disposed on the heat exchanger and configured to discharge vaporized nitrogen from the heat exchanger;

wherein the heat exchanger is configured to liquefy the gaseous natural gas traversing the cooling passage via indirect heat exchange with nitrogen traversing the warming passage;

an intermediate outlet disposed on the heat exchanger and coupled to one or more warming channels of the plurality of warming channels and configured to divert a flow of gaseous nitrogen through the one or more warming channels of the plurality of warming channels;

a first intermediate inlet disposed on the heat exchanger; and

a second intermediate inlet disposed on the heat exchanger;

wherein the dual mode natural gas liquefier is configured to operate in a first mode or a second mode;

wherein when the dual mode natural gas liquefier is configured to operate in the first mode, the intermediate outlet is in fluid communication with the first intermediate inlet and a diverted gaseous nitrogen stream is reintroduced to the warming channel within the heat exchanger via the first intermediate inlet, wherein the temperature of the reintroduced nitrogen stream is equal to or greater than the temperature of the diverted gaseous nitrogen stream; and is

Wherein when the dual mode natural gas liquefier is configured to operate in the second mode, the intermediate outlet is in fluid communication with the second intermediate inlet, and wherein the diverted gaseous nitrogen stream is expanded and the expanded nitrogen stream is reintroduced to the warming channel within the heat exchanger via the second intermediate inlet and the diverted gaseous nitrogen stream is reintroduced to the warming channel within the heat exchanger via the first intermediate inlet, wherein the temperature of the reintroduced nitrogen stream is less than the temperature of the diverted gaseous nitrogen stream.

2. The dual mode natural gas liquefier of claim 1, wherein the heat exchanger comprises a cooling section, an intermediate section, and a warming section; and is

Wherein the natural gas inlet and the nitrogen outlet are disposed on the warming section of the heat exchanger, the liquefied natural gas outlet and the liquid nitrogen inlet are disposed on the cooling section of the heat exchanger, and the intermediate outlet, the first intermediate inlet, and the second intermediate inlet are disposed on the intermediate section of the heat exchanger.

3. The dual mode natural gas liquefier of claim 2, wherein the second intermediate inlet is disposed between the cooling section of the heat exchanger and the intermediate section of the heat exchanger.

4. The dual mode natural gas liquefier of claim 2, wherein the intermediate outlet is disposed between the intermediate section of the heat exchanger and the warming section of the heat exchanger.

5. The dual mode natural gas liquefier of claim 2, wherein the first intermediate inlet is disposed between the intermediate section of the heat exchanger and the warming section of the heat exchanger.

6. The dual mode natural gas liquefier of claim 1, wherein the heat exchanger comprises two or more separate heat exchangers comprising a cold heat exchanger and a warm heat exchanger;

wherein the warming channel of the cold heat exchanger is in fluid communication with a warming channel of the warm heat exchanger and the cooling channel of the cold heat exchanger is in fluid communication with the cooling channel of the warm heat exchanger;

wherein the liquefied natural gas outlet and the liquid nitrogen inlet are provided on the cold heat exchanger; and

wherein the natural gas inlet and the nitrogen outlet are disposed on the warm heat exchanger.

7. The dual mode natural gas liquefier of claim 6, wherein the cold heat exchanger is a brazed stainless steel heat exchanger and the warm heat exchanger is a brazed aluminum heat exchanger.

8. The dual mode natural gas liquefier of claim 6, wherein the cold heat exchanger is a stainless steel spiral wound heat exchanger and the warm heat exchanger is a brazed aluminum heat exchanger.

9. The dual mode natural gas liquefier of claim 6, wherein the second intermediate inlet is disposed between the cold heat exchanger and the warm heat exchanger.

10. The dual mode natural gas liquefier of claim 6, wherein the intermediate outlet is disposed at an intermediate location of the warm heat exchanger.

11. The dual mode natural gas liquefier of claim 6, wherein the first intermediate inlet is disposed at an intermediate location of the warm heat exchanger.

12. The dual mode natural gas liquefier of claim 6, further comprising a separator configured to remove Natural Gas Liquids (NGL) contaminants from the natural gas, the separator disposed upstream of and in fluid communication with the natural gas inlet or between the cold heat exchanger and the warm heat exchanger.

13. The dual mode natural gas liquefier of claim 1, further configured such that when configured to operate in the second mode, the dual mode natural gas liquefier further comprises a turbine configured to expand the diverted gaseous nitrogen stream and produce a turbine exhaust stream having a temperature less than a temperature of the diverted nitrogen stream.

14. The dual mode natural gas liquefier of claim 13, wherein the turbine comprises an air bearing turbine.

15. The dual mode natural gas liquefier of claim 13, wherein the turbine further comprises a turbine having an expansion ratio of between 2.0 and 4.0.

16. The dual mode natural gas liquefier of claim 13, further comprising a cold end blind flange configured to fluidly isolate a first set of warming channels within the warm heat exchanger from a second set of warming channels within the warm heat exchanger and to prevent nitrogen exiting the cold heat exchanger from reaching the second set of warming channels.

17. The dual mode natural gas liquefier of claim 13, further comprising a warm end blind flange disposed proximate to the first intermediate inlet and configured to prevent any flow of nitrogen into or out of the heat exchanger via the first intermediate inlet.

18. The dual mode natural gas liquefier of claim 1, further comprising:

a liquid nitrogen storage tank in fluid communication with the liquid nitrogen inlet and configured to supply the liquid nitrogen feed; and

an LNG tank in fluid communication with the LNG outlet and configured to hold the LNG produced by the dual mode natural gas liquefier.

19. The dual mode natural gas liquefier of claim 1, further comprising a pump disposed upstream of and in fluid communication with the liquid nitrogen inlet, the pump configured to raise the pressure of the liquid nitrogen feed.

20. The dual mode natural gas liquefier of claim 1, further comprising a natural gas compressor disposed upstream of and in fluid communication with the natural gas inlet, the natural gas compressor configured to raise the pressure of the natural gas feed.

Technical Field

The present invention relates to the production of Liquefied Natural Gas (LNG) and, more particularly, to a small or micro-scale nitrogen refrigeration LNG production system suitable for use in a distributed LNG production environment.

Background

Demand and acceptance by energy, transportation, heating, power generation and utility sectors for both LNG production and LNG use applications is rapidly increasing because the use of LNG is less costly and alternative fuels also allow for the potential reduction of carbon emissions and other harmful emissions such as Nitrogen Oxides (NOX), Sulfur Oxides (SOX) and particulate matter generally considered to be harmful to air quality.

One such LNG production application is flare gas capture, as many energy companies seek methods to reduce the combustion of methane gas associated with crude oil and bitumen production by the purification and liquefaction of gaseous by-products and subsequent distribution of the resulting LNG along highway or ocean transportation or the use of LNG fuel on site. The united states Energy Information Agency (EIA) reports that over 2350 hundred million cubic feet of natural gas was discharged and/or burned in 2017 alone, essentially discarding a very valuable resource from the national oil and gas supply chain.

In areas with little access to natural gas pipeline distribution networks, a new trend has emerged in distributed LNG production involving the construction and operation of smaller LNG plants or production systems built into regions where attractive sources of low cost natural gas or methane biogas are available, and there is currently a demand for LNG or the demand is expected to grow over time. With this small scale LNG production, stranded gas resource owners can monetize their natural gas assets that cannot be connected to the natural gas pipeline network. Such small scale LNG production may also economically enable or further enhance crude oil production in certain regions that do not have pipeline infrastructure that can capture associated natural gas produced with the oil. Other distributed LNG opportunities include oil well seeding, LNG supply at compressed natural gas fueling stations, LNG production from biological gas sources (such as landfills, farms, industrial/municipal waste and wastewater operations), and the like.

The goal of most conventional small-scale or micro-scale LNG production systems is to produce 5000 gallons per day (0.4MMSCFD) to 15000 gallons per day (1.2MMSCFD) of LNG and employ mechanical refrigeration to cool the collected gas to natural gasSub-zero temperatures required for liquefaction. Two examples of small or micro-scale mechanical-based refrigeration solutions on the market are LNGo provided by Siemens sender Rand^TMMicro-scale LNG production system and designed and manufactured by GalileoLNG production station.

Disadvantages of these mechanically-based refrigeration LNG production systems for small-scale LNG production include the relatively high capital cost of the mechanically-based refrigeration LNG production system, the large size/footprint and complexity of the mechanically-based refrigeration LNG production system, significant power consumption, high maintenance costs associated with compression and refrigeration equipment in the mechanically-based refrigeration LNG production system, as well as the general lack of design flexibility during installation/commissioning and system inefficiencies, particularly during turndown operations, as compared to nitrogen-based refrigeration LNG production systems.

Although nitrogen refrigeration based liquefaction systems are well known and currently used in large scale LNG production plants, this technology has not proven commercially viable for small or micro scale LNG production. What is needed is a low capital cost nitrogen refrigeration based micro-scale LNG production system that is compact, modular, and mobile, yet provides design and cost flexibility in the configuration of the micro-scale LNG production system.

Disclosure of Invention

The invention may be characterized as a dual mode natural gas liquefier, comprising: (i) a heat exchanger having a plurality of cooling channels and a plurality of warming channels, the heat exchanger configured to liquefy gaseous natural gas traversing the cooling channels via indirect heat exchange with nitrogen traversing the warming channels; (ii) a natural gas inlet disposed on the heat exchanger and configured to receive a gaseous natural gas feed and distribute the natural gas through the plurality of cooling channels; (iii) a natural gas outlet disposed on the heat exchanger and configured to discharge liquefied natural gas from the heat exchanger; (iv) a liquid nitrogen inlet disposed on the heat exchanger and configured to receive a liquid nitrogen feed and distribute the liquid nitrogen through a plurality of warming channels; (v) a gaseous nitrogen outlet disposed on the heat exchanger and configured to discharge vaporized nitrogen from the heat exchanger; (vi) an intermediate outlet disposed on the heat exchanger and coupled to one or more of the plurality of warming channels and configured to divert a flow of gaseous nitrogen through one or more of the plurality of warming channels; (vii) a first intermediate inlet disposed on the heat exchanger; and (viii) a second intermediate inlet provided on the heat exchanger.

The presently disclosed dual mode natural gas liquefier is configured to operate in either a first mode or a second mode. When operating in the first mode, the intermediate outlet is in fluid communication with the first intermediate inlet and the diverted flow of gaseous nitrogen is reintroduced to the warming channel within the heat exchanger via the first intermediate inlet, wherein the temperature of the reintroduced flow of nitrogen is equal to or greater than the temperature of the diverted flow of gaseous nitrogen. In another aspect, when the dual mode natural gas liquefier is configured to operate in the second mode, the intermediate outlet is in fluid communication with the second intermediate inlet, and wherein the diverted gaseous nitrogen stream is expanded and the expanded nitrogen stream is reintroduced to the warming channel within the heat exchanger via the second intermediate inlet, and the diverted gaseous nitrogen stream is reintroduced to the warming channel within the heat exchanger via the first intermediate inlet, wherein the temperature of the reintroduced nitrogen stream is less than the temperature of the diverted gaseous nitrogen stream.

Additionally, when the dual mode natural gas liquefier is configured to operate in the second mode, the dual mode natural gas liquefier further comprises a turbine configured to expand the diverted gaseous nitrogen stream and produce a turbine exhaust stream having a temperature less than a temperature of the diverted nitrogen stream. The turbine is preferably an air bearing turbine having an expansion ratio between 2.0 and 4.0. Further, to isolate the nitrogen flow within the heat exchanger during the second mode, cold and warm end blind flanges are installed. The cold end blind flange fluidly isolates the first set of warming channels from the second set of warming channels within the warm heat exchanger, thereby preventing nitrogen exiting the cold heat exchanger from reaching the second set of warming channels. A warm end blind flange is disposed proximate the first intermediate inlet and is configured to prevent any flow of nitrogen into or out of the heat exchanger via the first intermediate inlet.

The heat exchanger includes two or more separate heat exchangers including a cold heat exchanger and a warm heat exchanger. The warming channel of the cold heat exchanger is in fluid communication with the warming channel of the warm heat exchanger, and the cooling channel of the cold heat exchanger is in fluid communication with the cooling channel of the warm heat exchanger. In both heat exchanger arrangements, the liquefied natural gas outlet and the liquid nitrogen inlet are provided on the cold heat exchanger, while the natural gas inlet and the nitrogen outlet are provided on the warm heat exchanger. Preferably, the warm heat exchanger is a brazed aluminum heat exchanger and the cold heat exchanger is a brazed stainless steel heat exchanger or a stainless steel spiral wound heat exchanger. In addition, the second intermediate inlet is preferably provided between the cold heat exchanger and the warm heat exchanger, and the intermediate outlet and the first intermediate inlet are preferably provided at an intermediate position of the warm heat exchanger.

The use of the dual mode LNG liquefier of the present invention in an LNG plant, which is typically sized to capture a flare gas volume in the range of about 0.4 to 1.5MMSCFD, is expected to result in lower overall capital costs for the LNG plant as compared to a conventional small scale LNG plant with mechanical refrigeration.

The small-scale LNG production system of the present invention with liquid nitrogen refrigeration presents at least two distinct and advantageous features. First, small scale LNG production systems with liquid nitrogen refrigeration are designed or configured to operate in dual modes, including a first mode without a turbine or a second mode with a turbine. The heat exchanger arrangement and associated piping in a dual mode LNG liquefier would be able to accommodate either configuration with little design change. In that way, depending on the parameters of a given project opportunity and the regional cost of liquid nitrogen, an LNG liquefier design without a turbine or an LNG liquefier design with a turbine may be selected. Thus, a fixed or common heat exchanger arrangement enables a more flexible supply for a given project at potentially lower installation costs, and facilitates predictable and rapid project planning. The dual mode LNG liquefier design of the present invention also enables a compact embedded cold box design for any project opportunity. A second advantageous feature is that the LNG liquefier capacity is such that when configured to operate in the second mode with the turbine, the turbine pressure and temperature conditions are selected such that a low cost portable air bearing turbine can be employed.

Drawings

The claimed invention is believed to be better understood when taken in conjunction with the accompanying drawings, wherein:

FIG. 1 illustrates a schematic flow diagram of a dual mode LNG liquefier with liquid nitrogen refrigeration configured to operate in a first mode, the dual mode LNG liquefier liquefying a natural gas feed without using supplemental refrigeration from a turboexpander;

FIG. 2 illustrates a schematic flow diagram of an alternative embodiment of a dual mode LNG liquefier with liquid nitrogen refrigeration configured to operate in a first mode, the dual mode LNG liquefier liquefying the natural gas feed without using supplemental refrigeration from the turboexpander;

FIG. 3 illustrates a schematic flow diagram of a dual mode LNG liquefier with liquid nitrogen refrigeration configured to operate in a second mode, the dual mode LNG liquefier liquefying the natural gas feed with supplemental refrigeration from the turboexpander;

fig. 4A and 4B are graphical illustrations of temperature profiles of respective streams in a dual mode LNG liquefier, with fig. 4A showing a temperature profile for a first mode and fig. 4B showing a temperature profile for a second mode;

fig. 5A and 5B conceptually depict a schematic flow diagram of a dual mode LNG liquefier arrangement having a common heat exchanger arrangement operating in a first mode (fig. 5A) or a second mode (fig. 5B);

FIG. 6 conceptually depicts a physical arrangement of flow paths for distributing nitrogen flow in warming channels in various modes of operation; and

fig. 7A and 7B illustrate a preferred heat exchange channel configuration with additional design details regarding the preferred header and distributor.

Detailed Description

A dual mode LNG liquefier arrangement configurable to operate in either a first mode or a second mode is provided. The first mode of operation is broadly characterized as a low pressure liquid nitrogen plus LNG liquefier without turboexpansion, while the second mode of operation is broadly characterized as a low pressure liquid nitrogen plus LNG liquefier with turboexpansion. Advantageously, the dual mode LNG liquefier arrangement is configured or fabricated to have the same fixed heat transfer surface area for both modes of operation. The design and installation flexibility provided by the dual mode LNG liquefier arrangement facilitates a supplier or customer selection of whether to employ a turbine to expand the vaporized nitrogen turbine in a small-scale LNG production process to achieve optimal project economics.

When using a dual mode LNG liquefier arrangement configured to operate in the second mode with a turbine, the initial capital cost associated therewith is higher due to the presence of the turbine compared to a base LNG liquefier arrangement configured to operate in the first mode. On the other hand, using a dual mode LNG liquefier arrangement configured to operate in the first mode without a turbine requires a potential reduction in capital costs, but requires additional liquid nitrogen to liquefy the same volume of natural gas. Generally, the price of liquid nitrogen is very dependent on the location of the proposed installation site and the distance between the source of liquid nitrogen production and the proposed installation site.

In addition, as is well known in the art, the volume of liquid nitrogen required for natural gas liquefaction depends on the surface area of the heat exchanger as well as the pressure of the natural gas feed, the natural gas composition, and the ambient temperature. Under natural gas supply conditions, feed pressure will have the greatest effect on the liquid nitrogen required to date. For example, in either mode of operation, if the natural gas feed is supplied at a pressure of 500psig, the total liquid nitrogen demand is reduced by about 5% to 6% compared to a pressure of 100 psig. Increasing the natural gas feed pressure can be easily achieved, but may require capital purchase and installation of a natural gas compressor, which negatively impacts project economics.

Turning now to the drawings, fig. 1 shows a schematic flow diagram of a dual mode LNG liquefier arrangement 100 configured to operate in a first mode, without a turbine, and without turboexpansion of vaporized nitrogen. In this embodiment, liquid nitrogen stream 114 is preferably supplied from storage tank 115 or other liquid nitrogen source at not less than about 55psia, so that the liquid nitrogen is at a temperature sufficiently warm to avoid freezing the liquefied natural gas. Brazed aluminum heat exchangers (BAHX) cannot be used for natural gas liquefaction and subcooling due to the large difference between the condensation temperature of natural gas and the boiling temperature of nitrogen. A possible alternative is to use a brazed stainless steel heat exchanger (BSSHX) for the cold end of the heat exchanger arrangement, but a stainless steel spiral wound heat exchanger is also a viable option.

As can be seen in fig. 1, the heat exchanger arrangement is preferably made up of two sections, including a cooling section 130 with heat exchange channels C1 and C3 in the BSSHX and a warmer section 120 as the BAHX with heat exchange channels M1, W1, M3 and W3. Heat exchange channel C1 is configured to receive liquid nitrogen stream 114 at a nitrogen inlet of BSSHX 130 and produce nitrogen effluent stream 112 at a nitrogen outlet of BSSHX 130. Heat exchange channels M1 and W1 are disposed in BAHX 120 and are configured to receive effluent stream 112 from BSSHX 130 at an intermediate inlet and produce vaporized nitrogen stream 110 at a nitrogen outlet. The illustrated heat exchanger arrangement is further configured to receive a natural gas feed 102, the natural gas feed 102 optionally being compressed in a compressor 104 and cooled in an aftercooler 116 to produce a conditioned natural gas feed 108, the conditioned natural gas feed 108 being introduced to the BAHX 120 at the natural gas inlet. Conditioned natural gas feed 108 is cooled in heat exchange channels W3 and M3 in BAHX 120 to produce cooled natural gas stream 127, which cooled natural gas stream 127 is taken at an intermediate outlet of BAHX 120 and directed to an inlet of BSSHX 130, and specifically in heat exchange channel C3, wherein the natural gas is liquefied via indirect heat exchange with liquid nitrogen stream 114 to produce liquefied natural gas stream 132, which liquefied natural gas stream 132 may be depressurized in expansion valve 134 and stored in tank 135.

The illustrated heat exchanger arrangement is designed and configured such that only the heat duty necessary to perform natural gas liquefaction is performed in the BSSHX, as the heat transfer surface cost in the BSSHX is typically higher than that of the BAHX. This means that almost all liquefaction of the natural gas and all liquid subcooling occurs in the cooling section or BSSHX, while most of the heat transfer surface area is included in the BAHX.

From a design point of view, only minor amounts of heavier hydrocarbons (i.e., heavier than methane) may condense in the warmer section or BAHX portion of the heat exchanger arrangement. A suitable amount of natural gas steam subcooling also occurs in the cooling section or BSSHX. This is necessary because it ensures that the vaporized nitrogen is sufficiently warmed before exiting the BSSHX and avoids any unacceptably high temperature differences in the BAHX.

Fig. 2 shows an alternative embodiment of the LNG liquefier arrangement of the present invention. Many of the components in the LNG liquefier arrangement shown in fig. 2 are similar or identical to those described above with reference to fig. 1, and will not be repeated for the sake of brevity. The difference between the embodiment of figure 2 compared to the embodiment shown in figure 1 is the addition of the NGL removal loop. In some cases, pre-treatment of the natural gas is performed to remove Natural Gas Liquids (NGL) prior to the feed stream entering the LNG liquefier supply line. It is important to remove NGLs in order to avoid freezing of heavier components in the cooling section. If NGL has not been removed in upstream operations, such removal of NGL should occur prior to entering the BSSHX, as shown in fig. 2. In this embodiment, the natural gas stream 122 exiting the BAHX 120 is diverted to a separator 125, the separator 125 configured to remove NGL. The cooled, purified natural gas stream 126 is directed to the BSSHX 130 while the removed NGL streams can be vented to provide the auxiliary product stream 128A, or if they are to be recovered or otherwise used locally as fuel, the separated NGL stream 128B can be re-warmed in the BAHX 120.

Turning now to fig. 3, a schematic flow diagram of a dual mode LNG liquefier arrangement configured to operate in the second mode is shown. Also, since many of the components in the LNG liquefier arrangement shown in fig. 3 are similar or identical to those described above with reference to fig. 1, the description thereof will not be repeated. The difference between the embodiment of fig. 3 compared to the embodiment shown in fig. 1 is the addition of a turbine 142, which turbine 142 is configured to expand all or a portion of the vaporized nitrogen stream 140 extracted from an intermediate location of BAHX 120 (preferably between heat exchange channels M1 and W1).

By employing turbines of appropriate temperature levels, additional refrigeration is supplied to the LNG production system at the required temperature above the liquid nitrogen boiling zone. This in turn mitigates intermediate temperature pinch, such that liquid nitrogen consumption is reduced compared to the first mode of operation described above with reference to fig. 1, and in this embodiment, the temperature end difference in the heat exchanger arrangement may be reduced to a practical minimum.

As indicated above, the vaporized nitrogen stream 140 is extracted from an intermediate location of the BAHX 120, expanded in the turbine 142, and the turbine exhaust 144 is returned to the BAHX 120 at the appropriate location. Preferably, the heat exchanger arrangement is designed such that the turbine exhaust 144 is returned to a location at the break point between the BSSHX 130 and the BAHX 120. The turbine exhaust 144 is then warmed in heat exchange passages M2 and W2 and exits BAHX 120 as vaporized nitrogen stream 145.

In the embodiment of fig. 3, the vaporized nitrogen stream 140 extracted from the intermediate location of BAHX 220 is preferably at a pressure selected to achieve the desired turboexpansion, preferably between about 50psia and about 150psia, and more preferably between about 50psia and about 100 psia. To achieve this desired pressure, the pressure of the liquid nitrogen stream 114 may be raised using a dedicated pump 116 or simply by operating the liquid nitrogen storage tank 115 at high pressure. When a dedicated pump is used, the high pressure liquid nitrogen stream 118 fed to the cooling section of the heat exchanger or BSSHX 130 will be subcooled, while the liquid nitrogen feed is preferably a warmer saturated liquid if the pressure of the liquid nitrogen storage tank 115 is raised. Thus, using pump 116 will reduce total liquid nitrogen consumption, but introduces additional cost and complexity.

Fig. 4A and 4B are graphical illustrations of temperature profiles of respective streams in a dual mode LNG liquefier, with fig. 4A showing a temperature profile for a first mode and fig. 4B showing a temperature profile for a second mode. Curves 150A and 155A represent the temperature profiles of the warmed nitrogen and the cooled natural gas, respectively, as a function of the heat load fraction in the first mode of operation, while curves 150B and 155B represent the temperature profiles of the warmed nitrogen and the cooled natural gas, respectively, as a function of the heat load fraction in the second mode of operation with turboexpansion of the warmed nitrogen stream.

Comparing the temperature profiles shown in fig. 4A and 4B highlights the benefit given by the second mode of operation compared to the first mode of operation. Specifically, the decreasing slope in the warmed nitrogen temperature profile 150B in fig. 4B indicates the region where the turbine provides additional refrigeration. Point 156 represents an intermediate position of the vaporized nitrogen stream 140 extracted from the warmer section of the BAHX 120, while point 158 represents a position where the turbine exhaust is reintroduced into the BAHX 120. Thus, the nitrogen flow required for the lower refrigeration demand regions above the turbine (i.e., above points 156 and 158) and below the turbine (i.e., below points 156 and 158) may be reduced. Natural gas compression is generally optional for all configurations and modes of operation. If natural gas compression is used, the resulting reduction in liquid nitrogen is in addition to the reduction in liquid nitrogen provided by the turboexpansion of the warmed nitrogen stream.

While the addition of the turbine 142 significantly reduces liquid nitrogen consumption in the disclosed LNG production system, it is important that the second mode of operation be configured to operate in a cost effective manner. In preferred embodiments, the turbine inlet pressure for the second mode of operation is preferably in the range of about 50psia to about 100psia, although the pressure may be up to about 150 psia. The turbine outlet pressure is preferably in the range of about 15psia to about 30 psia. The warmed nitrogen vent stream 144 from the turbine may be vented to the atmosphere or used in a pre-treatment or post-treatment step, such as for natural gas purifier regeneration.

For example, in some applications, a natural gas feedstream is purified in a pretreatment step using a Temperature Swing Adsorption (TSA) bed to convert impurities (i.e., CO)₂And H₂O) to below 50ppm and 1ppm, respectively. The molecular sieve bed of TSA may be purged and regenerated using the vaporized nitrogen exiting the dual mode liquefier. This would represent an improvement over conventional techniques using clean natural gas, as is embodied in many conventional small-scale LNG production systems. The use of a molecular sieve bed purged with vaporized nitrogen and regenerated TSA significantly reduces the volume of hydrocarbons that would otherwise be discharged or combusted.

An air bearing turbine is the preferred choice of turbine for use in the second mode, primarily because of its low cost. Air bearing turbines also have the important benefit of being devoid of a lubrication system, which facilitates a compact and portable design when a turbine is added. A blower may be used to dissipate expansion energy from the turbine without coupling the turbine to an external facility. Alternatively, oil brakes or generators could be used, but these would require connections to external supplies that would prevent a compact and portable design that could be mounted on a flatbed trailer to facilitate portability.

Turning now to fig. 5A and 5B, a schematic flow diagram of an alternative embodiment of a dual mode LNG liquefier arrangement 200 having a fixed or common heat exchanger arrangement is shown. Fig. 5A conceptually depicts natural gas and liquid nitrogen flow paths when the fixed or common heat exchanger arrangement is configured to operate in a first mode, while fig. 5B conceptually depicts the corresponding flow paths when the fixed or common heat exchanger arrangement is configured to operate in a second mode.

As can be seen in fig. 5A, the illustrated embodiment of the heat exchanger arrangement or liquefier 200 is also preferably comprised of two sections, including a cooling section or BSSHX 230 having heat exchange channels C1 and C3 and a warmer section BAHX 220 having heat exchange channels M1, M2, M3, W1, W2, and W3. Heat exchange channel C1 is configured to receive liquid nitrogen stream 214 at a nitrogen inlet of BSSHX 230 and produce nitrogen effluent stream 212 at a nitrogen outlet of BSSHX 230. Heat exchange channels M1, M2, W1, and W2 are disposed in BAHX 220 and are configured to receive effluent stream 212 from BSSHX 230 at an intermediate inlet and produce vaporized nitrogen stream 210 at a nitrogen outlet. The illustrated heat exchanger arrangement is further configured to receive a conditioned natural gas feed 208, which conditioned natural gas feed 208 is introduced to the BAHX 220 at a natural gas inlet. Conditioned natural gas feed 208 is cooled in heat exchange channels W3 and M3 in BAHX 220 to produce cooled natural gas stream 227, which cooled natural gas stream 227 is taken at an intermediate outlet of BAHX 220 and directed to an inlet of BSSHX 230, and specifically in heat exchange channel C3, wherein the natural gas is liquefied via indirect heat exchange with liquid nitrogen stream 214 to produce liquefied natural gas stream 232.

As can be seen in fig. 5B, the turbine branch or extraction point of turbine flow 240 is located at an intermediate location of BAHX 220. Extracted turbine stream 240 is expanded in turbine 242, with the resulting turbine exhaust stream 244 being returned to the inlet of BAHX 220, preferably to heat exchange path M2 and continuing through heat exchange paths W1 and W2. The preferred location of the extraction point of the turbine flow 240 is determined based on UA values selected for common designs, as generally taught in the examples below. The turbine exhaust stream 244 is returned to an inlet disposed at a location preferably at the breakpoint between the BSSHX 230 and BAHX 220. The exhaust stream 244 is used to cool the natural gas stream that traverses the BAHX 220 via indirect heat exchange and exits as stream 245 from the nitrogen outlet of the BAHX 220.

In both embodiments shown in fig. 5A and 5B, the liquid nitrogen and vaporized nitrogen within BAHX 220 are apportioned across warming heat exchange channels M1, M2, W1 and W2 through which it passes, which is required to maintain the highest utilization, which should result in the most efficient or most efficient design. That is, any warmed heat exchange passages that are simply not used in the design case will result in a potentially inefficient design. The substantial relative flow of each stream means that heat exchanger layers not used in a mode will significantly reduce efficiency in that mode. In the embodiment shown in fig. 5A and 5B, all warming heat exchange channels M1, M2, W1, and W2 are utilized in both the first mode and the second mode.

In a second mode of operation utilizing turbine 242, warmed turbine exhaust gas flow 244 is split at or near the extraction point such that all warmed heat exchange passages of BAHX 220, i.e., heat exchange passages W1 and W2, are used. The desired distribution of the flow in the BAHX 220 will be such that the warm end temperatures of the flows in the heat exchange channels W1 and W2 are almost the same (i.e. the maldistribution is minimal).

In fig. 5A, the warmed steam nitrogen exiting the BSSHX 230 must be properly distributed to the warmed heat exchange channels within the BAHX 220 so that all channels (conceptually depicted as M1 and M2) are effectively utilized. Similar to the second mode of operation, the flow of nitrogen in the warming channel M2 is drawn or extracted from the BAHX and then quickly returned to the warming heat exchange channel depicted as W2. Thus, the correct distribution of nitrogen vapor in M1 and M2 will produce very similar warm end temperatures for channels M1 and M2, and very similar warm end temperatures for channels W1 and W2.

For the second mode of operation, the relative volumetric flow rates of nitrogen and natural gas at the cold end of BAHX 220 are shown in the table below, which is associated with the examples. The lower pressure of the turbine exhaust stream, compared to the nitrogen stream, is preferably converted to a volumetric flow of the turbine exhaust stream that is about four times (4 times) the flow of nitrogen vapor from the BSSHX into the cold end of the BAHX. Additionally, the lower pressure of the turbine exhaust stream compared to the nitrogen stream means that the cost of the turbine exhaust stream associated with or due to the pressure drop is higher. From a design perspective, this implementation would suggest using more heat exchange layers and/or lower pressure drop extension fins for the warming channel in M1.

Meanwhile, the distribution of the nitrogen vapor flow between the warming channels W1 and W2 for the second operation mode and the distribution of the nitrogen vapor flow between the warming channels M1 and M2 for the first operation mode should be reasonably ideal. The importance and relevance of a lower pressure drop for the turbine exhaust stream compared to other nitrogen vapor streams means that the turbine exhaust stream will preferably use a centrally located header and distributor within the BAHX, which typically achieves a lower pressure drop compared to peripherally located or other distributors.

FIG. 6 schematically depicts the physical arrangement of flow paths and conduits for distributing nitrogen flow in the warming channel in various operating modes for the embodiment shown in FIGS. 5A and 5B.

Fig. 7A and 7B illustrate a preferred heat exchange channel configuration with additional design details regarding the preferred header and distributor. These figures illustrate the flow paths within the BAHX for: from the BSSHX, through to boiling LIN in M2, and to nitrogen in exhaust from the turbine in M1 in designs operating in the second mode, and to the remainder of boiling LIN in M1 in designs operating in the first mode. Note that fig. 6, 7A, and 7B do not show the flow or heat exchange configuration of the cooled natural gas stream to avoid unnecessary complications. Ideally, the natural gas stream would occupy adjacent layers in both sections of the BAHX.

As can be seen in fig. 7A and 7B, when operating in the second mode of operation, the nitrogen stream from the BSSHX is preferably directed to end-side header 302 for feeding into the warming channel (collectively identified as M2) of the BAHX. A cold end blind flange 304 is disposed upstream of the BAHX in the cold end piping to prevent any nitrogen flow exiting the BSSHX from reaching the warming channel (collectively identified as M1) in the BAHX. Cold end blind flange 304 substantially isolates the flow fed to warming channels M1 and M2 of BAHX. Alternatively, the portion of the duct depicted as containing the cold end blind flange may simply be uninstalled.

The warmed nitrogen vapor stream from warming channel M2 of the BAHX is extracted into side header 306 and supplied to a turbine (not shown) where the stream is expanded. The expanded turbine exhaust stream 244 from the turbine is then fed into the warming channel M1 of the BAHX 220 via an inlet, which may include a centrally located header and distributor 310. The warmed nitrogen vapor stream from the warming channel M1 of the BAHX is drawn into the other side header 312 and returned to the warming channels W1 and W2 of the BAHX 220. This other side header 312 is also referred to as a turnaround header. The warm end blind flange 314 is disposed near or adjacent to the swing header and prevents any external flow from entering the swing header 314 in the second mode of operation and prevents any internal flow from exiting the swing header 314. Instead of a warm end blind flange, for designs operating in this mode, this section of the duct can be eliminated.

When operating the LNG production system in the first mode of operation, the cold end blind flange 304 is removed or not installed. The nitrogen stream from BSSHX 230 is preferably evenly distributed to the warmed heat exchange channels M1 and M2 of BAHX 220. The flow of warmed nitrogen from the warmed heat exchange passages, collectively identified as M2, in the BAHX 220 is directed from one side header 306 to the other side header 312 of the BAHX, rather than to the turbine in the pipe section connection location designated 241 in fig. 5A and 6. For this first mode of operation, warm end blind flange 314 is also removed or not installed so that the warmed stream from warming channel M2 within BAHX exits BAHX at the other side header 306 and returns to BAHX at turnaround header 312 where it mixes with the warmed stream from warming channel M1 of BAHX. The mixed stream is distributed or distributed into warming channels W1 and W2 of BAHX 220 and exits via outlet header 318.

In both modes of operation, the warming channels of the BAHX, collectively identified as W1 and W2, contain a common or mixed flow. Thus, warming channels W1 and W2 would preferably be designed to have the same heat transfer fin selection, UA value, etc. Thus, the warming layer that collects each of the warming streams M1 and M2 is shown in fig. 7A and 7B as combined streams W1 and W2.

As shown in example 2 below, it is also preferable that the total number of layers used for warming channels W1 and W2 be the same as the number of layers for warming channels M1 and M2. Such an arrangement would avoid the need to redistribute the cooled natural gas flowing from the warmed section of the BAHX to the intermediate section of the BAHX. It is desirable to achieve good flow distribution between the warming channels M1 and M2 in the BAHX and between the warming channels W1 and W2 in the BAHX by appropriate selection of the number of layers and heat transfer fins, and appropriate design of the headers, distributors, and associated piping. Flow restricting devices may also be installed in the piping between the two cold side headers of the BAHX and/or between the two side headers of the BAHX, if desired. Examples of flow restricting devices include fixed orifices or adjustable trim valves.

The nitrogen refrigeration system described above for small or micro-scale LNG production is well suited for modular form. Because the disclosed LNG production system enables design flexibility with or without turbines, there is little additional engineering cost and the project is performed quickly.

To take advantage of this modularity, the base LNG production system should be designed to handle the most likely LNG production rate, expected to be approximately 5000 gallons per day (0.4MMSCFD) to 15000 gallons per day (1.2 MMSCFD). For customers with higher demand for LNG production, the proposed solution would involve integrating two or more of the above-described modular LNG production systems, rather than building a custom designed medium-scale LNG production plant. For example, a client that requires about 20000 gallons of LNG per day would likely use two modules.

Another possibility where the modularity of the presently disclosed LNG production system is advantageous is in the following cases: the sales of LNG for customers are growing and it is desirable to make more LNG product sometime after the initial installation of the original LNG production system. The presently disclosed LNG production modules are ideal for adding LNG capacity in modest increments.

The modular design of small-scale or micro-scale LNG production systems facilitates different design approaches that may be beneficial. For example, two modules may be configured such that a common turbine is being serviced and coupled to both modules. In this case, the selected turbine should be able to effectively handle a wider range of flow conditions for a multi-module installation. Such an arrangement having multiple modules served by a single turbine would provide advantages such as capital cost savings or greater efficiency than employing a separate turbine for each module. Alternatively, a multi-module installation may use one or more turbines for some of the modules, and not others, as such a hybrid arrangement may be beneficial in some circumstances, particularly where modules are added over time or liquid nitrogen costs vary over time.

It should also be noted that while it is expected that a given LNG production system installation at a given customer site may not be possible to convert from a configuration employing a turbine to a configuration without a turbine, or vice versa, the addition or removal of such a turbine may be readily performed during periodic maintenance/refurbishment of the LNG production system, or in the event of a turbine failure, or even in response to significant changes in liquid nitrogen costs.

In the case of blind flanges, as described above, the cost and penalty incurred in converting from one configuration to another at the customer site may be minimal. Furthermore, the blind flange may be replaced with one or more manual valves if the intended customer may ultimately desire or intend to replace the LNG production system with or without the turbine at least once during the intended life of the installation, or possibly even more frequently. To achieve ultimate flexibility, LNG production system installations may include turbines and automatic control valves to quickly change to turbine-based operations and from turbine-based operations to non-turbine-based operations as needed. Generally, the use of blind flanges is preferred due to lower cost and complete avoidance of valve leakage, the presence of which would result in a loss of efficiency.

Example 1

The first embodiment is a computer model simulation that attempts to compare and verify the optimal heat exchanger design for a dual mode LNG liquefier over the expected range of LNG applications.

In table 1, the relative liquid nitrogen flow rates and turbine pressures for LNG production systems designed for applications with different natural gas feed pressures, including a natural gas feed pressure of 100psia and a natural gas feed pressure of 500psia, are shown. Natural gas feed pressure is the most critical state condition affecting liquefier design and performance. Table 1 also shows the relative UA, which is normalized for flow to better represent the actual heat transfer surface area required for each of the four design cases. In other words, table 1 shows the performance and heat exchanger UA requirements for the optimal or customized heat exchanger design for the four selected cases. The optimal design is defined such that each heat exchange section provides an optimal but practical temperature differential profile.

Table 1. LNG liquefier with liquid nitrogen refrigeration and custom heat exchanger

As can be seen in fig. 1 and 3 and as discussed above, the BSSHX represents a cooling section of a heat exchanger arrangement or a brazed stainless steel heat exchanger. The middle section of the BAHX and the warming section of the BAHX represent portions of the warmer section of the heat exchanger arrangement or brazed aluminum heat exchanger. The dividing point between the intermediate section of the BAHX and the warmed section of the BAHX is the point of extraction of the turbine feed stream, as represented by the "M" and "W" heat exchange channels in the drawing. In the operation mode 1 case configured without a turbine, there is no extraction point, so the relative UA value of BAHX represents the combined value.

The simulation data shown in table 1 indicates that the ideal or optimal heat transfer surface area is highly variable in the four design cases. The relative UA of the BSSHX is relatively constant, but the relative UA of the total BAHX varies significantly, as does the relative UA between the intermediate section of the BAHX and the warmed section of the BAHX, which represents an ideal or optimal extraction point for the turbine feed stream. It is also apparent from the data in table 1 that the design case using a low pressure natural gas feed (i.e., 100psig) requires a much larger BAHX surface area than the design case using a high pressure natural gas feed (i.e., about 500 psig). In mode 2 of operation with a turbine, this excess surface area is in the warmed-up section of the BAHX above the turbine branch point.

Example 2

The second embodiment is a computer model simulation that attempts to compare and verify whether a fixed heat exchanger design based in part on the optimal heat exchanger design characterized in embodiment 1 will perform acceptably in the first and second operating modes.

In table 2, the relative UA value of the flow normalization remains constant for each heat exchange section, as is the case in fixed or common heat exchanger designs. Any performance trade-off will be indicated by comparing the relative liquid nitrogen flow in table 2 with the equivalent design case in table 1 above. Note that the UA selection for each section is not simply to over-design the BAHX and eliminate any possible performance loss. While these heat exchangers will be relatively small and low cost, it is expected that the need for portability and low installation cost will be realized by selecting a relatively low UA value. The total UA of 0.60 for BAHX is lower than the best custom design UA for all but one case in table 1. UA of 0.10 for BSSHX approximates the average of the custom design cases of table 1, which applies to relatively constant requirements.

Table 2. LNG liquefier with liquid nitrogen refrigeration and common heat exchanger

For the mode 1 configuration, there was no significant increase in liquid nitrogen flow when using a low pressure natural gas feed (i.e., 100psig) and no significant decrease in liquid nitrogen flow when using a medium or high pressure natural gas feed (i.e., 500psig) without a turbine or turbine extraction point. In other words, selecting a common heat transfer surface area design for the low pressure natural gas case results in insignificant losses.

For a mode 2 configuration with a turbine and defined turbine extraction point, the liquid nitrogen flow can be held constant for both low pressure natural gas feed (i.e., 100psig) and medium or high pressure (i.e., 500psig) design cases, indicating that there is no performance loss. The shortfall in heat transfer surface area for the lower pressure natural gas feed case shown in table 2 is compensated by a slight increase in turbine inlet pressure to increase its refrigeration output as compared to the corresponding optimal design case in table 1. Such a small change in turbine inlet pressure will likely moderately increase the speed of the turbine and thus may remain within the turbine design capabilities. The added cost of increasing the pump pressure to achieve the turbine inlet pressure is almost non-existent. On the other hand, if design conditions occur such that an increase in turbine inlet pressure cannot be handled by the turbine design, only a modest loss of 0.5% of the liquid nitrogen flow would be required for low natural gas feed pressures (relative flow of 0.887, instead of 0.883 in table 2). This analysis shows that an efficient, fixed, or common heat exchanger design (without an undesirable overdesign) can handle the expected range of LNG applications with minimal impact on system performance. This is the necessary capability to make a single design system efficient for both design modes.

While the present invention has been described with reference to one or more preferred embodiments, it should be understood that various additions, modifications and omissions may be made without departing from the spirit and scope of the present invention as set forth in the appended claims.