US 20030051875 A1
The present invention is a method for re-gassifying Liquefied Natural Gas (LNG) in a subterranean formation/cavity, storing the resulting gaseous hydrocarbon in the same or connected strata, then subsequent conventional production and delivery of the gas to end users. LNG is injected into a permeable subterranean reservoir through surface and wellbore equipment suitable for operations at cryogenic temperatures. The liquid hydrocarbon vaporizes in the permeable rock/cavity near the injection wellbore as it gains thermal energy from the surrounding strata. The resulting gas is held within the reservoir for subsequent production and/or immediately produced by producing wells in the same or contiguous formations. The invention eliminates the need for onshore LNG receiving/storage terminals.
1. A method of storing natural gas comprising liquefying natural gas to obtain liquefied natural gas (“LNG”), transporting the LNG to a location near a subterranean reservoir within a formation, off loading the LNG into the reservoir, and permitting the ambient heat of the formation to vaporize the LNG into the natural gas.
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9. A method of storing natural gas comprising liquefying the natural gas to obtain liquefied natural gas, (“LNG”), transporting the LNG to a location near a subterranean gas reservoir wherein the reservoir has a flow capacity of at least about 10,000 md-ft, offloading the LNG into the reservoir through at least one injection well capable of receiving cryogenic fluids and which is in fluid communication with the reservoir, permitting the ambient heat of the formation to vaporize the LNG back into the natural gas, and withdrawing the natural gas through at least production well in fluid communication with the reservoir.
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 This invention relates to a method of storing liquefied natural gas (“LNG”) in a subterranean reservoir. The LNG is injected into an injection well in fluid communication with the subterranean reservoir, and the ambient heat of the reservoir and the surrounding formations vaporizes the LNG. The resulting natural gas is delivered to a point of end use via conventional gas transmission means.
 LNG is defined by the Gas Processors Suppliers Association (“GPSA”) as a liquefied gas consisting of hydrocarbon components typically including methane, ethane, propane, and normal and iso-pentane as well as some trace impurities (FIG. 1.1, GPSA Engineering Data Book, Gas Processors Suppliers Association, 2000, Gas Processors Suppliers Association, 6526 E. 60th St., Tulsa, Okla. 74145). At atmospheric pressure, methane, which is the main component of LNG and generally present in concentrations of about 80-100% by volume, is a liquid at temperatures between its normal boiling point of about −259° F., and above its freezing point at about −296° F. Within these temperature ranges, methane predominant LNG has a density of about 0.5 gm/cc and a viscosity of about 0.12 centipoise (Friend, D., Ely, J., Ingham, H.; Tables for the Thermophysical Properties of Methane, April, 1989, National Institute of Standards and Technology, Boulder, Colo., 80303-3328).
 In the operation of LNG transportation, storage, and gas delivery, it is customary to deliver LNG to on-shore receiving facilities by ocean-going tankers carrying LNG chilled to −270° F. The receiving facilities store the LNG in liquid form once it is off loaded from the tankers. When sufficient end user demand occurs, the LNG is converted back to gaseous form immediately prior to its delivery to transmission lines. From the transmission pipelines, it is moved to end users in gaseous form. This process typically starts by offloading LNG tankers into onshore LNG storage vessels using pumps and piping capable of transferring cryogenic liquids. LNG is re-gassified by adding heat and the resulting gas is piped through metering facilities into natural gas transmission lines for ultimate delivery to markets.
 The equipment required at the receiving terminal includes docks capable of berthing an LNG tanker, cryogenic pumps and piping capable of transferring LNG from the tankers to the storage tanks, cryogenic storage tanks, re-gassification equipment, a source of heat capable of introducing sufficient heat to vaporize the LNG, piping connections and measurement facilities for metering and delivering the gas into a natural gas distribution system.
 Problems associated with these receiving facilities include the high cost and risk of berthing ships along coastlines at specialized docks capable of receiving LNG tankers, the high cost of cryogenic storage facilities, the cost and energy required to convert the LNG back to gaseous form, and the need to install new pipelines and metering systems required to deliver gas to a transmission line or gas distribution system.
 Also, the safety precautions required to berth and unload ocean-going LNG tankers creates complexities since onshore facilities near population centers are discouraged due to a real or perceived probability of industrial accidents. The very large initial capital investment, significant recurring operating costs, and environmental and community related drawbacks have discouraged construction of onshore receiving facilities (U.S. Pat. No. 4,365,576).
 Prior art solutions attempting to eliminate onshore LNG receiving facilities include U.S. Pat. No. 5,511,095 which describes direct injection of LNG into subterranean man-made cavities capable of receiving and storing the LNG in a dense phase. U.S. Pat. No. 5,511,095 relies on storing the LNG at prescribed pressures and temperatures in the subsurface so that LNG does not return to gas phase. While pressure can be controlled in subsurface cavities by a variety of means, the temperature of the cavity will continuously attempt to return to the ambient temperature of the subsurface.
 Except in the Polar Regions, ambient subsurface temperatures rarely fall below 50° F., so maintaining subsurface temperatures low enough to keep LNG from flashing back to gaseous phase is impossible without an active cooling mechanism: e.g., refrigeration or introduction of cold fluids. To store the LNG as any phase but gas, the temperature of the cavity must remain below about −116° F., which is the critical temperature of methane. Critical temperature is defined as the maximum temperature at which a pure component can exist as a liquid.
 U.S. Pat. No. 5,511,095 relies on displacing the “dense phase” LNG with saline water or brine. Brine freezes at temperatures significantly higher than about −116° F. where methane-based LNG will become gaseous. Displacement with brine at these temperatures will create significant problems in the cavity and wellbores connecting the cavity to the surface: e.g., the interface in the reservoir at the boundary between the LNG and the displacing fluid will freeze and no longer move with the differing fluid levels, while any brine in a wellbore at these temperatures will freeze.
 Academic work designed to evaluate the permeability reduction caused by injecting natural gas at cold temperatures into subterranean formations found that permeability decreased significantly, but, in no case was a total loss of injection experienced. The current art of injecting cold fluids in water saturated porous media is characterized by significant permeability reduction and difficult injection due to ice and hydrate formation and other deleterious effects (Sturgeon-Berg, R., Permeability reduction effects due to methane and natural gas flow through wet porous media, Master of Science Thesis, Chemical and Petroleum Refining Engineering Department, Colorado School of Mines, Golden, Colo., U.S.A. 1996.).
 The current state of the art in ocean bound LNG delivery is characterized by continued use of onshore cryogenic LNG storage and re-gassification facilities. U.S. Pat. No. like 4,365,576 describe a means of storing cryogenic liquids in man-made offshore storage vessels but these have not gained widespread use. The current system is costly and is projected to “eventually manifest itself as a choke point in the U.S. system.” (Economides, M., Oligney, R., and Demarchos, A., “Natural Gas: The Revolution Is Coming,” Journal of Petroleum Technology, Society of Petroleum Engineers. May, 2001(p66), Dallas Tex., U.S.A.).
 It is an object of the invention to use the ambient temperature and warming capacity of subsurface formations to gassify the LNG injected into the subsurface reservoir.
 Another object of the invention is to use existing porous reservoirs to store LNG in gaseous form.
 It is an object of this invention to obtain a more economical and efficient method of delivering LNG to the market.
 A further object of the invention is to use existing transmission systems in fluid communication with the reservoir to deliver natural gas to the market.
 To achieve the foregoing and other objects, and in accordance with the purposes of the present invention, as embodied and broadly described herein, conventional subterraneous porous fluid reservoirs are used to receive and store LNG. The LNG is injected into an injection well capable of withstanding cold temperatures: e.g., down to about −296° F., and in fluid communication with the reservoir. As the LNG begins moving down the wellbore and into portions of the reservoir away from the injection well, the LNG absorbs heat from the surrounding formations until it eventually reaches the ambient temperature of the formation, which is approximately 1.5° F. higher than surface temperature for each 100 ft. of depth below the surface. The resulting gas will come to temperature equilibrium with the surrounding formation over a period of a few hours and at most a few days. Once the LNG is in the subsurface, the tendency of the subterranean formation to warm the LNG to ambient temperature is continuous and for all intents and purposes, infinite. The resulting gas is stored in the reservoir until it is produced through one or several production wells in fluid communication with the reservoir and the gas is withdrawn for delivery to the market.
 The accompanying drawings, which are incorporated in and form a part of the specification, illustrate the embodiments of the present invention and, together with the description, serve to explain the principles of the invention.
 In the drawings:
FIG. 1 is an elevational view of an LNG tanker off-loading LNG into an injection well in fluid communication with a reservoir that is in fluid communication with two production wells.
FIG. 2 is an elevational view of an injection well capable of receiving cryogenic fluids in fluid communication with a gas reservoir that is also in fluid communication with a production well.
 This invention relates to improvements in the method of delivering LNG to conventional gas users by eliminating onshore surface receiving cryogenic storage facilities. The initial capital cost, the ongoing operations expense, the onshore land acreage, operations manpower, and shoreline community hazards, and exposures to risk are reduced by this invention.
 These benefits are accomplished by offloading LNG from tankers directly into conventional subterranean reservoirs through traditional injection wells fitted with wellbore equipment capable of operations at cryogenic temperatures. The LNG tanker can be berthed at offshore unloading facilities in close proximity to the injection wellheads. The wellheads can be located on a multi-well platform, on single well structures, on the sea-bottom with a surface tie-in injection lines, on near shore injection wells and on other facilities tied into a cryogenic transport line from the tanker to the injection well. The LNG is stored in gaseous form in subterranean reservoirs at ambient conditions. The invention eliminates re-gassification facilities since the LNG is vaporized after it reaches the subterranean reservoir by utilizing heat from the surrounding strata to gassify the LNG. The present invention takes advantage of the ambient temperatures of the subterranean reservoir to impart heat to the injected fluid, and the injected fluid's ability to displace and remove liquid water in near wellbore areas that would normally decrease injectivity of the injection well.
 The invention reduces the need for gas gathering, metering, and transmission line tie-ins if a reservoir is used that was previously or currently used for traditional gas production. If a recently decommissioned gas production field is used or one still on production, gas gathering and/or transmission line tie-ins can be used. Gas can be produced from production wells concurrently with LNG injection or as demand requires. This invention simplifies offshore handling if a suitable reservoir that is in fluid communication between the offshore and onshore surface locations is used, since LNG can be injected offshore and natural gas produced at the onshore location.
 The present invention differs from the prior art in that it uses underground reservoirs with sufficiently high native permeability and infectivity that injection of the LNG can be initiated. In addition, wellbore conditioning is carried out and maintained in injection wells to ensure adequate infectivity. Conditioning includes minimizing water saturation by repeated injection of dry gas, thus decreasing water saturation by evaporating, vaporizing, subliming, and absorbing water in which the LNG comes in contact. The effect of the reduction in water saturation in the flow paths followed by the LNG will be to maintain permeability with respect to the injected LNG.
 Gas resulting from re-gassification of LNG is dry: i.e., contains no measurable water in liquid or vapor form, and will come to thermodynamic equilibrium with the water in the reservoir until the gas becomes water saturated. This gas is produced to the surface and any undesirable water is removed before being sent to the gas purchaser, resulting in a net decrease in the water within the reservoir. Although the total amount of water in the reservoir cannot be affected significantly, the area around the injection wellbores can, since the near-wellbore area will be flushed extensively with water-free gas/LNG. Since no additional water is introduced into the reservoir near the injection well, the flow paths taken by the LNG/gas will eventually become water-free. For example, one million cubic feet of a typical water free natural gas at 150° F. and 1000 psia can absorb 220 pounds of liquid water while coming to equilibrium with a liquid water saturation (see GPSA page 20-2,GPSA Engineering Data Book, Gas Processors Suppliers Association, 2000, Gas Processors Suppliers Association, 6526 E. 60th St., Tulsa, Okla. 7414500). Therefore, a single tanker load of 3 bcf (billion cubic feet) of LNG could remove 660,000 pounds or 1900 bbls of water from the flow paths of the LNG/gas. The resulting water-free flow paths will provide excellent conduits for future injection of LNG. Injectivity should continue to improve until it approaches a highly favorable single-phase liquid relative permeability.
 Injection of LNG continues until offloading of the tanker is complete. The gas reservoirs best suited are those that have flow capacities above about 1000 md-ft and preferably above about 10,000 md-ft, and most preferably above 100,000 md-ft. The permeabilities and injection rate of the injection well should permit offloading of the LNG at rates of about 1000 bbl/day to about 50,000 bbl/day and preferably about 10,000 bbl/day to about 50,000 bbls of LNG/day. The reservoir should also have gas “storage” volume sufficient to accept a full load of LNG without overpressuring the reservoir. In addition, the reservoir should not have a water influx greater than about 1000 bbl/day to about 10,000 bbl/day and preferably about 0 bbl/day to about 1000 bbl/day: this will help the reservoir to maintain containment-like behavior and reduce the introduction of new water to injection wellbores that have been de-watered and/or conditioned to reduce water saturation. Heat flux into the reservoir from surrounding strata will bring the gas to ambient temperature in a matter of days. It is preferred that the reservoir not be significantly affected by an aquifer that would re-introduce substantial quantities of water into the reservoir.
 If LNG injection does not sufficiently decrease water saturation, other methods of decreasing water saturation near the wellbore can be used to pre-condition injection wells for LNG injection. These other methods include the use of fireflood techniques to vaporize and displace water around the injection wellbore, injection of surfactants to allow increased gravity related water drainage, injection of chemicals to absorb and/or adsorb water off of the reservoir rock, or other dehydration methods used in the current art.
 By reducing or eliminating water saturation in the injection well, injection of LNG should follow the same pressure—flow rate relationships commonly used in the current art of petroleum reservoir engineering as defined by Darcy's law. Darcy's law states that the flow-rate through porous media is proportional to the cross sectional area, the permeability, and the pressure differential, while flow-rate is inversely proportional to the viscosity of the flowing fluid and the length of flow path. Wells capable of injecting a 0.12 centipoise liquid at the required flow are common in the prolific sands of the U.S. gulf coast and other coastal offshore subterranean reservoirs throughout the world.
 Injection rates in injection wells sufficient for efficient offloading of large LNG tankers (135,000 m3) are generally within the range of about 20,000 bbl/day/well to about 50,000 bbl/day/well and preferably about 50,000 bbl/day/well to about 100,000 bbl/day/well and most preferably above 100,000 bbl LNG/day/well. To accomplish a one-day offloading turnaround, approximately 10 injection wells are required. Horizontal and fractured wells can be used to provide higher injectivity if necessary. In the Gulf of Mexico, wells capable of injection at these rates are currently producing gas into well-established gas gathering systems.
 As the pressures in existing, state of the art reservoirs are depleted, the producing zones may be abandoned and the wells plugged. A few of these same wells could be “unplugged” and used for LNG injection, the low pressure reservoirs used for storage, and the multitude of current platform, gathering systems, and producing wells used for production as-is; thus, this invention could avoid the great expense presently incurred in the current art in abandoning these platforms and wells.
 Gas reservoirs suitable for this invention can be described as high permeability, competent porous formations with low pressure due to depletion, but high fracture gradients so that the formation can be repressured completely if desired. The size of the reservoir should be large enough to meet the needs of the LNG delivery schedule in conjunction with the gas offtake schedule. A preferred embodiment has existing gas production wells and gathering, metering and trunk line connections so that delivery to the gas distribution network is simple.
 Injection wells suitable for this invention can be described as fitted with cryogenic capable injection lines, wellheads, and tubulars and preferably wellbore equipment and casing strings. Large tubular strings of at least 3½″ outer diameter and preferably larger will enable larger injection rates. Tubular strings preferably should be fitted with multiple expansion/contraction joints or other means to allow anticipated movement due to temperature fluctuations. Tubing strings should also be fitted with sufficient pressure relief systems to accommodate a blockage and resulting reverse flow after the wellbore fluids re-gassify.
 The present invention greatly simplifies the process of receiving and storing LNG in locations where conventional offshore oil and gas fields exist. Since these fields generally deliver gas into the gas transmission system, the ability to move ocean-borne LNG to end-users is more efficient and economical than conceived in the prior art. In its simplicity and efficiency, the present invention not only eliminates the cost and hardship incurred in building new facilities, but also extends the productive lives of offshore gas production assets considered uneconomic and soon to be permanently abandoned.
 The actual operation and apparent advantages of the present invention will be better understood by referring to the drawings which are not necessarily to scale and in which like numerals identify like parts and in which:
FIG. 1 illustrates the preferred method for carrying out the injection, regassification, storage, and ultimate delivery of hydrocarbon gas previously existing in the liquefied form. LNG tanker 2 delivers a load of LNG to offshore injection well 4. Docking facilities 6 similar to those used in Floating Production and Storage Operations (FPSO) vessels can be used to tether and maintain position of the LNG Tanker near the injection well location. Transfer pumps 8 capable of handling cryogenic fluids housed either on the tanker itself, on the wellhead platform 18, or on a service vessel are used to transfer LNG from the tanker to the injection well. After the lower section 10 of injection well 4 is sufficiently cooled, the LNG (some of the LNG may be converted to gas due to heat being absorbed by the LNG) begins dispersing out through perforations 12 into the subterranean gas reservoir 14.
 While liquefied gas contacts the underground formations, it is heated by the ambient heat present in subterranean formations 26 and in the reservoir itself 14. LNG continuously vaporizes and moves toward lower pressures that exist in other parts of the reservoir near producing wells 20 and 22. Given sufficiently high injection rates, vaporization may not occur until the LNG has flowed away from the injection well 10. However, the capacity of the formation to warm the LNG to ambient conditions is essentially infinite, so the LNG will eventually return to a gas phase and approach ambient temperature. The resulting increase in pressure as the LNG returns to the gas phase will force flow toward lower pressure production wells and areas of the reservoir farther away from injection sources.
 High permeability, low-pressure reservoirs of moderate size (10-15 bcf) provide the best reservoirs for application of this invention since such reservoirs require low injection pressure to introduce LNG into the formation, move gaseous hydrocarbon quickly to producing wells, and provide high deliverability at the producing wells. There is no requirement for a specific size. However, a reservoir size of less than a tanker load (approximately 3 bcf) could be used as a regassification means and alternate docking method to conventional LNG facilities. Larger reservoirs could be charged continuously or seasonally for long-term gas storage and/or peak production needs. Even those reservoirs that have previously been abandoned may be candidates since their production characteristics are well known, thus reducing the risk associated with unpredictable reservoir performance.
 The benefits of injecting gas in liquefied form are many. No regassification equipment is required. Injection is accomplished with pumps 8, which are simpler and less expensive than the compressors that would be required for the same mass injection rates of gaseous hydrocarbons. The hydrostatic head of the injection liquid provides additional pressure energy for injection since the accumulated mass of the LNG in the wellbore serves to push LNG into the reservoir 14. Conversely, producing wells can be located offshore 20 or onshore 22 if the subject reservoir extends onshore. In general, using the LNG injection wells for subsequent production is not advised, since this could re-saturate the near-wellbore region of the injection well with water produced along with the gas. Once delivery of the gas is needed, gas is produced from production wells into a gathering system or gas transmission system 24.
FIG. 2 illustrates the present method for delivering LNG to the underground gas reservoir 14. LNG is injected from a surface location into a cryogenic tubing string 32. LNG moves down the wellbore at velocities exceeding the bubble rise velocity of natural gas which is approximately 7 feet/second. LNG exits the wellbore 34 in gas and/or liquid form into the open casing 36 that is adjacent to the reservoir. Technology developed for the steamflood and LNG handling industries can be used in constructing competent wellbores for purposes of injection. The current art in these industries includes ductile metallurgies at cryogenic temperatures, expansion/contraction fittings and seals, and insulated casings and cements 38. Low heat-flux annular fluids like gelled diesel can be used to isolate upper sections of the wellbore from extreme temperature variations 40 and maintain LNG in liquid form if it is deemed advantageous. The present invention incorporates injection into the formation in either gas, liquid or mixed phase; during the offloading of a tanker all three phases may exist at times.
 After the LNG enters the casing 36, it is forced into conventional perforations 42. After traveling the length of the perforations, it flows into the outer reaches of the reservoir 14. The area of the reservoir near the injection wellbore 44 will have an extremely low water saturation after the LNG and dry gas has been injected for a sufficient time to remove the liquid water in the pore spaces. For the maximum injection rate, LNG will move as a liquid away from the wellbore toward lower pressures.
 As the formation warms the LNG, the LNG begins to vaporize 46 and moves away from the LNG saturated areas of the formation toward production well 50. After the ambient temperature of the formation heats the LNG to gassify it, the gas moves within the gas reservoir 14 according to pressure gradients induced by production and injection wells. Gas can remain in the reservoir until seasonal or cyclic demand requires production of the gas through production well 50 or can be produced concurrently with injection.
 While the foregoing preferred embodiments of the invention have been described and shown, it is understood that the alternatives and modifications, such as those suggested and others, may be made thereto and fall within the scope of the invention.