The natural gas is preferably loaded at a port, but may also be loaded from a deep sea location in the ocean where a pipeline may not be feasible. Also if regulations prevent flaring, use of a marine vessel may be more economic than other options such as re-injecting the gas. Multiple offshore fields can be connected to a central loading facility, providing the combined loading rates are high enough to make efficient use of the marine vessel(s).

 Referring now to FIG, 29, there is described a detailed example of the overall method of transportation of the gas, including a further description of the on-loading and off-loading of the gas. The preferred marine CNG transportation system of the present invention is preferably directed to a source of natural gas such as a gas field 111. The composition of the natural gas delivered from a gas field 111 is preferably pipeline quality natural gas, as is known in the art. A loading station 113, capable of receiving gas at a pressure of approximately 400 psi or other pipeline pressure, is provided for preparing the gas for transportation.

 Loading station 113 preferably includes compressing and chilling equipment, such as compressor/chiller 117, as is known in the art, for compressing the natural gas to a pressure of approximately 1800 psia, for the 0.6 specific gravity gas example, and chilling the gas to approximately -20°F. For example, compressor/chiller 117 may comprise multiple Ariel JGC/4 compressors driven by Cooper gas-fired engines, depending on capacity, with York propane chilling systems. Loading station 113 is preferably sized to load CNG at a rate greater than or equal to approximately 1.0/0.9 times the rate at which CNG will be consumed by end users, to optimize the capital cost of the loading station 113 and optimize its Operating costs.

 Loading station 113 is also preferably provided with a loading dock 131 for loading the compressed and chilled natural gas aboard a CNG transporting marine vessel for transporting the gas produced from the gas field 111. The gas field 111 and the loading station 113 may be connected by a conventional gas line 151 as is well known in the art. Likewise, the compressor/chiller 117 is connected to loading dock 131 by an insulated conventional gas line 152. Marine vessels, such as ship 10, is provided for transportation of the CNG. A plurality of such ships is preferably provided so that a first ship 10 can be loaded while a previously loaded second ship is in transit. In actual practice, the choice between ships or barges as the marine vessel of choice will depend on the relative capital costs and the relative travel time between the two options, barges typically being less expensive but slower than ships. Although the preferred method of the present invention will be described with respect to ships, it should be understood that ships, barges, rafts or any other type of water transport may be used without departing from the scope of the invention.

 A receiving station 112 is provided for receiving and storing the transported natural gas and preparing it for use. The receiving station 112 preferably comprises a receiving dock 141 for receiving the CNG from the ship 10, and an unloading system 114 in accordance with the present invention for unloading the CNG from ship 10 to a surge storage system 181.

 Surge storage system 181 may comprise a land based storage unit or underground porous media storage, such as an aquifer, a depleted oil or gas reservoir, or a salt cavern. One or more vertical or horizontal wells (not shown), as are well known in the art, are then used to inject the gas and withdraw it from storage. The surge storage system 181 preferably is designed with a CNG storage capacity that is sufficient to supply the demand of users, such as a power plant 191, a local distribution network 192, and optional additional users 193, during the time period between arrival of the second ship 120 and first ship 10 at receiving dock 141. For example, surge storage system 181 may have the capacity to accept two ship loads of CNG and provide sufficient CNG to supply users 191, 192 (and 193, if provided) for about two weeks without being re-supplied. The surge storage system 181 is required in some cases to allow a ship 10 to unload CNG as rapidly as possible and to allow for a disruption in demand for CNG such as a failure of power plant 191. Additionally, surge storage system 181 should have about two weeks of reserve capacity to supply users 191, 192 in the event a hurricane or earthquake disrupts the supply of CNG.

 Receiving dock 141 is connected to the unloading system 114 by displacing liquid line 144. The receiving dock 141 is also connected to the surge storage system 181, by gas line 161, as is well known in the art. Similarly, gas lines 163 and 164 connect the surge storage system 181 to gas users, such as power plant 191 and local distribution network 192, respectively. Additional gas lines 165 may optionally connect surge storage system 181 to the additional users 193, if required, without departing from the scope of the present invention.

 Alternatively, where a large existing gas distribution system is already in place, surge storage system 181 may not be necessary. In this case, line 161 is connected directly to lines 163, 164 (and 165, if provided) for discharging the CNG directly into the existing distribution system. Further, where the demand rate of CNG by users 191, 192 (and 193, if provided) is very high, unloading system 114 may be designed with sufficient capacity that the rate of discharge of CNG from ship 10 equals the total demand rate by users 191, 192, 193. It can be seen that in such a case, receiving dock 141 and unloading system 114 are in substantially constant use. Finally, surge storage system 181 may comprise an on-shore, or offshore, pipe with satisfactory surge capacity, conventional on-shore storage, a system of cooled and insulated pipes using the methods of the present invention, or the CNG marine vessel itself may remain at the dock to provide a continuing supply, although these options significantly increase the cost of receiving station 112.

 In operation, pipeline quality natural gas flows from gas field 111 to loading station 113 through gas line 151. One skilled in the art will appreciate that the present invention may load natural gas from an offshore collection point at an offshore facility. The present invention should not be limited to on-shore gas fields. At loading station 113, compressor/chiller 117, as an example, compresses the natural gas to approximately 1800 psi and chills it to approximately -20°F., to prepare the gas for transportation. The compressed and chilled gas then flows through gas line 152 to loading dock 131. The gas is then loaded aboard ship 10 by conventional means at loading dock 131.

 In the embodiment illustrated schematically in FIG. 29, second ship 120 has already been loaded with CNG at loading dock 131. After loading, second ship 120 then proceeds on to its destination. A portion of the CNG loaded may be consumed to fuel ship 120 during the voyage. Fueling ship 120 with a portion of the loaded CNG has the additional advantage of cooling the remaining CNG, by expansion, thus compensating for any heat gained during the voyage and maintaining the transported CNG at a substantially constant temperature. While second ship 120 is in route, first ship 10 is loaded with natural gas at loading dock 131. Although only two ships 10, 120 are shown, it will be recognized by one skilled in the art that any number of ships may be used, depending on, for example: the demand for natural gas, the travel time for the transporting ships 10, 120 to travel between loading dock 131 and receiving dock 141, and the rate of gas production from gas field 111.

 Upon its arrival at its destination, second ship 120 is unloaded at receiving dock 141 of receiving station 112. Unloading system 114 unloads the natural gas transported 6 aboard second ship 120 by allowing the gas to first expand to the pressure of surge storage system 181 and then to flow through gas line 161. Remaining gas is unloaded using displacing liquid line 144, as will be described further below. The natural gas in surge storage system 181 is then provided through gas lines 163 and 164 to users, such as the power plant 191 and the local distribution network 192, respectively, Thus, gas may be continuously withdrawn from surge storage system 181 and supplied to users 191, 192 although gas is only periodically added to surge storage system 181.

 During the process of unloading, sufficient gas is allowed to remain aboard second ship 120 to provide fuel for the return voyage to loading dock 131. After unloading, second ship 120 undertakes the return voyage to loading dock 131. First ship 10 then arrives at receiving dock 141 and is unloaded as described above with respect to second ship 120. Second ship 120 then arrives at loading dock 131 and the on-loading/off-loading cycle is repeated. The on-loading/off-loading cycle is thus repeated continuously.

 When more than two ships 10, 120 are used, the on-loading/off-loading cycle is also repeated continuously. The frequency with which the on-loading/off-loading cycle must be repeated (and thus the number of ships required) depends on the rate at which gas is withdrawn from surge storage system 181 for supply to users 191, 192 and the capacity of surge storage system 181.

 Referring now to FIG. 32, there is shown a schematic representation of an embodiment of a compressed natural gas off-loading system for use in practicing the method of the present invention. The off-loading system, denoted generally by reference numeral 114, preferably comprises a displacing liquid 143, a insulated surface storage tank 142 for storing the displacing liquid 143, and a pump 141 connected to an outlet of insulated surface storage tank 142 for pumping the displacing liquid 143 out of surface storage tank 142. A liquid return line 144a and return pump on shore are provided to return the liquid to the liquid storage tank 142. One or more sump pumps 141a are provided on the marine vessel 10. Sump pumps 141a on the marine vessel 10 returns the liquid to the tank 142 through the return manifold system 144a.

 The displacing liquid 143 preferably comprises a liquid with a freezing point that is below the temperature of the CNG transported aboard ship 120, which is approximately -20°F. Further, the composition of displacing liquid 143 preferably is chosen so that the CNG has only negligible solubility in displacing liquid 143. A suitable displacing liquid which meets these requirements, and is relatively readily available at reasonable cost is methanol. Methanol is known to freeze at approximately -137°F., and CNG has low solubility in methanol.

 A displacing liquid line 144 is preferably provided to connect the pump 141 to ship 10 or 120. A first displacing liquid valve 145 is preferably disposed in displacing liquid line 144 to prevent the flow of displacing liquid when valve 145 is closed, such as when ship 120 is not present. Similarly, a first gas valve 146 is preferably disposed in gas line 161 to prevent the backflow of gas when valve 146 is closed, such as when ship 120 is in transit.

 Pump 141 preferably comprises one or more pumps and pump drivers, arranged in series and/or parallel, and capable of producing sufficient methanol pressure at its discharge to overcome the pressure of surge storage system 181, the methanol flow losses in displacing liquid line 144, and any downstream flow losses in displacing the CNG to surge storage system 181. The capacity of reversible pump 141 depends on the unloading rate that is desired for ship 120.

 In the embodiment described above with respect to FIG. 32, ships 10, 120 are illustrated as including multiple storage pipes 12 for storing the gas being transported . It will be understood by one skilled in the art that any number of gas storage pipes 12 may be carried aboard ships 10, 120 without departing from the scope of the present invention.

 For example, multiple gas storage pipes 12 may include 20 inch diameter welded sections of X-80 or X-100 steel pipe, rack mounted and manifolded together in accordance with relevant codes. Such pipes may be satisfactory in terms of both performance and cost. Other materials may of course be used, provided they are capable of providing satisfactory service lifetimes and are able to withstand the CNG conditions of approximately -20°F. and approximately 1800 psi.

 Likewise, many acceptable means of insulating gas storage pipes 12 are possible, provided the CNG stored therein is maintained at a substantially constant temperature of approximately -20°F. over the time of its transit from loading dock 131 to unloading dock 141, including any idle time and any time required for the on-loading and off-loading processes. For example, with the 20 inch diameter pipe described above and expansion cooling provided by fueling the ship with CNG, an approximately 12-24 inch layer of polyurethane foam around the outside of the gas storage pipes 12 should result in the temperature being maintained at around -20°F. Other insulation, such as a 36 inch thick layer of perlite having a thermal conductivity of approximately 0.02 Btu/hour/foot/°F. or less are also acceptable.

 The unloading process is then practiced as previously described.

　

 FIG. 33 shows the dollar break-even cost per million BTU's of natural gas with a specific gravity of 0.7 versus the distance that the gas is being shipped for LNG 400, CNG 410, CNG 30 and pipeline 430. The LNG and pipeline data are taken from the Oil & Gas Journal dated May 15, 2000. LNG has a high initial cost because of the equipment that has to be built to handle LNG. The compressed natural gas has the distinct advantage of much lower starting costs as compared to that of LNG. All the present invention requires is some standard compressors and chillers to load and off load the compressed natural gas. Line 430 represents the use of a pipeline. Line 410 is the present invention for natural gas having a specific gravity of 0.7. FIG. 34 shows a similar graph for natural gas having a specific gravity of 0.6. The graph for gas having specific gravity of 0.7 is very economical because the compressibility factor is so low at 0.4. At 0.6, the natural gas is almost pure methane but still is competitive up to a travel distance of 6,500 kilometers. Pipeline is competitive up to a distance of about 500 kilometers. Thus, the present invention is competitive from about 300 miles to 4,000 miles transportation. The cost graphs include every cost associated with the transportation of the gas including amortization, insurance, interest, operating costs, etc. The slope of the lines on the graph shows the difference in transportation costs. The graphs also include the cost of the marine vessel. These graphs are at break even and do not represent taxes or profits.

 One of the possible locations for the use of the present invention is Venezuela. Thus, looking at the 0.7 specific gravity chart on cost versus distance, one can determine the cost from Venezuela to any port in the Caribbean. The invention is economical from anywhere in Venezuela to as far as the southeastern part of the United States. To use the graphs, enter the distance, move vertically to the CNG line and read across to determine the cost. Thus for Charleston, S.C., a distance of 1900 miles from eastern Venezuela, the breakeven cost is $0.60/mcf. This is based on a delivery rate of 0.5 BCF/day. Economies of scale may apply.

　

 While it is preferred that the storage system of the present invention be used at or near rts optimum operating conditions, it is considered that it may become feasible to utilize the system at conditions other than the optimum conditions for which the system was designed. It is foreseeable that, as the supplies of remotely located gas develop and change, it may become economically feasible to employ storage systems designed in accordance with the present invention at conditions separate from those for which they were originally designed. This may include transporting a gas of different composition outside of the range of optimum efficiency or storing the gas at a lower pressure and/or temperature than originally intended.

 The pipe based storage system of the present invention can also be used in the transport of liquids. The advantage to the present invention relates to the design factor for the pipe as compared to a tank. If the pipe only needs to be built twice as strong as is required (i.e. a design factor of 0.5), and the design factor for the tank is 0.25, then the tank will be four times stronger than is required. For example, liquid propane has a particular vapor pressure and the storage pipe can be designed for a pressure twice as great as the vapor pressure of the liquid propane. This means that the storage of liquid propane in a pipe would be cheaper than in a tank. It would also be cheaper to use pipes for liquid propane if the propane was going to be transported on a marine vessel. The liquid propane would be transported in the pipe at ambient temperature.

 While a preferred embodiment of the invention has been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit of the invention.

What is claimed is;

 1. A storage system for storing a compressible gas in the dense phase under pressure, the storage system comprising:

 one or more pipes of a material which will withstand a predetermined range of temperatures and meet required design factors for the pipe material;

 a chilling member cooling the gas to a temperature within said temperature range;

 a pressurizing member pressurizing the gas within a predetermined range of pressures at a lower temperature of said temperature range where the compressibility factor of the gas is at a minimum; and

 said chilling member and pressurizing member setting the temperature and pressure of the gas to maximize the ratio of mass of stored gas to mass of the pipe.

 2. The storage system of claim 1 wherein said pipes material is either X-80 or X-60 premium high strength steel and said temperature range is between -20°F. and 0°F.

 3. The storage system of claim 2 wherein said lower temperature is substantially -20°F.

 4. The storage system of claim 3 wherein the gas has a specific gravity of about 0.6 and said pressure range is between 1800 and 1900 pounds per square inch.

 5. The storage system of claim 3 wherein the gas has a specific gravity of about 0.7 and said pressure range is between 1300 and 1400 pounds per square inch.

 6. The storage system of claim 1 wherein said pipe is made of X-100 premium high strength steel and said temperature range is between -40°F. and 0°F.

 7. The storage system of claim 4 wherein said lower temperature is substantially -40°F.

  8. The storage system of claim 1 wherein said pressure range is that range of pressures at said lower temperature where the compressibility factor varies no more than 2% of the minimum compressibility factor.

 9. The storage system of claim 1 wherein there are a plurality of pipes connected by one or more manifolds.

 10. The storage system of claim 1 wherein the pipe material is steel and one required design factor is 0.5 of the yield strength of steel pipe.

 11. The storage system of claim 1 wherein said pipe is made of steel and further including maximizing the ratio of the mass of the stored gas to the mass of said steel pipe.

 12. The storage system of claim 11 wherein the pipe diameter and pipe wall thickness are chosen to maximize the ratio of masses.

 13. The storage system of claim 12 wherein the gas has a specific gravity of substantially 0.6 and wherein one required design factor is 0.5 of the yield strength of the steel pipe, the steel pipe has a yield strength of 80,000 psi, the pipe diameter is 20 inches, and the pipe wall thickness is between 0.43 and 0.44 inches.

 14. The storage system of claim 12 wherein the gas has a specific gravity of substantially 0.6 and wherein one required design factor is 0.5 of the yield strength of the steel pipe, the steel pipe has a yield strength of 80,000 psi, the pipe diameter is 36 inches and the pipe wall thickness is between 0.78 and 0.79 inches.

 15. The storage system of claim 12 wherein the gas has a specific gravity of substantially 0.7 and wherein one required design factor is 0.5 of the yield strength of the steel pipe, the steel pipe has a yield strength of 80,000 psi, the pipe diameter is 24 inches and the pipe wall thickness is between 0.38 and 0.39 inches,

 16. The storage system of claim 12 wherein the gas has a specific gravity of substantially 0.7 and wherein one required design factor is 0.5 of the yield strength of the steel pipe, the steel pipe has a yield strength of 80,000 psi, the pipe diameter is 36 inches and the pipe wall thickness is between 0.58 and 0.59 inches.

 17. A method for storing a compressible gas in the dense phase in a storage container under pressure, the method comprising:

 18. The method of claim 17 wherein said storage container is made of X-80 or X-60 premium high strength steel and said temperature range is between -20°F. and 0°F.

 19. The method of claim 18 wherein said lower temperature is substantially -20°F.

 20. The method of claim 19 wherein the gas has a specific gravity of about 0.6 and said pressure range is between 1800 and 1900 pounds per square inch.

 21. The method of claim 19 wherein the gas has a specific gravity of about 0.7 and said pressure range is between 1300 and 1400 pounds per square inch.

 22. The method of claim 17 wherein said storage container is made of X-100 premium high strength steel and said temperature range is between -40°F. and 0°F.

 23. The method of claim 22 wherein said lower temperature is substantially -40°F.

 24. The method of claim 17 wherein said pressure range is that range of pressures at said lower temperature where the compressibility factor varies no more than 2% of the mini-mum compressibility factor.

 25. The method of claim 17 wherein said storage container is made of steel pipe.

 26. The method of claim 25 wherein one required design factor is 0.5 of the yield strength of the steel pipe.

 27. The method of claim 25 further including maximizing the ratio of the mass of the stored gas to the mass of the steel pipe.

 28. The method of claim 27 further including selecting a pipe diameter and determining the optimum pipe wall thickness from the ratio of masses.

 29. The method of claim 28 wherein the gas has a specific gravity of substantially 0.6 and wherein one required design factor is 0.5 of the yield strength of the steel pipe, the steel pipe has a yield strength of 80,000 psi, the pipe diameter is 20 inches and the pipe wall thickness is between 0.43 and 0.44 inches.

 30. The method of claim 28 wherein the gas has a specific gravity of substantially 0.6 and wherein one required design factor is 0.5 of the yield strength of the steel pipe, the steel pipe has a yield strength of 80,000 psi, the pipe diameter is 36 inches and the pipe wall thickness is between 0.78 and 0.79 inches.

 31. The method of claim 28 wherein the gas has a specific gravity of substantially 0.7 and wherein one required design factor is 0.5 of the yield strength of the steel pipe, the steel pipe has a yield strength of 80,000 psi, the pipe diameter is 24 inches and the pipe wall thickness is between 0.38 and 0.39 inches.

 32. The method of claim 28 wherein the gas has a specific gravity of substantially 0.7 and wherein one required design factor is 0.5 of the yield strength of the steel pipe, the steel pipe has a yield strength of 80,000 psi, the pipe diameter is 36 inches and the pipe wall thickness is between 0.58 and 0.59 inches.

 33. A method for optimizing gas payload in a gas storage pipe, the method comprising:

 34. The method of claim 33 wherein the steel pipe is a high strength steel pipe 36 inches in diameter and made of material having a yield strength between 60,000 and 100,000 pounds per square inch.

 35. The method of claim 33 wherein the design factor is the lower of 0.5 of the yield strength of the pipe and 0.33 of the ultimate tensile strength of the pipe.

 36. The method of claim 33 wherein the minimum temperature is -20°F.

 37. The method of claim 36 wherein the optimum pres-sure is between 1,200 and 1,500 pounds per square inch.

 38. The method of claim 37 wherein the steel pipe has a 36 inch diameter.

 39. The method of claim 38 wherein the gas has a specific gravity of 0.6 and the pipe has a wall thickness of 0.66 inches.

40. The method of claim 38 wherein the gas has a specific gravity of 0.7 and the pipe has a wall thickness of 0.49 inches.

 41. The method of claim 33 wherein the ratio of the mass of stored gas to the mass of storage components is at least 0.3.

42. A system for storing gas having a compressibility factor and a gas constant, the system comprising:

 a plurality of pipes having an inner and outer diameter;

 a manifold connecting said plurality of pipes; and

 said pipes being made of a material having a yield stress which will withstand a reduced temperature and elevated pressure that maintains the gas at a minimum compressibility factor and in a dense phase, wherein said pipe material and the reduced temperature and elevated pressure are chosen so as to maximize the value of ψas determined by:

　

　

 where S is the allowable stress of the pipe material, ps is the density of the pipe material. Z is the compressibility factor of the gas, R is the gas constant, Tg is the reduced temperature; Di is the inner diameter of the pipe, and Do is the outer diameter of the pipe.

 43. The system of claim 42 wherein the gas is stored at a temperature in the range of -20°F. to 0°F. and at a pressure above 1200 pounds per square inch.

　

*****

　

UNITED STATES PATENT AND TRADEMARK OFFICE

PATENT NO.: 6,584,781 B2

DATED:July 1, 2003

INVENTOR(S): William M. Bishop