Patent Application
20110297346
The disclosure relates generally to methods and systems for efficiently and effectively liquefying, transporting, and delivering liquefied gas to commercial markets from production locations. More particularly, the disclosed systems, apparatuses, and associated methods relate to recovering and storing the cold thermal energy from the regasification of liquefied gases for later use in a liquefaction process or apparatus utilizing a regenerative heat exchange apparatus.
This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Increasingly, the world's energy needs are being met by natural gas, which is a cleaner alternative to coal and other hydrocarbons. However, much of the world's natural gas is located in reservoirs that are far removed from existing infrastructure (e.g. pipelines). Such natural gas resources are known as “remote gas.” Some estimates place the amount of the world's natural gas resources considered to be “remote gas” at nearly 40 percent the total amount of natural gas in the ground. The remote location of the gas makes it highly energy inefficient and economically inefficient to recover and transport due to its very low energy to volume and energy to mass ratios. Liquefying the natural gas (LNG) is one common method of improving the transportation economics of delivering natural gas to consuming markets.
In remote gas commercialization based on LNG, energy is expended to liquefy natural gas at the production site and a comparable amount of thermal energy expended to convert the liquid back to gas for use at an import terminal. The cold thermal energy associated with vaporizing the liquid is not utilized. This constitutes a significant source of energy inefficiency in the remote gas commercialization chain.
Attempts to recover and re-use the cold energy associated with the re-gasification of LNG at the import terminal have evolved to using the cold energy to liquefy nitrogen, ship the liquid nitrogen (LN2) back to the export terminal for use as refrigerant in the LNG liquefaction process. Two types of approaches have been proposed in patents such as British Pat. No. 1,170,329 and British Pat. No. 2,333,148. In the first approach, typified by a disclosure in the '329 patent, up to the maximum amount of cold energy available is recovered from the LNG during the re-gasification process at the import terminal and used in a process to liquefy nitrogen which is shipped back to the export terminal in the same LNG ship without any modifications. The resulting liquid nitrogen shipped is typically about half the volume of the LNG (corresponding to about the same mass as the LNG). This appears to simplify the transportation segment of the chain but the reduction in the refrigeration required at the export terminal is not large and significant supplemental refrigeration is still needed to produce the LNG. Further, there are technical challenges associated with shipping partially-filled liquid tanks due to high sloshing loads in the containers encountered, for example, during a storm. Finally, there is substantial energy required to produce the high-purity nitrogen required for the process, typically in an Air Separation Unit (ASU).
In the second approach, disclosed in both the '329 and the '148 patents, enough liquid nitrogen (LN2) is shipped back to the export terminal to provide the total refrigeration required to liquefy the natural gas. Thus no supplemental refrigeration is needed at the export terminal. The liquid nitrogen required for this approach is substantial (about the same volume as the LNG which translates to almost twice the mass of the LNG). Consequently, large supplemental refrigeration is required at the import terminal beyond what is available from regasifying the LNG. Again, there is substantial energy required to produce the high-purity nitrogen required for the process, typically in an Air Separation Unit (ASU), in addition to the energy for the supplemental refrigeration required to liquefy the nitrogen. Further, structural changes to the LNG ship are needed to transport the increased mass. These proposed patented approaches have never been commercially implemented.
Proposals that have seen limited commercial applications include utilizing the cold energy for power generation at the import terminal, or to provide refrigeration for example for preserving food. However, these options are limited to niche applications and require specific synergies for them to be economically viable. Consequently, these proposals have not been widely implemented.
What is needed is a method and system to improve the thermal efficiency of the remote gas commercialization chain utilizing high heat capacity heat exchange.
One embodiment of the present invention discloses a heat transfer system. The system includes a regasification system at a first location configured to convert a first volume of liquefied gas (LG) contained at or below a liquefaction temperature into a first volume of gas at above the liquefaction temperature, the regasification system comprising a heat exchange apparatus. The heat exchange apparatus includes a regenerator matrix having a volume of high heat capacity materials configured to recover and store cold energy from the LG from the regasification system for subsequent use at a second location to provide at least a portion of a cold energy requirement for liquefaction of a second volume of gas into a second volume of LG.
Another embodiment of the present invention discloses a heat transfer system. The heat transfer system includes a liquefaction system at a first location configured to convert a first volume of gas at above a liquefaction temperature into a first volume of liquefied gas (LG) contained at or below the liquefaction temperature, the liquefaction system comprising a heat exchange apparatus. The heat exchange apparatus includes a regenerator matrix including a volume of high heat capacity materials configured to provide cold energy to the first volume of gas in the liquefaction system, wherein the cold energy is obtained from a regasification system at a second location configured to regasify a second volume of LG contained at liquefaction temperatures.
A third embodiment of the present invention discloses a heat transfer system. The heat transfer system includes a heat exchange apparatus. The heat exchange apparatus having a regenerator matrix including a volume of high heat capacity materials, wherein the regenerator matrix is configured to: a) recover and store cold energy from a volume of liquefied gas at or below a liquefaction temperature from a regasification system at a first location; and b) provide cold energy to a volume of gas at above the liquefaction temperature in a liquefaction system at a second location.
In a fourth embodiment of the presently disclosed concepts, a method of delivering liquefied natural gas (LNG) is provided. The method includes flowing LNG to a heat exchange apparatus from an LNG storage tank on an LNG carrier at an LNG gasification location; recovering cold energy from the LNG using the heat exchange apparatus having a regenerator matrix including a volume of high heat capacity materials to form at least partially vaporized natural gas; storing the cold energy in the high heat capacity materials for use at an LNG liquefaction location; and delivering the at least partially vaporized natural gas to a consuming market.
In a fifth embodiment of the presently disclosed concepts, a method of producing natural gas is provided. The method includes feeding a natural gas stream to a heat exchange apparatus on a liquefied natural gas (LNG) carrier from a producing location; and passing the natural gas stream through the heat exchange apparatus having a regenerator matrix including a volume of high heat capacity materials. Passing the natural gas through the heat exchange apparatus includes a) imparting cold energy from the high heat capacity materials to the natural gas to form at least partially liquefied natural gas; and b) storing heat energy in the high heat capacity materials for use at an LNG gasification location. The method further includes storing the at least partially liquefied natural gas on the LNG carrier.
In a sixth embodiment of the present disclosure, an alternative heat transfer system is provided. The system includes a regasification system at a first location configured to convert a first volume of liquefied gas (LG) contained at or below a liquefaction temperature into a first volume of gas at above the liquefaction temperature, the regasification system comprising a heat exchange apparatus. The heat exchange apparatus includes a shell and tube heat exchanger. The shell and tube heat exchanger includes a) a sealed tube bundle containing a volume of high heat capacity material; and b) the shell side is configured to receive the first volume of liquefied gas (LG) to provide the cold energy stored in the tube bundle, wherein the volume of high heat capacity material is configured to recover and store cold energy from the LG from the regasification system for subsequent use at a second location to provide at least a portion of a cold energy requirement for liquefaction of a second volume of gas into a second volume of LG.
In a seventh embodiment of the present disclosure, an alternative heat transfer system is provided. The system includes a liquefaction system at a first location configured to convert a first volume of gas at above a liquefaction temperature into a first volume of liquefied gas (LG) contained at or below the liquefaction temperature, the liquefaction system comprising a heat exchange apparatus. The heat exchange apparatus includes a shell and tube heat exchanger, comprising a) a sealed tube bundle containing a volume of high heat capacity material; and b) the shell side is configured to receive the first volume of liquefied gas (LG) to receive the cold energy to the volume of high heat capacity material in the sealed tube bundle, wherein the volume of high heat capacity material is configured to provide cold energy to the first volume of gas in the liquefaction system, wherein the cold energy is obtained from a regasification system at a second location configured to regasify a second volume of LG contained at liquefaction temperatures. In each of the sixth and seventh embodiments, the systems may include a phase-change material (PCM) configured to utilize at least the latent heat of vaporization and a non-condensible gas in the sealed tubes.
In an eighth embodiment of the present disclosure, a method of delivering liquefied natural gas (LNG) is disclosed. The method includes flowing LNG to a heat exchange apparatus from an LNG storage tank on an LNG carrier at an LNG gasification location; passing the LNG through the heat exchange apparatus having a shell and tube heat exchanger including sealed tubes containing a volume of high heat capacity material; recovering cold energy from the LNG utilizing the shell and tube heat exchanger to form at least partially vaporized natural gas; storing the cold energy in the high heat capacity materials for use at an LNG liquefaction location; and delivering the at least partially vaporized natural gas to a consuming market. The shell and tube heat exchanger may include a phase-change material (PCM) configured to utilize at least the latent heat of vaporization and a non-condensible gas in the sealed tubes.
In a ninth embodiment, a heat transfer system is provided. The system includes a regasification system at a first location configured to convert a first volume of liquefied gas (LG) contained at or below a liquefaction temperature into a first volume of gas at above the liquefaction temperature, the regasification system comprising a heat exchange apparatus. The heat exchange apparatus including a cross-flow heat exchanger, comprising: a) at least one plugged flow channel containing a volume of high heat capacity material; and b) at least one open flow channel configured to receive the first volume of liquefied gas (LG) to provide cold energy to the volume of high heat capacity material in the at least one plugged flow channel, wherein the volume of high heat capacity material is configured to recover and store cold energy from the LG from the regasification system for subsequent use at a second location to provide at least a portion of a cold energy requirement for liquefaction of a second volume of gas into a second volume of LG.
The foregoing and other advantages of the present techniques may become apparent upon reviewing the following detailed description and drawings in which:
In the following detailed description section, the specific embodiments of the present techniques are described in connection with preferred embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present techniques, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the invention is not limited to the specific embodiments described below, but rather, it includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.
The term “liquefaction temperature,” as used herein, means a temperature at which a gas is converted to a liquid. The liquefaction temperature of a gas will change with pressure, so a single gas may have more than one liquefaction temperature, depending on the pressure of the gas. Further, this term applies to mixtures of gases, such as, for example, air and natural gas. The composition of natural gas may vary by location or by the inclusion or exclusion of certain pre-treating process steps and the liquefaction temperature will vary somewhat with variations in the composition of such gases. The term is intended to include any and all such variations in pressure and temperature.
In one exemplary embodiment of the present invention, a heat transfer system is provided, which may include a regasification system for converting liquefied gas at a liquefaction temperature, such as, for example, liquefied natural gas (LNG), from a liquid to a vapor phase (e.g. natural gas) at above a liquefaction temperature for the gas. The system may further include a heat exchange apparatus having a regenerator matrix containing a volume of high heat capacity materials (a.k.a. thermal energy storage materials), which may be phase-change materials in some exemplary embodiments. The heat exchange apparatus may further be configured to recover and store the cold energy (e.g. refrigeration effect) from the cryogenically stored liquefied gas as the liquefied gas is vaporized. The regenerator matrix is configured to store the cold energy in the high heat capacity materials long enough to transport it to a second location to perform a liquefaction operation utilizing the cold energy for at least a portion of the cooling needed to liquefy gas from a vapor phase.
In an alternative exemplary embodiment of the present invention, a heat transfer system including a liquefaction system for converting a first volume of feed gas at above liquefaction temperature from a substantially gaseous phase to a substantially liquid phase (e.g. a first volume of liquefied gas) is provided. The liquefaction system further includes a heat exchange apparatus having a regenerator matrix including a volume of high heat capacity materials configured to provide cold energy to the first volume of gas in the liquefaction system, wherein the cold energy is obtained from a regasification system at a second location configured to re-gasify a second volume of liquefied gas contained at liquefaction temperatures.
In one exemplary embodiment, the re-gasification system and the liquefaction system may be integrated and utilize the same heat exchange apparatus. The high heat capacity materials may include phase change materials (PCMs) and may be configured in the regenerator matrix as micro-encapsulated spheroids, macro-encapsulated spheroids, micro-encapsulated sheets, macro-encapsulated sheets, macro-encapsulated honey-comb network, or a micro-encapsulated honey-comb network. The PCMs may be a series of phase-change materials (PCMs) stacked sequentially based on a phase transition temperature of the PCMs or may be a thermo-adjustable mixture, which allows the phase transition temperature to be tuned based on the composition of the mixture. The mixture may comprise at least two unique PCMs, wherein each PCM has a different phase transition temperature range. In this exemplary embodiment, an integrated production, transport, and re-gasification system (PTRS) is provided. One specific embodiment provides for the integration of the LNG production system, the LNG transport system, and the LNG regasification system into a single unit (LNG-PTRS) through the use of a heat exchange system. Such an integrated system may further utilize the liquefaction system to reliquefy boil-off gas during transit.
Additional embodiments include methods of re-gasifying and delivering natural gas to an import terminal as well as liquefying and producing natural gas at a production location utilizing embodiments of the systems disclosed herein.
Still further alternative embodiments may incorporate a shell and tube heat exchanger instead of the regenerator matrix, wherein the tubes may be filled with a high heat capacity material and a non-condensible gas. In particular, the high heat capacity material may be a phase change material (PCM) that takes advantage of the latent heat of vaporization for a liquefaction temperature of interest. A cross-flow heat exchanger with alternating flow channels having high heat capacity materials may also be used.
The disclosed embodiments also provide substantial advantages over building an LNG production facility on an offshore platform. For example, the disclosed systems and methods eliminate the need for several large LNG storage tanks on a platform; eliminate the technical challenges associated with cryogenic liquid transfer between an offshore platform and an LNG ship (only a gas connection is needed between the resource and the LNG ship); and eliminate the enormous space and weight requirements for an LNG production facility on an offshore platform.
The presently disclosed systems and methods also have several advantages over the prior art. The presently disclosed systems and methods do not require costly and energy intensive air separation units (ASU), as required by systems utilizing liquefied nitrogen to transfer cold energy, and since air is not used, there is no risk of forming a combustible mixture as there is with systems utilizing liquefied air. The presently disclosed systems and methods also eliminate the risks associated with shipping storage tanks partially filled with liquid, which places a carrier at risk due to sloshing loads on the storage tanks from the liquid.
Referring now to the figures,
In some exemplary embodiments of the regasification system 100, the liquefied gas is liquefied natural gas (LNG), but may alternatively be liquefied propane gas (LPG), liquefied carbon dioxide gas, liquefied nitrogen gas, liquefied air, liquefied oxygen, liquefied neon, liquefied hydrogen, or some combination thereof. The container 102 may be any type of container suitable for transporting liquefied gases, such as a spherical tank container, a membrane tank container, a corrugated tank container, a prismatic tank container, or other type of container. The line 104 may be any type of conduit or flow line suitable for delivering liquefied gases. The line 104 should be large enough to flow the liquefied gas at a rate sufficient to support efficient regasification operations. It is contemplated that the line 104 may include insulation, have a corrosion resistant coating, a low-friction loss coating, another performance-enhancing coating, and any combination thereof. The container 102 and the line 104 should be capable of operation at temperatures from at least about −253 degrees Celsius (° C.) to about 40° C. and have joints and other design features to permit the container 102 and the line 104 to cyclically contract and expand between these temperatures without failure for the life of the system 100. It is contemplated that a person of ordinary skill in the art has been provided with sufficient information to engineer the container 102 and line 104 in accordance with the present disclosure.
In some embodiments of the regasification system 100, the pump 106 may be a series of multiple pumps or one large pump. The pump 106 should be configured to handle liquefied gases at temperatures ranging from about −253° C. to about −60° C. or from about −196° C. to about −100° C. and should be capable of handling stress due to expansion and contraction cycles over a temperature range of about −253° C. to about 40° C. The pump 106 should further be capable of providing a sufficient flow rate of the liquefied gas through the system 100 for normal unloading and regasification operations. In some particular, exemplary embodiments, a reciprocating pump, a centrifugal pump, a cryogenic pump, or any combination of these types of pumps may be utilized in accordance with the present disclosure.
The line 108 may have many of the same features as line 104, however the liquefied gas flowing through line 108 is expected to have a somewhat higher temperature and pressure than the liquefied gas in line 104 because it passes through the pump 106.
The heat exchange apparatus (heat exchanger) 110 may include a regenerator matrix, a shell and tube arrangement, a plate-fin arrangement, or other configuration having high heat capacity materials configured to recover and store cold energy from the liquefied gas (LG) for subsequent use at a second location (e.g. a liquefaction location) to provide at least a portion of a cold energy requirement for liquefaction of a second volume of gas (e.g. a feed gas) into a second volume of LG. In some exemplary embodiments, the high heat capacity materials may be a series of phase-change materials (PCMs) stacked sequentially based on a phase transition temperature of the PCMs, may include a thermo-adjustable mixture of materials which allow the phase transition temperature to be tuned based on the composition of the mixture. The mixture may comprise at least two PCMs each having a different phase transition temperature, or may be a combination of these configurations.
The heat exchanger 110 may be a fixed bed regenerator, a compact regenerator, a micro-scale regenerator, or some combination of these. In particular embodiments, the heat exchanger 110 may include a regenerator matrix including one of micro-encapsulated spheres, macro-encapsulated spheroids, micro-encapsulated sheets, a micro-encapsulated honey-comb network, macro-encapsulated sheets, macro-encapsulated honeycomb network, or some combination of these.
Alternatively, the heat exchanger 110 may comprise a shell and tube arrangement having high heat capacity materials in the tubes configured to recover and store cold energy from the liquefied gas (LG) for subsequent use at a second location (e.g. a liquefaction location) to provide at least a portion of a cold energy requirement for liquefaction of a second volume of gas (e.g. a feed gas) into a second volume of LG. In the shell and tube example, the high heat capacity materials may be PCMs and include a thermo-adjustable mixture of materials which allow the phase transition temperature to be tuned based on the composition of the mixture. Additionally, the high heat capacity materials in this arrangement may include materials utilizing at least the latent heat associated with vapor-liquid phase transition—(latent heat of vaporization or condensation). Note, these materials may also utilize the liquid-solid phase transition similar to the PCM's discussed above.
The regasification system 100 further includes a line 112 from the heat exchanger 110 to one of a vaporized gas delivery or offloading system, or may optionally include a supplemental heat exchange system 114 with optional supporting equipment 114a such as pumps, condensers, and boilers to further vaporize the gas after it passes through the heat exchanger 110. The line 112 may be configured to carry vaporized gas after it passes through the heat exchanger 110. As such, it is expected that the gas will be at a temperature of from about −10° C. to about 80° C., or from about 0° C. to about 60° C., depending on the operation of the heat exchanger 110, the ambient temperature, implementation of an optional heat exchange system 114, the initial temperature of the liquefied gas (LG), and other factors. As such, line 112 may have a larger diameter than lines 108 and 104, may not include insulation and may have a composition with less nickel as lines 104 and 108 because line 112 may not operate at or below cryogenic liquefaction temperatures.
The optional heat exchange system 114 may be an electrical heater, may burn some of the vaporized gas for heat, may use ambient air or water, may utilize concentrated solar energy, or impart heat to the at least partially vaporized gaseous stream in line 112 by some other means. In some embodiments, power for the optional heat exchange system 114 may be generated by a co-located power plant, such as on a ship, on-shore, or off-shore structure having the regasification system 100. A person of ordinary skill in the art will understand the engineering variables to consider in determining the placement, capacity, efficiency, and type of heat exchanger, if such an apparatus is utilized.
The line 202 for carrying the gaseous feed may be similar to the line 112, as it may be configured to carry a substantially gaseous feed, such as natural gas from a production location at substantially atmospheric or slightly higher temperatures and above ambient pressure. The line 202 may not require insulation and may have a larger diameter than some of the other lines, but may be sized to handle sufficient amounts of gas to supply the system 200. The gas may be a natural gas (NG), but may alternatively be propane gas (PG), carbon dioxide gas, nitrogen gas, air, oxygen, neon, hydrogen, or some combination thereof.
The heat exchange apparatus 110 may be the same or similar to the heat exchange apparatus (heat exchanger) 110 of the regasification system 100. In one embodiment, the heat exchanger 110 includes high heat capacity materials configured to provide cold energy to the feed gas in the liquefaction system 200. The cold energy is obtained from a regasification system (e.g., regasification system 100) at a second location (e.g. a delivery or offloading location) configured to regasify another volume of liquefied gas contained at liquefaction temperatures. In some exemplary embodiments, the high heat capacity materials may be a series of phase-change materials (PCMs) stacked sequentially based on a phase transition temperature of the PCMs, may include a thermo-adjustable mixture of materials which allow the phase transition temperature to be tuned based on the composition of the mixture. The mixture may comprise at least two PCMs each having a different phase transition temperature, or may be a combination of these configurations.
The heat exchanger 110 may be a fixed bed regenerator, a compact regenerator, a micro-scale regenerator, a shell and tube heat exchanger, or some combination of these. In particular embodiments, the heat exchanger may include a regenerator matrix, which may be comprised of micro-encapsulated spheres, macro-encapsulated spheroids, micro-encapsulated sheets, a micro-encapsulated honey-comb network, macro-encapsulated sheets, macro-encapsulated honey-comb network, or some combination of these. Alternatively, the high heat capacity materials may be enclosed in sealed tubes in a shell and tube heat exchanger arrangement, or a cross-flow heat exchanger arrangement having alternating flow channels with high heat capacity materials therein.
The line 204 is configured to carry gas that may be at least partially liquefied and at or below liquefaction temperatures and at high pressures. Line 204 may be the same or similar to line 108. Lines 208 and 212 are optional and may be the same or similar to line 204, line 108, and line 104, which are configured to safely and efficiently transport a substantially liquefied gas at liquefaction temperatures and above ambient pressures.
The system 200 may further include optional supplemental cooling systems 206 and/or 214. Supplemental cooler 206 may include additional equipment 206a such as pumps, chillers, and/or expanders and may be utilized for sub-cooling the gaseous stream if the heat exchanger 110 fails to sufficiently liquefy the gas for transport and supplemental cooler 214 may include additional equipment 214a such as pumps, chillers, and/or expanders and may be utilized for pre-cooling the gaseous stream before entering the heat exchanger 110 to ensure sufficient liquefaction of the gas for transport. The cooling may be accomplished by utilizing any reasonably applicable heat exchanger such as a co-current or counter-current heat exchanger, a finned heat exchanger, direct contact heat exchanger, another type of heat exchanger, or some combination of these. The refrigerant may be obtained from cold sea water, a mixed refrigerant system, an HPXP system, or some combination of these. Power for the system may be generated by a co-located power plant, such as on a ship, on-shore, or off-shore structure, by a solar array, by burning a fuel gas, or some combination of these. A person of ordinary skill in the art will understand the engineering variables to consider in determining the placement, capacity, efficiency, and type of optional supplemental cooler to install and utilize.
The optional expander 210 may be configured to provide supplemental cooling and liquefaction of the cooled stream prior to storage in the container 102. The container 102 is the same or similar to the container 102 in the regasification system 100. The expander 210 may be capable of cryogenic operation. The expander may be a dual expander, a hydraulic turbine, a turbo expander, a throttling valve, or some combination of these. Depending on the ambient conditions, composition of the feed gas, and other factors, the expander 210 may not be needed and may be bypassed.
The platform 302 may be a carrier, such as an LNG carrier, or a barge or other facility. In some embodiments, the platform 302 will be capable of moving from a regasification location to a liquefaction location which may be separated by a distance of from 100 miles to about 15,000 miles or from about 1,000 miles to about 10,000 miles, or from about 3,000 miles to about 6,000 miles. The optional equipment 310, 214, and 114 may be on the platform 302 or located at a loading or unloading location.
The pretreatment unit 306 may be located at a gas production location or connected by pipeline to such a location. The pretreatment unit 306 may be configured depending on the quantity and quality of the gas for treating, but may include a liquids separation portion or water-knockout portion to remove any hydrocarbon or aqueous liquids from the feed gas stream. The unit 306 may further include an acid gas removal or separation unit to remove carbon dioxide, hydrogen sulfide, and other unwanted gases, depending on the composition of the feed gas. Such a separation unit may include an amine unit, a membrane separation unit, an adsorption unit, or similar unit, or some combination thereof. A person of ordinary skill in the art will understand the engineering variables to consider in selecting the type of unit, placement, capacity, efficiency, and power requirements and utilize for the pretreatment unit 306.
The pipeline 312 may be operably connected to gas handling system, a gas storage facility, a gas distribution network, or any combination thereof (not shown). In some embodiments, the vaporized gas product is delivered to a gas consuming market via the available gas receiving and handling system at that particular location. The facilities may vary significantly from one location to another. Exemplary gas consuming markets include the United States, Japan, China, Italy, Great Britain, and others. Delivery locations may be located offshore or onshore. The system 300 may be configured to be interoperable with any or all of these gas delivery locations.
The heat exchange apparatus 110 is configured to recover and store cold energy from a volume of liquefied gas at liquefaction temperatures from a regasification system 100 at a first location; and provide cold energy to a volume of gas at above liquefaction temperatures in a liquefaction system 200 at a second location.
The integrated system 300 may be utilized with an integrated production, transport, and re-gasification system (PTRS). The production system may be liquefaction system 200, the transport may be carrier or barge 302, and the re-gasification system may be re-gasification system 100. In particular, such an integrated unit may be utilized to deliver liquefied natural gas (LNG) to commercial markets from remote production location. Such an integrated LNG unit may be referred to as an LNG-PTRS. In one exemplary advantageous embodiment, the PTRS may further utilize the liquefaction system to reliquefy boil-off gas during transit. For example, as the carrier 302 transports the liquefied gas from the producing location to the delivery location some of the liquefied gas in the container 102 may boil off or vaporize. The stored cold energy in the heat exchange apparatus 110 may be utilized to reliquefy this boil-off gas and return it to the container 102 in liquid form.
In another exemplary embodiment, any of the systems 100, 200, or 300 may utilize an instrumentation and control system (not shown) for safely and efficiently operating the systems 100, 200, or 300. For example, various sensors at a plurality of locations may be utilized to measure temperature and pressure of the gas in liquid or vapor form. Input from such sensors may be utilized to determine the amount of supplemental heat that may be added via the supplemental heat exchanger 114, the amount of supplemental cooling that may be added via the supplemental cooler 214 or 206, and the expander 210. Such a control system may also control the flow rate of the liquefied gas via the pump 106 or the reliquefaction of boil-off gas. The control system may be programmed to operate automatically via a programmable computer system having software instructions, may include manual inputs, a graphical user interface (GUI), and may include manual overrides, such as valves or switches in a central location or throughout the system 100, 200, or 300 at particular locations. It is contemplated that a person of ordinary skill in the art has been provided with sufficient information to engineer the control system in accordance with the present disclosure.
In some embodiments of the disclosure, the LNG storage tank may be container 102 and the LNG carrier may be an LNG-PTRS, which may be represented by platform 302. In some embodiments of the invention, the heat exchange apparatus is the heat exchange apparatus 110. The heat exchanger 110 may be included in the regasification system 100 or the integrated system 300. In addition, the liquefaction location may include a liquefaction system 200. The delivering step 410 may include the utilization of pipeline 312.
Referring to
In some embodiments of the disclosure, natural gas may be fed via line 202 in the liquefaction system 200 or via line 304 in the integrated system 300. In some embodiments of the invention, the heat exchange apparatus is the heat exchange apparatus 110. The heat exchanger 110 may be included in the liquefaction system 200 or the integrated system 300. In addition, the gasification location may include a regasification system 100. The storing step 460 may include the utilization of container 102.
Referring now to
Valves 504a and 504d are shown in the open position to permit fluid flow through lines 202 and 204, while valves 504b and 504c are shown in the closed position to prevent fluid flow in the opposing direction via lines 108 and 112. In one alternative embodiment, valve 504a may be open while valve 504d is closed. For example, when the initial feed gas stream is fed to the heat exchanger 110 via line 202, valve 504d may remain in the closed position until the feed gas (which is now much colder and may be at least partially liquefied) reaches valve 504d and some pressure is built up. In other words, the valves 504a and 504d may be operated based on the pressure requirements of the liquefaction system 200, which may depend on the feed gas composition, initial temperature, flow rate, flow volume, and other factors. Alternatively, as the process comes to an end, valve 504a may be closed while 504d remains open.
In some exemplary embodiments of the disclosed systems 500 and 520, the valves 504a-504d may all be of the same or similar design, but alternatively, the valves 504a-504d may be independently selected based on expected operating conditions. For example, it is expected that valve 504a may be configured to handle primarily gaseous feed streams at relatively high temperatures (e.g. from about 0° C. to about 120° C.) and relatively high pressures (e.g. from about 1 atmosphere (atm) to about 20 atm), depending on the feed gas source. However, valve 504d may be expected to handle gas and liquid (multiphase) streams at significantly lower temperatures (e.g. from about −200° C. to about −20° C.). As such, valve 504d may have different sizing, material selection, and operating parameters than valve 504a. Similarly, valve 504b is expected to handle fluid streams similar to the streams handled by valve 504a, but may require operation at a slightly lower temperature and pressure and valve 504c may be required to handle fluid streams similar to that of valve 504d. In one exemplary embodiment, valves 504a and 504b may be the same valve, capable of operation in both directions (liquefaction 500 and re-gasification 520) and valves 504c and 504d may be the same valve.
The high heat capacity materials (also called thermal energy storage (TES) materials) may be any one or a combination of phase-change materials (PCMs), molecular alloys, a single composite material configured to span a temperature range of interest. In one embodiment, the material of choice includes a high enthalpy change in the appropriate temperature range (e.g. about 20K (−253° C.) to about 273K (0° C.) or about 77K (−196° C.) to about 213K (−60° C.)); phase change temperature in the appropriate regime of interest; and high mass density. In addition, the material selected should have low density variation accompanying the thermal energy changes, high chemical stability associated with the thermal cycling, and compatibility between the active phase change material (PCM) and any containment material.
Referring now to
For example, in a PCM-based solution, the specific heat capacity of each material 602, 606, 608, and 610 in the series of materials may also be used to augment the thermal energy storage capability of the PCM near its phase transition temperature. Thus, the thermal energy storage capacity of the target material may be optimized for both the heat of fusion and the integrated value of the specific heat capacity over the appropriate temperature interval. There may be flexibility in the material, geometry and type of encapsulation technology used. The TES system may further be packaged into a heat exchanger, such as the regenerator matrix 601 in the heat exchange apparatus 110. As such, the form of encapsulation may guide the development of the heat exchanger configuration. Additionally, the encapsulation technology may recognize the need for long term stable behavior of the TES system (e.g., compatibility between the different materials, minimizing the potential for adverse impacts of thermal cycling, abrasion, corrosion etc.). In some embodiments, the material may have a significantly high density (>1000 kg/m3).
In one alternative embodiment, the high heat capacity material (or TES) may comprise a material analogous to phase change materials (PCMs) made up of molecular alloys (sometimes called MAPCM) which have the advantage of being thermo-adjustable, allowing the flexibility to tune the phase transition temperature through their composition. For example, one configuration may include a pair of materials, each with high heat of fusion that may be mixed in different proportions to provide mixtures with phase transition temperatures in the range of about 77 K to about 273 K, or from about 100 K to about 250 K or from about 150 K to about 200 K. Such a mixture may be encapsulated to preserve the mixture composition and thereby ensure a fixed phase transition temperature. However, individual materials/compounds with high heat of fusion and/or high specific heat capacity and with phase transition temperature in the desired ranges may be provided.
Another variation of the disclosed embodiments includes the use of a single composite material (SCM) to span the temperature range of interest. In such an arrangement, the thermal energy storage capacity for the composite material is the sum of the solid phase specific heat capacity, the latent heat (of fusion) and the liquid phase specific heat capacity. Graphs 700, 750, and 760 showing the effect on the thermal energy consumption using such a material are provided at
Yet another variation of the disclosed embodiments includes the use of a single composite material (SCM) to span the temperature range of interest but in an arrangement with an even higher thermal energy storage capacity. The higher thermal energy storage capacity comes from utilizing the large latent heat associated with vapor-liquid phase transition—latent heat of vaporization (condensation). A graph 760 showing the effect on the thermal energy consumption using such a material is provided as
In addition to the selection and arrangement of the materials for the regenerator matrix 601, there should also be some consideration to the encapsulation of such materials to control the mixing of materials with each other and with the fluid streams 202 and 108. In one exemplary embodiment, the PCM material may be hermetically sealed to isolate it from the process stream 202 or 108. This may be accomplished by encapsulating the PCM in a form and geometry such that, when integrated into a heat exchanger, improves heat transfer effectiveness as well as cost effectiveness. One exemplary encapsulation approach involves micro-encapsulation of the PCM to produce geometries, such as spheroids, that may be incorporated into the regenerator matrix 601 Beneficially, the regenerator matrix has a high surface area for a given volume, which provides a small exchanger volume for a given energy density, effectiveness and pressure drop.
In another exemplary embodiment, the PCM may be macro-encapsulated. This may include creating spheroids or sheets of encapsulated material that may be formed into a heat exchanger. Heat transfer enhancement techniques, such as fins, may be incorporated into the chosen configuration to increase the heat transfer area and hence the heat exchange effectiveness.
Other heat transfer enhancement techniques may be exploited in the manufacture of the PCM. For example, composites may be developed based on the PCM to advantageously improve the latent heat of fusion of the packaged PCM. This is analogous to composites that have been developed based on paraffins such as styrene-butadiene-styrene triblock copolymer. Further, a small fraction of other materials such as carbon fibers may be dispersed in the PCM to enhance the thermal conductivity of the TES. For this application, a high thermal conductivity is not a primary requirement, unlike the typical Thermal Energy Storage system (where there may be sufficient energy stored but insufficient capacity to dispose of the energy quickly enough): there is enough flexibility in this application, to design a system optimized around the thermal conductivity value of the PCM.
Although optimal solutions and selection of high heat capacity materials will depend on the composition of gas, flow rate, temperature range, and other factors, the following is one exemplary combination of materials arranged as a series of phase-change materials (PCMs) stacked sequentially in a regenerator matrix 601 based on a phase transition temperature of the PCMs. In this exemplary embodiment, six materials are used with dividing walls between them. Table 1 below shows the list of materials with each material's heat of fusion (hfs), temperature of fusion (Tfs), specific heat capacity (Cp), mass and change in enthalpy (dH).
In the example set forth in Table 1, the temperature increase in each PCM is limited to the phase transition temperature of the adjacent PCM for illustrative purposes only. The total mass of the TES material required may be reduced to 1.21 from 1.81 by allowing each PCM to warm up to the highest process temperature. Further, the required mass may be reduced to about 0.65 by using only the exemplary high heat capacity material Mix2 to span the whole temperature range.
In another example, an ammonia-water binary system (mixture) may be utilized with the shell and tube arrangement 620, 640, or 660. Such an exemplary TES material would be expected to have an hfs of 146 BTU/lbm a Tfs of −103° F., a hfg of 589 BTU/lbm, a Tfg of −28° F. and a Cp of 1.123 BTU/lbm-F and a mass ratio of about 0.27 lbm/lbm.
While the present techniques of the invention may be susceptible to various modifications and alternative forms, the exemplary embodiments discussed above have been shown only by way of example. However, it should again be understood that the invention is not intended to be limited to the particular embodiments disclosed herein. Indeed, the present techniques of the invention include all alternatives, modifications, and equivalents falling within the true spirit and scope of the invention as defined by the following appended claims.
This application claims the benefit of U.S. Provisional Application Nos. 61/151,765 filed Feb. 11, 2009 and 61/161,683 filed Mar. 19, 2009.
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/US09/68083 | 12/15/2009 | WO | 00 | 7/22/2011 |
| Number | Date | Country | |
|---|---|---|---|
| 61161683 | Mar 2009 | US | |
| 61151765 | Feb 2009 | US |
