US3477509A - Underground storage for lng - Google Patents

Description

Nov. 11, 1969 H. s. ARENDT UNDERGROUND STORAGE FOR LNG Filed March 15, 1968 20 1:11. 2 Y 22 +10 ll '3 *3 *3 '3 v v v"'|"'4 v v L.NG.OUT 4 ms. INJECTION j LNG. INJECTION 4 WELL WELL INITIAL GAS /|NJECT|ON TO a v PURGE WATER ATTOR United States Patent US. Cl. 166252 8 Claims ABSTRACT OF THE DISCLOSURE An underground liquefied gas storage and vaporization chamber is formed by injecting a purge gas under sufficient pressure into an aquifier or water bearing sand reservoir to displace the water and create a gas bubble. Liquefied gas, such as liquefied natural gas (LNG), ethane, ethylene, etc. is injected into the gas bubble whereupon freezing of the surrounding water in the aquifier occurs. There is appreciable heat flow to the stored liquefied gas from the overlying and underlying formations which vaporizes a portion of the gas which may be withdrawn in gaseous form at positions remote from the injection wells. The non-vaporized portion can be withdrawn in liquid form and vaporized in the usual revaporization facilities.

Background of the invention This invention relates to improvements in methods of storing and vaporizing liquefied gas in general and in particular to an improved low cost method of storing and partially vaporizing LNG delivered at 2S9 F. and atmospheric pressure or under pressure at more moderate temperatures.

In the transportation of natural gas in liquefied form from a point of production to a point of consumption a major cost factor in the capital investment is the cost of the storage facilities. Conventional types of atmospheric pressure storage cost in the range of $8.00 per barrel of capacity. Recent proposals havesuggested shipments of liquefied natural gas in the 200. p.s.i. pressure range in order to avoid the extreme low temperatures required at atmospheric pressure. The cost of 200 p.s.i. conventional pressure storage soars to approximately $45.00 per barrel. With the large storage volumes required in ship movements of LNG even the $8.00 per barrel cost is a major capital investmentland a $45.00 per barrel cost approaches a prohibitive level. Accordingly, the incentives for developing a low cost storage technique for liquefied gases are great.

Initial LNG projects were for peak shaving with a relatively small volume of gas being liquefied on a daily basis and stored for an extended period for use during winter peaks. Under these conditions minimum heat flow was critical. Although the new base load LNG projects in which large volumes of LNG are revaporized each day could not only tolerate but actually benefit from appreciable heat flow in the storage facilities. Despite this, the same type of minimum heat flow storage developed for peak shaving projects has been adopted for the new base load projects.

In accordance with the present invention the cost of providing LNG storage, either at atmospheric or an elevated pressure such as the aforementioned 200 p.s.i., can be drastically reduced. In accordance with the invention, the initial step is the selection of an underground sane reservoir at a suitable depth and having adequate porosity, permeability and thickness. While a sand reservoir is preferred, a suitable limestone or other aquifier layer can be used. Once a suitable underground formation has Patented Nov. 11, 1969 ice been selected, injection of gas (such as natural gas, air, flue gas, etc.) equivalent to the desired storage volume or slightly greater to displace the mobile water out of the storage volume is initiated. The displacement of the mobile portion of the formation water is done before LNG is injected to prevent the extreme cold of the LNG from causing an almost immediate freeze-up and immobilization of the formation water with consequent loss of injectivity. Many aquifiers, i.e. water bearing soil strata, are sufiiciently permeable and extensive so that the displaced water can be forced out into the surrounding aquifier. In other cases, the displaced water may be produced through wells located around the approximate periphery of the planned storage area. The use of producing wells to produce the displaced water will add somewhat to the cost but permits better control of the configuration of the storage bubble as well as minimizing pressure build-up in the aquifier to permit use of less extensive or less permeable formations. In one form of the novel method of the invention. LNG injection is initiated as soon as a sufficiently large gas slug has been injected so that the gas slug moving ahead of the LNG displaces the formation down to about connate water and insures separation of the mobile water phase and the LNG. Under this procedure LNG injection is started after a volume of purge gas equal to approximately /3 to /2 of the ultimate storage volume has been displaced.

As the injected LNG ,cools the reservoir, the formation water surrounding the storage volume freezes, effectively creating an impermeable wall about the storage area and confining the LNG without any dependence on structural closure. It is contemplated with the storage reservoir thus formed that an LNG cargo from an incoming ship may be injected through suitable injection wells to refill the portion of the reservoir which previous to the ship arrival had been partially voided of liquefied gas by a combination of natural revaporization and withdrawals in liquid form.

As the stored LNG moves through the reservoir from the injection wells to the producing wells, a substantial amount of heat is absorbed from the formation and a proportionate amount of LNG will be vaporized during the precooling of the reservoir. Substantially all of the initial LNG will be vaporized as the reservoir rock or sand itself is cooled, as well as the overlying and underlying formations. After this precooling phase, the major though not exclusive source of heat will be the overlying and underlying formations which will continue to supply substantial heat at gradually diminishing rates as the cooling extends outward from the reservoir itself. Although this absorption of heat is very undesirable in an operation in which LNG is used solely for peak shaving, it is quite acceptable, in fact desirable, where LNG is used in a base load operation. Thus, it is a specific feature and advantage of the present invention in providing a system not only for storage of LNG but in also providing a system for vaporizing a portion of the LNG into gas at the same time. This feature of applicants underground storage (substantial heat flow from the surrounding rock formations) therefore reduces the amount of specific vaporization equipment needed at the point of LNG delivery and consumption.

Accordingly, it is the principal object of the invention to provide a new and novel method for storing and vaporizing large quantities of liquefied gases such as liquefied natural gases.

A further object of the invention is to provide a liquefied gas storage facility which is extremely safe and non-hazardous to the surrounding environment.

A further object of the invention is to provide a low cost storage facility for LNG which has a substantial heat gain sutficient to vaporize a major portion of the LNG as required.

A further object of the invention is to sufficiently reduce the unit cost of storage so that very large volumes can be stored thus providing security of supply in the event of interruption of deliveries. The larger storage will also permit use of larger ships and also the optimum scheduling of ships.

These and other objects and advantages of the invention will become apparent and the invention will be fully understood from the following description and drawings in which FIG. 1 is a vertical cross sectional view of an underground storage reservoir made in accordance with the method of the invention; and

FIG. 2 is a horizontal cross sectional view of the reservoir of FIG. 1 taken along line 2 -2 of FIG. 1.

Referring to the drawings in particular, a better understanding of the novel method of LNG storage and vaporization system may be had. In FIG. 1 a water bearing permeable layer 14 is shown immediately below an impervious rock layer 12 and adjacent an underlying similar impervious rock layer 16. Layer comprises all of the formations between layer 12 and the surface. The aquifer layer 14 while preferably being a water bearing sand may also be of a porous limestone from which the water may be similarly purged by a gas under pressure prior to the introduction of liquefied natural gas. The formation comprising the layers 10, 12, and 14 is penetrated by numerous injection and producing wells. A central injection well is shown at 18 extending downwardly through the rock layer 12 and terminating in the upper portion of the aquifer layer 14. After a small bubble of purge gas has been created around injection well 18, other injection wells 22 may be added in relatively close proximity to well 18 to increase the purge gas injection rate as well as future LNG injection capacity. The number of producing and injection wells and their relative spacing can be optimized for the conditions of the specific reservoir and project through well-known reservoir engineering principles. Although a center to periphery pattern is shown for convenience, this is not the only suitable pattern as individual reservoir conditions or project requirements may suggest the use of an end-toend pattern, a five-spot pattern, line-drive pattern, or any other suitable arrangement. A plurality of producing wells 20 are arranged peripherally about the central purge gas injection well 18. All of the wells 18, 20 and 22 are provided with suitable control valves and will be understood to be connected to suitable pumping means (not shown) as required.

In accordance with the novel method of the invention any suitable gas is injected downwardly under pressure through the well 18 at sufiicient pressure to displace the water from the aquifer layer 14. Obviously, to prevent freezing of the displaced water from the aquifer the displacing gas must be above the freezing temperatures of the formation water. As the purge gas is injected through the well 18 an increased hydrostatic pressure is created which tends to cause flow of the water within the area encompassed by the producing wells 20 outward into the surrounding aquifer. If this aquifer is extensive, all or a major portion of the water within the planned storage area can be displaced in this manner. However, pressure differentials can be minimized and the configuration of the storage bubble can be controlled by production of water from. the producing wells 20 during the formation of the storage bubble. When the injected gas reaches an individual producing well, gas and water will be simultaneously produced, with the ratio of gas to water gradually increasing. Prior to gas breakthrough, the relative advance of the gas towards the individual segments of the periphery can be controlled by controlling the relative rates of water production from individual wells or groups of wells. Subsequently, the control can be maintained by controlling the relative production rates of individual wells or groups of wells or by selectively shutting wells 20.

Since the injected gas is less dense than the formation water, gravity effects will tend to cause this gas to partially override the water in the formation and, at very slow rates of injection, the gas would displace water from only the top few feet of the formation, leaving water in the bottom portion. At high injection rates, however, the pressure differentials created will outweigh the gravity effects and water can be displaced from the entire vertical section, This relationship between vertical displacement and injection rates permits control of the vertical thickness of the bubble and thus the'ratio of volume to area. Since the flow of heat into the stored LNG is a direct functionof area, selection of gas injection rate can roughly optimize the rate of revaporization.

The injection of purge gas may be continued until the desired storage bubble has been completed. Alternatively, however, after a sufficient purge gas volume has been injected to create a pre-determined bubble size indicated by the dotted line 26 (perhaps one-third to one-half the ultimate storage volume), injection can be shifted to LNG. The LNG will displace the purge gas ahead of it, with the purge gas continuing to act as a buffer between the waterbeing displaced and the extremely cold LNG, and thus avoid the freezing of displaceable water. It is noted that of the water will not be displaced as some water will be left behind as residual water, which will, of course, be frozen as soon as contacted by the LNG. However, this residual water saturation is low and does not appreciably impair the permeability of the formation. The heat contained in this residual water and the reservoir rock itself will vaporize the initial LNG injected and this vaporized gas will serve as an additional buffer between the LNG and displaceable waters.

Heat will flow indefinitely into the cold sink from the overlying and underlying formations although at a gradually diminishing rate. As the injected LNG approaches the periphery of the bubble, the undisplaced water will be frozen to surround the gas bubble with an impervious ice containment layer 24 of reservoir rock with pores completely filled with ice. In time, this layer will be many hundreds of feet thick.

After the storage bubble is created and the peripheral walls frozen, the bubble is ready for usage. LNG is injected intermittentlyas ships arrive, with more or less continuing withdrawals as needed. Preferably sufiicient heat will be gained from the surrounding strata (predominately from the overlying and underlying forma tions) so that a portion of the injected LNG will be vaporized and natural gas vapor as well as LNG will be produced through the producing wells 20 as desired.

The mixture of gas and liquid natural gas can be separated through gas liquid separation facilities. The gaseous portion can be warmed to acceptable distribution temperatures and routed directly to the gas distribution system. The liquid portion can be sent to conventional revaporization facilities and thence to the distribution system. During peak demand periods, the LNG may also be withdrawn from the injection wells 18 and 22 to increase the amount of LNG available.

Since the revaporized gas will tend to seek the top of the formation and the heavier LNG the bottom, some control can be exercised over the ratio of gas to liquid that is produced from a given well on any given day by utilizing selective completions. This would involve dual sets of perforations through the lower end of the well casing (one set near the top and one near the bottom of the formation) with an appropriate packer and sliding sleeve, dual tubing as other conventional arrangement (not shown).

The ratio of liquid LNG to revaporized gas withdrawn on a given day can also be controlled by production of selected wells including backflowing of injection wells.

In this manner vaporized LNG may, if desired, be retained in the reservoir so that surface revaporization equipment may be operated at near capacity.

While specific methods in accordance with the invention have been illustrated and described in detail to teach the application of the inventive principles, it will be understood that the invention may be practiced in other ways without depa ing from such principles.

What is claimed is:

1. An improved method of storing liquefied natural gas at cryogenic temperatures comprising the steps of introducing a purge gas into a subterranean water bearing stratum at suificient pressure to displace the water from a predetermined area of stratur'n and at a temperature above the freezing point of the formation water, and thereafter introducing the liquefied natural gas into the predetermined area to thereby freeze the water surrounding the predetermined area and form an' impermeable barrier to thereby prevent escape of regasified natural gas vapors emerging from said liquefied natural gas.

2. The method of claim 1 wherein said last mentioned step is started after a volume of purge gas equal to onethird to one-half of the ultimate storage volume has been introduced.

3. The method of claim 1 including the step of producing said displaced water from at least one well in said stratum at a point remote from the point of introduction of said purge gas, and sensing the presence of purge gas at the remote water producing well to ascertain and control the shape of said predetermined area.

4. The method of claim 3 indluding withdrawing natural gas in a gaseous state from said stratum after sulficient heat has been absorbed by said liquefied natural gas from the stratum surrounding said predetermined area.

5. A method of storing and vaporizing super-cool liquefied gas comprising the steps of creating a storage void in an aquifier by introducing a purge gas therein to displace the water from a predetermined area of said aquifer, introducing the super-cool liquefied gas into said storage void to thereby freezeithe water in the aquifer surrounding said predetermined area, and withdrawing vapors of said liquefied gas from said predetermined area after sufiicient heat has been absorbed by said liquefied gas from the aquifer surrounding said predetermined area.

6. The method of claim 5 wherein the stepfof introducing the super-cool liquefied gas is-commenced after a volume of purge gas equal to one-third to one-half of the ultimate storage volume of the storage void has been produced.

7. The method of storing and vaporizing liquefied natural gas (LNG) delivered in 'ifa ship to a consuming area at 259 F. and atmospheric pressure comprising the steps of, drilling a first injection well through a relatively impervious rock layer into water bearing sand stratum immediately therebelow, drilling a plurality of producing wells through said rock stratum into said sand stratum to approximately the same'gg jepth as said injection well, said producing wells being drilled in a substantially circular pattern concentric to and spaced from said injection well, drilling one or more LNG injection wells in close proximity to said first injecition well, injecting a purge gas at a temperature abov *32" F. through said first injection well to displace th ater from the sand stratum and at the same time produfiing water from said producing wells to thereby create la predetermined area in said sand stratum free of waterffclosing said producing wells upon change of production from water to purge gas, introducing liquefied natural gas through said LNG injection wells to thereby freeze the water in said stratum surrounding said predetermined' area, and withdrawing gasified natural gas from said plurality of producing wells.

8. The method of claim wherein the step of injecting purge gas is done at a ratesufficiently slow to create a large diameter predetermined area of minimum depth free of water immediately below, said impervious rock layer, whereby maximum dissipatin of LNG cold will occur in the radial movement of LNG outward from the LNG injection wells to the gas iproducing wells.

References Cited UNITED STATES PATENTS 3,275,078 9/1966 Rieljer 166-305 3,296,805 1/1967 Graham 166-305 3,301,326 1/1967 McNamer 166-285 X 3,304,725 2/1967 Faul coner 61--.5 3,306,354 2/1967 OBfiien 166-305 3,344,607 10/1967 Vigjovich 61.5 3,393,738 7/1968 Ber 'ard et a1. l66305 X OTHER REFERENCES STEPHEN J. NOVOSAD, Primary Examiner US. Cl. X.R.

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