Patent Application
20050126220
The present invention relates generally to the storage and distribution of liquefied natural gas (LNG) and vaporization of the LNG into a natural gas product. More particularly, the present invention relates to systems and methods to modify the gross heating value (GHV) of the LNG so as to produce, upon vaporization, a natural gas product that meets pipeline or commercial specifications, or is otherwise interchangeable with domestically produced natural gas.
Presently, the use of imported LNG is becoming increasingly important for many countries as the demand for natural gas continues to increase, while domestic production, particularly in the United States and Canada, has been on decline. The imported LNG can make up for a shortfall in domestic production and/or otherwise meet market demand during peak periods, such as during the winter heating season. Such LNG is produced by any of a number of liquefaction methods known in the art, and typically is produced at and imported from a number of remote areas around the world having vast natural gas supply sources, such as the Middle East, West Africa, Trinidad, Australia, and Southeast Asia. After being shipped from such remote locations by specially designed cryogenic tankers, the LNG is typically stored at cryogenic temperatures, until just prior to use, at various locations around the world near locations of high natural gas demand.
It is known that LNG produced from such remote locations in many instances when vaporized does not meet pipeline or other commercial specifications. The resulting natural gas may have an unacceptably high heating value, typically referred to as gross heating value or “GHV”. Various methods have been proposed or used to adjust the GHV of LNG to produce natural gas that will meet pipeline specifications, as is discussed by D. Rogers in “Gas Interchangeability and Its Effects On U.S. Import Plans”, Pipeline & Gas Journal, August 2003 at pages 19-28 and “Long-term Solution Needed To Embrace Imports With Pipeline Gas”, Pipeline & Gas Journal, September 2003, at pages 14-22. For example, such “GHV reduction” or “BTU stabilization” is said by Rogers to be conducted by one or more of the following methods: 1) blending of a high GHV LNG liquid with another LNG liquid having a lower GHV value, such as in the storage tank used to hold LNG prior to sendout; 2) blending of natural gas obtained from a high GHV LNG after vaporization with domestically produced natural gas having a relatively low GHV; 3) injection of an inert gas, such as air or nitrogen, into vaporized LNG prior to its introduction into a pipeline; and 4) stripping heavier hydrocarbons such as ethane, propane, and butane (also known as natural gas liquids or NGLs) from the LNG prior to sendout.
A particular method for NGL removal to lower the GHV of LNG is disclosed by U.S. Pat. No. 6,564,579.
The methods mentioned above generally require significant additional capital costs or have operational problems associated with them. For example, option 1 advanced by Rogers is not very practical as it would either require maintaining a separate inventory of LNG liquids with suitable GHV values, or very careful management of shipments of specific LNG liquids with suitable GHV values for blending with the remaining LNG contained within existing storage tanks. Option 3 would require expensive equipment to conduct the injection into the vaporized LNG, including compressors for raising the pressure up to pipeline pressure, typically as high as 100 bar. Option 4 advanced by Rogers, and the method disclosed in U.S. Pat. No. 6,564,579, would require expensive equipment to remove the desired amount of NGLs.
Conversely, in other parts of the world, such as Japan, there is a desire to increase the GHV of LNG, particularly for LNG having a relatively low GHV produced from sources of natural gas having lower levels of NGLs therein. The GHV can be increased by injection of NGLs or other combustible hydrocarbon materials, such as dimethyl ether, into the LNG such that upon vaporization the resulting natural gas product has an increased GHV.
The LNG is typically stored at low pressure, in liquid form, and at cryogenic temperatures at an import terminal. The LNG is usually pumped to a pressure that is slightly above the pressure of the natural gas distribution pipeline. The high-pressure liquid is then vaporized and sent to the distribution pipeline. The pumping operation typically involves a set of low-pressure pumps located in a storage tank or container connected in series to a set of high-pressure pumps located outside the storage tank.
In many instances in the past, LNG has been vaporized by simply burning a portion of the vaporized LNG to produce the heat to warm up and vaporize the remainder of the LNG and produce natural gas. Various heat exchange systems have been used for this purpose.
As is well known, heat input into the LNG storage tank gradually generates boil-off vapor during storage. Additional vapor generation may occur during filling of the storage container. Vapors may also be obtained from an outside source such as a ship. Ideally, the above-described boil-off vapors are included with the vaporized natural gas sendout into the distribution pipeline. Compressors may be used to boost these vapors to the high operating pressure of the pipeline, which can be as high as 100 bar. However, compressing the vapor to these high pressures requires considerable energy and expensive compressors and related equipment.
U.S. Pat. No. 6,470,706 discloses a system and related apparatus that utilizes cold LNG sendout to condense such boil-off vapors at a low interstage pressure. The teachings of U.S. Pat. No. 6,470,706 are incorporated herein by reference in their entirety. The vapor condensate combines with the liquid sendout and becomes a single phase flow into the high pressure pumps. The combined stream then flows to the vaporizers from the high-pressure pumps. Compressing the boil-off vapor stream to the distribution pipeline pressures requires considerably more energy than boosting the boil-off vapor condensate to the high pressure with a liquid pump.
Other LNG import terminals use systems similar to U.S. Pat. No. 6,470,706 that condense boil-off vapor at low pressure and pump the resulting condensate with the liquid LNG stream flowing to the vaporizer.
It would be desirable to develop a method and system for GHV reduction or BTU stabilization which is more efficient at adjusting the GHV of LNG so that upon vaporization, the resulting natural gas product is interchangeable with domestically produced natural gas or otherwise able to meet set commercial and/or pipeline specifications. It would also be desirable to develop methods and systems that may accomplish the foregoing objectives by relatively simple and low cost modifications to existing systems for vaporization of LNG.
In one aspect, the invention is directed to a method for adjusting the GHV of a liquefied natural gas comprising mixing a condensable gas with the liquefied natural gas, the amount of the liquefied natural gas being sufficient to condense at least a portion of the condensable gas and thereby produce a blended condensate.
In embodiments, the invention also is directed to a method for adjusting the GHV of a liquefied natural gas that comprises the following steps:
In another aspect, the invention is directed a method for vaporizing a liquefied natural gas having an initial GHV to obtain a natural gas product having a final GHV compatible with pipeline or commercial requirements. The method comprises the steps of:
In embodiments, the invention relates to a method for vaporizing a liquefied natural gas having an initial GHV to obtain a natural gas product having a final GHV that meets commercial specifications or is otherwise suitable for transport in a pipeline. The method comprises:
In other embodiments, the invention is more particularly directed to a method for vaporizing a liquefied natural gas having an initial GHV to obtain a natural gas product having a final GHV within a commercial specification or suitable for transport in a pipeline. The method comprises:
In further embodiments, the invention is directed to a method for vaporizing a liquefied natural gas having an initial GHV to obtain a natural gas product having a final GHV within a commercial specification or suitable for transport in a pipeline, the method comprising:
In another aspect, the invention relates to a system for adjusting the GHV of a liquefied natural gas. The system comprises a condenser vessel that comprises an inlet for a stream of the liquefied natural gas, an inlet for a stream of a condensable gas, an inlet for a stream of a boil-off vapor obtained by vaporization of the liquefied natural gas, an internal structural member providing a surface area for contact of the stream of the liquefied natural gas with the streams of the condensable gas and the boil-off vapor such that the condensable gas and boil-off vapor condense on contact and mixing with the liquefied natural gas stream to form a blended condensate product, and an outlet for the blended condensate product.
In other embodiments, the invention relates to a system for adjusting the GHV of a liquefied natural gas. The system comprises:
In further embodiments, the invention is directed to a system for vaporizing a liquefied natural gas comprising:
An important feature of the invention is that condensable gases, such as air, nitrogen, and even NGLs and other combustible hydrocarbons, such as dimethyl ether (depending upon the desired change in GHV or other natural gas specification), can be condensed into LNG by using cold LNG sendout as a condensing fluid. The type and amount of condensable gas employed is selected such that the resulting combined condensate will have a GHV value or other natural gas specification compatible with the pipeline or commercial use contemplated for the natural gas product upon vaporization of the combined condensate.
Other features and advantages are inherent in the methods and systems disclosed herein, or will become apparent to those skilled in the art from reading the following detailed description and its accompanying drawings.
In the description of the Figures, the same numbers will be used to refer to the same or similar components. Further, not all heat exchangers, pumps, valves, and the like, necessary to achieve the accomplishment of the process, as known to those skilled in the art, have been shown for simplicity.
Referring now to
As mentioned above, such LNG generally has a GHV which is higher than domestically produced natural gas present in pipelines or otherwise used commercially; typically the LNG imported from most natural gas producing areas has a GHV of greater than 1065 BTU/ft3, and generally from 1070 BTU/ft3 to 1200 BTU/ft3, and more specifically from 1080 BTU/ft3 to 1150 BTU/ft3.
As shown, in-tank, low-pressure pumps 14 are used to pump the LNG from tank 12 through a line 16, which LNG is typically stored at a temperature of about −255° F. (−159.4° C.) to about −265° F. (−165° C.) and a pressure of about 2 to 5 psig (0.138 to 0.345 bar). Pump 14 typically pumps the LNG through line 16 at a pressure from 35 psig (2.4 bar) to 200 psig (13.8 bar), preferably from about 50 psig (3.4 bar) to about 150 psig (10.4 bar), and at substantially the temperature at which the LNG is stored in tank 12.
The LNG as delivered inevitably is subject to some gas vapor loss (collectively boil-off vapor as mentioned previously) and is conveyed from tank 12 as shown through a line 20. This boil-off vapor directed via line 20 is typically recompressed in a compressor 24 driven by a power source, not shown. The power source may be a gas turbine, a gas engine, an engine, a steam turbine, an electric motor or the like. As shown, the compressed boil-off vapor is passed through a line 26 to a condenser vessel 30 where it enters the vessel at inlet 28. The boil-off vapor is condensed, as shown, by passing a quantity of cold LNG from tank 12 via line 16 and a line 19 into a condenser vessel 30 where the boil-off vapor, which is now at an increased pressure, is contacted in a contact area 32 of condenser vessel 30 with the cold LNG from line 19. Upon contact and mixing with the cold LNG stream, the boil-off vapor condenses and is combined with the LNG stream to desirably produce a substantially liquid LNG stream that may be recovered through a line 44. A line 17 is used to direct a portion of the cold LNG from line 16 directly to high-pressure pump 46 (described hereinbelow) and thereby bypass the condenser vessel 30. The amount of cold LNG conveyed by line 17 will depend on the amount of natural gas product to be produced in vaporizer 50 (as needed by local market demand) and also the amount of cold LNG conveyed by lines 18 and 19 as necessary to condense the boil-off gas and condensable gas in condenser vessel 30.
To adjust the GHV of the LNG, a source of a condensable gas (which may have no GHV or a different GHV) is provided via line 36, which for reduction of GHV is desirably air or nitrogen (molecular nitrogen or N2) gas. Preferably, the condensable gas is nitrogen gas, as this gas is generally inert and does not contribute toward corrosion of the contact vessel 30 or any related downstream equipment. In the event that an increase in GHV is desired, the condensable gas may be a stream with a higher GHV value relative to the LNG employed, such as a relatively NGL rich hydrocarbon stream with a higher carbon content of C2+, such as ethane, propane, and butane, or other combustible hydrocarbon such as dimethyl ether. The amount of condensable gas employed will depend on the specific LNG and condensable gas employed, and also the desired GHV value as a result of condensing the condensable gas into the LNG. In preferred embodiments of those embodiments which employ nitrogen gas as a condensable gas, the nitrogen is employed in an amount such that the total content of inerts (nitrogen and carbon dioxide) is about 4 mol % or less due to pipeline specifications. The condensable gas is supplied at a pressure generally slightly above the operating pressure of the condenser vessel 30.
The nitrogen gas employed can be from any source known in the art, including but not limited to, that obtained by separation of nitrogen from air according to well-known technology. Alternatively, the nitrogen can be generated and separated from air using one or more membrane separator cells, also according to well-known, commercially available technology. If nitrogen gas is not generated on or adjacent to the site where the instant method is being practiced, the nitrogen gas may be supplied from an external source and stored in containers, such as one or more storage tanks, until used according to the present method.
In the embodiment shown in
Condenser vessel 30 may be any vessel known in the art for condensing boil-off vapor from LNG storage tanks and vessels, as mentioned in U.S. Pat. Nos. 6,470,706 B1 and 6,564,579 B1, the teachings of which are hereby incorporated by reference in their entirety. In particular, the condenser vessel and related apparatus described in U.S. Pat. No. 6,470,706 are preferred for use in the practice of the present invention. The condenser vessel 30 generally has internal members, such as a plurality of packing elements, such as 2-inch (5.1 cm) Pall rings, disposed within the vessel to provide a contact area 32 which has an enhanced surface area for contact of LNG with both boil-off gas and the condensing gas. The heat and mass transfer for vapor/gas condensing in the contact area 32 can also be enhanced by any of the various alternative means well known in the art for gas/liquid contact in a column, such as by structured packing, tray columns and spray elements. After conditioning of the condensing gas in mixing device 40, the condensing gas is conveyed by a line 41 to the condenser vessel 30, wherein it is introduced via inlet 42. Preferably, the inlet 42 is at or below the contact area 32. Upon contact and mixing with the cold LNG introduced into the condenser vessel, the condensing gas also condenses with the boil-off vapor and forms a blended condensate which is then conveyed by a line 44 to high-pressure pump 46.
It is possible in some embodiments to omit condenser vessel 30 such that the condensable gas is mixed with a stream of cold LNG, and thereby condensed upon contact and mixing therewith, within mixing device 40, and preferably a static, in-line mixer is used for mixing device 40 as previously described. In such embodiments, the hydraulic conditions should be sufficient that the resulting mixed, condensed stream is substantially in the liquid phase and of sufficient volume, i.e. surge, prior to being introduced to high-pressure pump 46 described hereinafter so that two-phase flow into said pump is avoided or minimized.
The condenser vessel 30 is typically operated at a pressure of from 35 psig (2.4 bar) to 200 psig (13.8 bar), and preferably 50 psig (3.4 bar) to 150 psig (10.3 bar), and a temperature of from −265° F. (−165° C.) to −200° F. (−128.9° C.), and preferably from −265° F. (−165° C.) to −260° F. (−162.2° C.).
High-pressure pump 46 receives cold LNG via line 17 and the blended condensate via line 44 and thereby increases the pressure thereof; typically, high pressure pump 46 discharges the resulting LNG mixture into a line 47 at a pressure suitable for delivery to a pipeline. Such pipeline pressures are typically from about 800 psig (55.2 bar) to about 1200 psig (82.7 bar) and can be up to 1450 psig (100 bar), although these specifications may vary from one pipeline to another. The LNG mixture in line 47 is passed to the inlet 48 of a vaporizer 50 or other heat exchanger well known in the art for vaporization of LNG. A natural gas product exits the vaporizer 50 at outlet 52 suitable for introduction into an existing natural gas transmission pipeline or system or other commercial use. Typically the temperature of the natural gas exiting from outlet 52 is about 30° F. (1° C.) to 50° F. (10° C.), but this may also vary.
In terms of GHV, the LNG mixture in line 47 will in some embodiments result in a natural gas product upon vaporization of 1065 BTU/ft3 or less, and for those embodiments it is preferably from 1020 BTU/ft3 to 1065 BTU/ft3.
Vaporizer 50 may be any type known in the art for vaporizing a LNG stream, such as a shell and tube heat exchanger, submerged combustion vaporizer, or open rack vaporizer. For example, water or air may be used as a heat exchange media, or the heat exchanger may be a fired unit. Such variations are well known to those skilled in the art. It is preferred in practicing the invention to use water, or a mixture of water and other heat exchange fluid, such as ethylene glycol, as the heat exchange medium in vaporizer 50. In
Referring now to
After pre-cooling, the air feed is conveyed by a line 88 to heat exchanger 90 wherein the air is further cooled to a temperature of from −100° F. (−73.3° C.) to −250° F. (−156.7° C.) by heat exchange with cold process streams provided by lines 96 and 94 as described hereinafter. Heat exchanger 90 is typically a multi-pass, plate-fin heat exchanger of the type well-known to those skilled in the art. The cooled air stream is then conveyed by line 92 to turboexpander 102, where the cooled air stream is expanded in the turboexpander 102 to provide a cooled air stream at a temperature of from −260° F. (−162.2° C.) to −300° F. (−184.4° C.) which is conveyed via line 104 to distillation column 110.
In distillation column 110, the condensed air stream is separated into streams of relatively pure nitrogen and oxygen, which are recovered from distillation column 110 by lines 96 and 94 respectively. A reboiler is used in conducting the distillation as known to those skilled in the art, and is not shown for simplicity. Distillation column 110 employs well-known air separation technology for separation of the air into the respective streams of nitrogen and oxygen. The stream of nitrogen is conveyed by line 96 to heat exchanger 90, wherein it is used in exchange relationship to cool the air feed introduced into heat exchanger 90 by line 88. The nitrogen stream is then conveyed by line 98 to a compressor 112, that is driven by work derived from expansion of air in turboexpander 102 that is transferred to compressor 112 via shaft 114. After initial compression in compressor 112, the nitrogen stream is then conveyed by line 115 to compressor 120, wherein it is further compressed to a pressure of from 50 psig (3.4 bar) to 150 psig (10.3 bar) suitable for being used in condenser vessel 30 of
Having thus described the invention by reference to certain of its preferred embodiments, it should be understood that the embodiments described herein are illustrative rather than limiting in nature and that many variations and modifications are possible within the scope of the present invention.
This application claims benefit of U.S. Provisional Application Ser. No. 60/529,693, filed Dec. 15, 2003, the teachings of which are incorporated herein by reference in their entirety.
| Number | Date | Country | |
|---|---|---|---|
| 60529693 | Dec 2003 | US |
