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Número de publicaciónUS3779602 A
Tipo de publicaciónConcesión
Fecha de publicación18 Dic 1973
Fecha de presentación7 Ago 1972
Fecha de prioridad7 Ago 1972
Número de publicaciónUS 3779602 A, US 3779602A, US-A-3779602, US3779602 A, US3779602A
InventoresBeard T, Van Meurs P
Cesionario originalShell Oil Co
Exportar citaBiBTeX, EndNote, RefMan
Enlaces externos: USPTO, Cesión de USPTO, Espacenet
Process for solution mining nahcolite
US 3779602 A
Resumen
The process of solution mining sodium bicarbonate (e.g., nahcolite) from a subsurface sodium bicarbonate containing, oil shale formation with water is improved by conducting leaching operations at a selected temperature greater than 250 DEG F and adjusting pressure to a particular preferred value for the selected leaching temperature.
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United States Patent [191 Beard et al.

[451 Dec. 18, 1973 PROCESS FOR SOLUTION MINING NAI-ICOLITE Thomas N. Beard, Denver, Colo.; Peter Van Meurs, Houston, Tex.

[75] Inventors:

Shell Oil Company, Houston, Tex.

Aug. 7, 1972 Assignee:

Filed:

Appl. No.:

U.S. Cl. 299/5, 166/303 Int. Cl E2lb 43/28 Field of Search 299/4, 5; 166/272,

References Cited UNlTED STATES PATENTS 2,388,009 Pike 299 5 x Pike et a1 299/5 X Papadopoulos et a1 299/5 Primary ExaminerErnest R; Purser Attorney-Theodore E. Bieber [57] ABSTRACT The process of solution mining sodium bicarbonate (e.g., nahcolite) from a subsurface sodium bicarbonate containing, oil shale formation with water is im proved by conducting leaching operations at a selected temperature greater than 250F and adjusting pressure to a particular preferred value for the selected leaching temperature.

6 Claims, 4 Drawing Figures I i-viii 7 I 1 EU um; I 8 I975 sum in; 3

0 0 0% @wwmm w 0 0 0 0 0 Q\.-m.wh; WD Q Q \CSQG KO MEQQ IREOID PATENIED DEC 18 I975 SHEET 2 BF 3 Dam saw Dom QQN ou z E zocqmEqm 252m 0% oux z I 3G9 8 2 m5 815 SE 8 2 E8 E 295%: 3 a

PROCESS FOR SOLUTION MINING NAHCOLITE BACKGROUND OF THE INVENTION Field of the Invention This invention relates to the field of producing minerals from subsurface formations; and more particularly, to a process for solution mining nahcolite from subsurface oil shale formations Description of the Prior Art The recovery of water-soluble minerals from subsurface deposits by solution mining with aqueous fluids is well known. In such a process, aqueous fluid is flowed downa well into contact with a subsurface deposit. The solution dissolves some of the soluble mineral. The mineral-containing solvent is then flowed to the surface where it is treated to remove the dissolved mineral, e.g., by evaporation.

The solubility of most commercially interesting water soluble minerals increases with increasing temperature. Therefore, aqueous solution-mining fluid is often heated to increase its mineral carrying capacity before it is injected into a subsurface mineral deposit. For example, U.S. Pat. No. 1,649,385 issued Nov. 15, 1927, to H. Blumenberg, Jr. teaches a method of solution-mining crystallized boron compounds by using a mixture of hot air and steam.

In the western United States, there are large subsurface oil shale formations which contain substantial amounts of water-soluble, heat-sensitive bicarbonate minerals such as trona and nahcolite. These minerals are present both in inter-bedded substantially pure soluble mineral layers and as dispersed nodules in certain layers which predominently contain oil shale.

It is known that theseheat-sensitive, water-soluble minerals can be solution-mined with hot aqueous solutions. *See, for example, U.S. Pat. 3,050,290, issued Aug. 21, 1962, to N. A. Caldwell et al. A co-pending commonly assigned application of T. N. Beard, Ser.

No. 75,009, filed Sept. 24, 1970, teaches a method of producing oil from such mineral-containing oil-shale formations which includes permeabilization of the formation by dissolution of mineral with hot aqueous solution.

SUMMARY OF THE INVENTION We have now found that the process of removing heat-sensitive, water-soluble bicarbonate minerals from subsurface oil shale deposits by solution-mining with hot aqueous solutions is improved by injecting steam into the formation at a selected temperature greater than 250F, and advantageously, greater than 300F, to leach water-soluble mineral from the formation; maintaining the temperature of fluid in the leached zone greater than 250F; and adjusting pressure in the leached zone to a particular optimum pressure for the selected temperature.

The optimum pressure is that pressure at which the sodium mineral-carrying capacity of the aqueous leaching fluid is at a maximum. At pressures below the optimum, excessive conversion of bicarbonate material to carbonate with attendant precipitation of carbonate leads'to a reduced mineral-carrying capacity. At higher pressures than the optimum, conversion of bicarbonate material to carbonate is inhibited and the mineralcarrying capacity of the leaching fluid is thereby reduced.

BRIEF DESCRIPTION OF THE DRAWINGS FIG. I is a graphical representation of cavity growth rate versus cavity temperature for a nahcolite leaching operation conducted in a nahcolite-containing oil shale formation.

FIG. 2 is a graph of sodium content expressed as equivalent pounds of nahcolite per pound of water for a sodium carbonate saturated, sodium bicarbonatewater system as a function of temperature.

FIG. 3 is a schematic view, partly in cross section, of a solution-mining well equipped for the practice of this invention. FIG. 4 is a schematic view, partly in cross-section, of another well system for use in the practice of this invention.

DESCRIPTION OF A PREFERRED EMBODIMENT Referring to FIG. 3, we see a subsurface oil shale formation 10 containing strata 11 of substantially pure nahcolite (NaHCO and strata 12 which are predominantly oil shale but which contain a substantial amount of nahcolite, e.g. 20 to 40 percent nahcolite dispersed in discreet nodules.

A solution-mining well 13 extends into the oil shale formation 10 from the earth surface. The well 13 has been completed in a conventional manner with casing 14 sealed in place with cement 15. A solution-mining fluid injection tubing string 16 and a solution-mining fluid production tubing string 17 are extended into the well 13. The lower end of the injection tubing 16 is preferably positioned adjacent the top of a zone 9 of the oil shale formation 10 to be solution-mined. The lower end of the production tubingstring is preferably positioned near the bottom of the zone 9.

Pack-off means such as packer 18 may be positioned in the casing 14 above the lower end of the tubing string 16. Production tubing string 17 is provided with suitable means for lifting solution-mining fluid to the surface. For example, pumping apparatus may be positioned adjacent the bottom of production string 17 or the production string 17 may be equipped for gas lift as shown in FIG. 3. In the embodiment illustrated, a pressure actuated gas lift valve 19 is operatively connected to production tubing 17 at a point above packer 18. A conduit 20 for injection gas is connected to the casing 14 at the surface. To lift fluid in the tubing 17, gas is injected through conduit 20 into casing 14. When the pressure of this gas exceeds a certain threshold value, valve 19 opens and admits gas into the interior of tubing 17. This gas lightens the column of fluid in tubing 17 thereby reducing the pressure necessary to cause fluid to flow from the bottom of tubing 17 to the earth surface.

To solution mine nahcolite from formation 10, hot aqueous solution-mining fluid, preferably low quality steam, is injected down tubing 16. This fluid contacts water-soluble minerals in the formation 10 and dissolves them thereby forming a leached zone and, eventually, a cavity 21. The cavity 21 may be at least partially filled with fragmented particles of oil shale and nahcolite 22.

We have found that in leaching formations similar to that shown in FIG. 1 with steam, the cavity growth rate varies logarithmically with the cavity temperature as shown in FIG. 1 and that cavity growth rate is only slightly dependent upon the rate of fluid injection. It is believed that this increase in cavity growth rate with temperature is at least in part due to more rapid thermal fracturing at higher temperatures of oil shale surrounding discreet nahcolite nodules. Such fracturing allows injected aqueous fluid to reach the nahcolite nodule and leach it from the formation leaving an exposed oil shale face which is in turn thermally fractured opening up communication to yet another nodule.

As can be seen in FIG. 1, for temperatures below 250F, growth rate of cavity radius is quite low, less than 0.08 feet per day; whereas at 300F, growth rate is almost doubled to 0.15 feet per day. Thus, for maximum mineral removal, cavity temperature should be maintained above 250F and preferably above 300F.

We have also found that in solution-mining nahcolite from an oil shale formation with aqueous fluid, the rate of mineral recovery can be maximized by selecting an operating temperature for maximum desired cavity growth rate as by reference to FIG. 1, and then during operation adjusting cavity pressure to a pressure at which the sodium carrying capacity of the aqueous leaching fluid is a maximum for the selected cavity temperature. This pressure is less than that required to bydraulically fracture the formation and is greater than the pressure at which nahcolite decomposition to sodium carbonite, carbon dioxide and water is maximized.

Operating in this manner can significantly reduce the energy requirement for carrying out the process since heat can be carried to the formation by relatively low pressure steam. Additionally, water requirements are reduced because the total amount of sodium mineral removed from the cavity 21 by a given volume of leaching luid is maximized.

The particular selected leaching temperature will vary from operation to operation depending upon economic conditions and the desired cavity growth rate for each particular case. Operating pressure for a particular selected temperature is determined from pressure, temperature, saturation relationships such as those given in FIG. 2. That figure shows total sodium concentration in pounds of nahcolite per pound of water for a sodium carbonate saturated, sodium carbonate/- sodium bicarbonatewater system. The graph reflects the amount of nahcolite removed from a nabcolite formation which is present in the solution even though the actual composition of the solution includes both sodium bicarbonate and sodium carbonate generated by nahcolite decomposition. Best results are obtained by operating at the pressure for which the isobar intersects the upper dashed curve at the selected operating temperature. Good results are obtained at pressures varying as much as percent above or below this pressure.

Looking at FIG. 2 for a temperature of 400, it can be seen that at that temperature and about 200 psi only sodium bicarbonate is present in the solution (as given by the lower dotted line of the Figure) and that the total amount of equivalent nahcolite dissolved is around 0.55 pounds per pound of water. However as pressure is increased, the amount of sodium bicarbonate in the system increases until at about 1,000 psi, the total sodium content is equivalent to about 1.25 pounds per pound of water even though sodium carbonate saturation remains the same. Further pressure increase to a pressure for which the extention of an isobar would intersect the 400F isotherm above the upper dotted line results in the precipitation of sodium bicarbonate and an effective reduction in the equivalent nahcolite saturation of the system. Thus at 400F, leaching operations can be maximized if pressure in the cavity 21 is maintained at about 1,000 psi. To maintain this pressure, it is necessary to artiflcally lift fluid from the cavity 21 if the fluid head of solution-mining fluid in production tubing 17 is greater than 1,800 psi. Therefore, the well 13 is provided with a gas lift system as heretofore described.

FIG. 4 shows a well 22 extending into the formation 10 that is completed in a manner particularly advantageous for the practice of this invention. The well 22 is completed with casing 23 which extends into the nahcolite-containing formation 10. The casing 23 is cemented in place with cement 24 and perforated adjacent formation 10 with perforations 25 to open the interior of the casing into communication with the formation 10.

A liquid production tubing string 26 and a gas production tubing string 27 extend into the well from the surface. The liquid production tubing string 26 preferably terminates at the point adjacent the bottom of the interval of the formation 10 to be treated whereas the gas production tubing string 27 terminates at a point above the lower end of the liquid production tubing 26 but below the perforations 25. The interior of the casing is preferably sealed to fluid flow by pack-off means such as packer 28 at a point above the terminal ends of the two tubing strings 26 and 27 and below the perforations 25.

The liquid production tubing string is provided with means for lifting liquid from the formation 10 to the surface. This may be a down-hole pump or gas lift means (as illustrated in FIG. 4) in which a gas injection string extends into the well 22 and is connected in communication with production tubing 26 at a point near the lower end of that tubing. The particular point of intersection will be determined by the fluid head desired to be maintained in liquid production string 26.

In operation, hot aqueous fluid having a temperature greater than 250 and preferably greater than 300F is injected into casing 23 through conduit 30 and then down the casing until it passes through perforations 25 into the formation 10. This fluid leaches nahcolite from the formation creating a cavity 31 which may be filled with fragmented particles of oil shale and nahcolite 32. The aqueous fluid advantageously contains high proportion of steam which upon contacting the formation 10 condenses to form a liquid phase capable of carrying dissolved mineral in solution. Simultaneously with the injection of steam down the casing 22, liquid is produced from the lower part of the cavern 31 through production tubing string 26 and gas is produced from the cavern 31 through gas production tubing string 27. The production rate of these fluids is preferably adjusted to maintain the pressure in the cavern 31 at a particular preferred value for the selected temperature operation. The removal of gas through the tubing 26 draws both steam and CO from the cavern 31. This results in a reduction of the partial pressure of CO in the cavern and further promotes the decomposition of nahcolite (NaHCO to sodium carbonate, CO and water (e.g., 2 NaHCO, Na CO3 C0, H O).

Both FIGS. 3 and 4 illustrates single well systems for the practice of this invention. However, it should be understood that two or more wells may at any one time be in communication with any particular cavern 21 or 31 or other permeabilized zone. In such a case, aqueous fluid may be injected into the formation through one well and produced from the formation through a separate well.

Both FIGS. 3 and 4 illustrate the process after a cavity 21 or 31 has been formed. It should be understood that in many cases, initial treatment will be confined to a substantially cylindrical wellbore and that the cavern is formed only after a period of leaching has expanded the wellbore radically.

We claim as our invention:

1. In a method for solution-mining heat sensitive water-soluble sodium bicarbonate minerals from a subsurface bicarbonate mineral containing oil-shale formation of the type wherein a hot aqueous fluid is injected into the formation to leach bicarbonate mineral therefrom, the improvement comprising:

injecting steam into the formation at a temperature greater than 250F to leach water-soluble mineral from the formation and thereby create a leached zone; maintaining the temperature of fluid in the leached zone at a temperature greater than 250F; and

adjusting pressure in the leached zone to an optimum pressure at which the sodium mineral carrying capacity of water at the selected temperature is a maximum.

2. The method of claim 1 further comprising producing liquid containing dissolved sodium bicarbonate from a liquid layer adjacent the bottom of the leached zone through a production tubing string using artificial lift means to lift the liquid to the surface.

3. The method of claim 2 further comprising withdrawing gas containing CO from a gas layer adjacent the top of the leached zone.

4. A method for solution-mining nahcolite from a subsurface oil-shale formation comprising the steps of:

traversing a nahcolite-containing zone of the oilshale formation with a well;

extending a production string of tubing into the well to a point adjacent the bottom of the nahcolitecontaining zone;

extending an injection tubing string into the well to a point adjacent the top of the nahcolite-containing zone; injecting steam into contact with the nahcolite containing zone through the injection tubing at a temperature such that upon contacting the formation at least some of the steam condenses to liquid which liquid flows to the bottom of the nahcolite zone leaching nahcolite therefrom; producing nahcolite-containing aqueous liquid from the nahcolite zone through the production tubing;

controlling the rate and temperature of steam injection to maintain a selected temperature of aqueous liquid adjacent the bottom of the nahcolite zone;

adjusting the pressure in the aqueous liquid adjacent the bottom of the nahcolite zone to an operating pressure substantially equal to that pressure at which the amount of sodium mineral the aqueous liquid can carry at the selected temperature is a maximum; and

maintaining the pressure in the aqueous liquid adjacent the bottom of the nahcolite zone substantially constant at the operating pressure.

5. The method of claim 4 wherein the operating pressure is a pressure less than that required to hydraulically fracture the formation.

6. The method of claim 5 wherein the operating pressure is greater than the pressure at which the rate of nahcolite decomposition is a maximum at the selected temperature.

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Clasificaciones
Clasificación de EE.UU.299/5, 166/303, 423/206.2
Clasificación internacionalE21B43/00, E21B36/00, E21B43/28
Clasificación cooperativaE21B43/281, E21B36/00
Clasificación europeaE21B43/28B, E21B36/00