US20160356118A1

US20160356118A1 - Method to minimize brine contamination and/or gas migration during in situ trona solution mining

Info

Publication number: US20160356118A1
Application number: US14/135,349
Authority: US
Inventors: Ryan Schmidt; Matteo PAPERINI; Ronald O. HUGHES; Herve CUCHE
Original assignee: Solvay SA
Current assignee: Solvay SA
Priority date: 2012-12-21
Filing date: 2013-12-19
Publication date: 2016-12-08

Abstract

A method for in situ solution mining of trona in which an aqueous solvent dissolves trona and forms a brine, which comprises: applying a hydraulic pressure greater than the overburden pressure at an interface between trona roof and overburden to lithologically displace the overburden from the trona roof and form a gap; flowing a liquid settable and/or sealing composition into such interface gap and allowing such composition to solidify inside such gap to form a water-impermeable and optionally gas-impermeable barrier inside. This technique should limit contamination from the overburden; should seal or plug fractures transversing the trona roof; should prevent water infiltration from overburden; and/or should minimize gas migration into the overburden from the cavity. The lithological displacement whereby the interface gap is formed may be carried out at the same time as the composition is flowed inside the gap being formed.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

TECHNICAL FIELD OF THE INVENTION

The present invention relates to methods for in situ solution mining of an evaporite ore from an underground cavity which uses a solvent to dissolve ore to form a brine. More particularly, a first aspect relates to a method for preventing brine contamination from overburden for the solution mining of trona ore, where contaminants such as chloride, sulfate and water-soluble organics are present in one or more overlying strata in the overburden above the trona bed being mined; and a second aspect relates to a method for minimizing gas migration into the overburden from an underlying cavity which is solution mined in the trona ore.

BACKGROUND OF THE INVENTION

Sodium carbonate (Na₂CO₃), or soda ash, is one of the largest volume alkali commodities made world wide with a total production in 2008 of 48 million tons. Sodium carbonate finds major use in the glass, chemicals, detergents, paper industries, and also in the sodium bicarbonate production industry. The main processes for sodium carbonate production are the Solvay ammonia synthetic process, the ammonium chloride process, and the trona-based processes.
Trona-based soda ash is obtained from trona ore deposits in the U.S. (southwestern Wyoming in Green River, in California near Searles Lake and Owens Lake), Turkey, China, and Kenya (at Lake Magadi) by underground mechanical mining techniques, by solution mining, or lake waters processing.
Crude trona is a mineral that may contain up to 99% sodium sesquicarbonate (generally about 70-99%). Sodium sesquicarbonate is a sodium carbonate-sodium bicarbonate double salt having the formula (Na₂CO₃.NaHCO₃.2H₂O) and which contains 46.90 wt. % Na₂CO₃, 37.17 wt. % NaHCO₃and 15.93 wt. % H₂O. Crude trona also contains, in lesser amounts, sodium chloride (NaCl), sodium sulfate (Na₂SO₄), organic matter, and insolubles such as clay and shales. A typical analysis of the trona ore mined in Green River is shown in TABLE 1.

	TABLE 1

	Constituent	Weight Percent

	Na₂CO₃	43.2-45
	NaHCO₃	33.7-36
	H₂O (crystalline and free moisture)	15.3-15.6
	NaCl	0.004-0.1
	Na₂SO₄	0.005-0.01
	Insolubles	3.6-7.3

Other naturally-occurring sodium (bi)carbonate minerals from which sodium carbonate and/or bicarbonate may be produced are known as nahcolite, a mineral which contains mainly sodium bicarbonate and is essentially free of sodium carbonate and known as “wegscheiderite” (also called “decemite”) of formula: Na₂CO₃.3 NaHCO₃.
In the United States, trona and nahcolite are the principle source minerals for the sodium bicarbonate industry. While sodium bicarbonate can be produced by water dissolution and carbonation of mechanically mined trona ore or of soda ash produced from trona ore, sodium bicarbonate can be produced also by solution mining of nahcolite. The production of sodium bicarbonate typically includes cooling crystallization or a combination of cooling and evaporative crystallization.
The large deposits of mineral trona in the Green River Basin in southwestern Wyoming have been mechanically mined since the late 1940's and have been exploited by five separate mining operations over the intervening period. In 2007, trona-based sodium carbonate from Wyoming comprised about 90% of the total U.S. soda ash production.
To recover valuable alkali products, the so-called ‘monohydrate’ commercial process is frequently used to produce soda ash from trona. When the trona is mechanically mined, crushed trona ore is calcined (i.e., heated) to convert sodium bicarbonate into sodium carbonate, drive off water of crystallization and form crude soda ash. The crude soda ash is then dissolved in water and the insoluble material is separated from the resulting solution. A clear solution of sodium carbonate is fed to a monohydrate crystallizer, e.g., a high temperature evaporator system generally having one or more effects (sometimes called ‘evaporator-crystallizer’), where some of the water is evaporated and some of the sodium carbonate forms into sodium carbonate monohydrate crystals (Na₂CO₃.H₂O). The sodium carbonate monohydrate crystals are removed from the mother liquor and then dried to convert the crystals to dense soda ash. Most of the mother liquor is recycled back to the evaporator system for additional processing into sodium carbonate monohydrate crystals.
Most mechanical mining operations to extract trona ore practice some form of underground ore extraction using techniques adapted from the coal and potash mining industries. A variety of different systems and mechanical mining techniques (such as longwall mining, shortwall mining, room-and-pillar mining, or various combinations) exist. Although any of these various mining techniques may be employed to mine trona ore, when a mechanical mining technique is used, nowadays it is preferably longwall mining.
The Wyoming trona deposits are evaporites, and hence form various substantially horizontal layers (or beds). These major deposits consist of 25 near horizontal beds varying from 4 feet (1.2 m) to about 36 feet (11 m) in thickness and separated by layers of shales. Depths range from 400 ft (120 m) to 3,300 ft (1,000 m). These deposits generally contain from about 70% to 95% sesquicarbonate, with the impurities being mainly dolomite and calcite-rich shales and shortite. Some regions of the basin contain soluble impurities, most notably halite (NaCl). These extend for about 1,000 square miles (about 2,600 km²), and it is estimated that they contain over 75 billions tons of soda ash equivalent, thus providing reserves adequate for reasonably foreseeable future needs.
Presently, trona from the Wyoming deposits is economically recovered by mechanical mining mainly from a main trona bed no. 17 in the Green River Basin, averaging a thickness of about 8 feet (2.4 m) to about 11 feet (3.3 m). Bed No. 17 is located from approximately 1,200 feet (about 365 m) to approximately 1,600 feet (about 488 m) below ground surface. This main bed is located below substantially horizontal layers of sandstones, siltstones and mainly unconsolidated shales. In particular, within about 400 feet (about 122 m) above the main trona bed are layers of mainly weak, laminated green-grey shales and oil shale, interbedded with bands of trona from about 4 feet (about 1.2 m) to about 5 feet thick (about 1.5 m). Immediately below the main trona bed lie substantially horizontal layers of somewhat plastic oil shale, also interbedded with bands of trona. Both overlying and underlying shale layers contain methane gas.
All mechanical mining techniques require miners and heavy machinery to be underground to dig out and convey the ore to the surface, including sinking shafts of about 800-2,000 feet (about 240-610 meters) in depth. The cost of the mechanical mining methods for trona is high, representing as much as 40 percent of the production costs for soda ash. Furthermore, recovering trona by these methods becomes more difficult as the thickest beds (more readily accessible reserves) of trona deposits with a high quality (less contaminants) were exploited first and are now being depleted. Thus the production of sodium carbonate using the combination of mechanical mining techniques followed by the monohydrate process is becoming more expensive, as the higher quality trona deposits become depleted and labor and energy costs increase. Furthermore, development of new reserves is expensive, requiring a capital investment of as much as hundreds of million dollars to sink new mining shafts and to install related mining and safety (ventilation) equipment.
Additionally, because some shale is also removed during mechanical mining, this extracted shale must then be transported along with the trona ore to the surface refinery, removed from the product stream, and transported back into the mine, or a surface waste pond. These insoluble contaminants not only cost a great deal of money to mine, remove, and handle, they provide very little value back to the mine and refinery operator. Additionally, the crude trona is normally purified to remove or reduce impurities, primarily shale and other nonsoluble materials, before its valuable sodium content can be sold commercially as: soda ash (Na₂CO₃), sodium bicarbonate (NaHCO₃), caustic soda (NaOH), sodium sesquicarbonate (Na₂CO₃.NaHCO₃.2H₂O), a sodium phosphate (Na₅P₃O₁₀) or other sodium-containing chemicals.
Recognizing the economic and physical limitations of underground mechanical mining techniques, solution mining of trona has been long touted as an attractive alternative with the first patent U.S. Pat. No. 2,388,009 entitled “Solution Mining of Trona” issued to Pike in 1945.
In its simplest form, solution mining of trona is carried out by contacting trona ore with a solvent such as water or an aqueous solution to dissolve the ore and form a liquor (also termed ‘brine’) containing dissolved sodium values. For contact, the water or aqueous solution is injected into a cavity of the underground formation, to allow the solution to dissolve as much water-soluble trona ore as possible, and then the resulting brine is flowed to the surface (pumped or pushed out). A portion of the brine can be used as feed material to process it into one or more sodium salts, while another portion may be re-injected for further contact with the ore.
Pike in U.S. Pat. No. '009 discloses a method of producing soda ash from underground trona deposits in Wyoming by injecting a heated brine containing substantially more carbonate than bicarbonate which is unsaturated with respect to the trona, withdrawing the solution from the formation, removing organic matter from the solution with an adsorbent, separating the solution from the adsorbent, crystallizing, and recovering sodium sesquicarbonate from the solution, calcining the sesquicarbonate to produce soda ash, and re-injecting the mother liquor from the crystallizing step into the formation.
Solution mining of trona could indeed reduce or eliminate the costs of underground mining including sinking costly mining shafts and employing miners, hoisting, crushing, calcining, dissolving, clarification, solid/liquid/vapor waste handling and environmental compliance. The numerous salt (NaCl) solution mines operating throughout the world exemplify solution mining's potential low cost and environmental impact. But a trona ore containing sodium carbonate and sodium bicarbonate has relatively low solubility in water at room temperature when compared with other evaporite minerals, such as halite (mostly sodium chloride) and potash (mostly potassium chloride), which are mined “in situ” with solution mining techniques.
Chloride salts of some naturally occurring minerals in roof shales above most trona beds, notably sodium chloride, are highly soluble. In the example of trona Bed 17 in Wyoming, the bed is bounded by a relatively impervious oil shale layer in the floor, and softer, more friable, ‘green shale’ layers in the roof and upper zones of the trona itself. Owing to the complicated process of deposition of the trona beds, the roof shales tend to contain significant amounts of chloride-laden minerals, as well as other water-soluble contaminants (e.g., sulfates). It is these upper shales that pose the greatest potential for chloride contamination.
Since trona has a relatively low solubility in water, sodium chloride will displace the solubility of sodium carbonate and sodium bicarbonate to a significant degree. Due to chloride's high solubility, once chloride is in solution in the brine or brine, it is economically not feasible to separate it from the desirable solutes. The only way for chloride to leave the surface refinery which processes the brine is either through brine purged to waste streams (carrying with it valuable mother liquor solution as well) and/or through the final product where chloride is a considerable contaminant for customers even at very small levels.
When using mechanical mining, chloride contamination of the brine can be minimized by not mining the trona ore close to the trona roof. Since the trona bed height is generally uneven, the mining machines are set to remove up to a certain height of trona bed, leaving behind some trona resources near the roof but this sacrifice of contaminated ore allows the mine operator to operate day-to-day without having to adjust the mining height and to predictably obtain a brine with an acceptable levels in chloride, sulfate, and dissolved organics which can be handled by the surface refinery.
For all in-situ trona solution mining processes, avoiding chloride contamination poses a more significant challenge, as the ‘chloride poisoning’ problem is derived from the environment of deposition of the trona beds. If the roof shales, or waters from brackish aquifers above the trona stratum are allowed to come in contact with the solvent in significant volumes, they are quite likely to ‘poison’ the brine and render it unsuitable for refining. In short, chloride contamination (‘chloride poisoning’) of the brine during solution mining must be avoided.
Implementing a solution mining technique without the negative impact of increased mining hazards and increased costs to exploit sodium (bi)carbonate-containing ores like trona ore, especially those ores whose thin beds and/or deep beds of depth greater than 2,000 ft (610 m) which are currently not economically viable via mechanical mining techniques, has proven to be quite challenging.
Most trona solution mining approach uses two or more vertical wells drilled into the trona bed, and a low pressure connection is established by hydraulic fracturing or directional drilling. U.S. Pat. No. 3,050,290 entitled “Method of Recovery Sodium Values by Solution Mining of Trona” by Caldwell et al. discloses a process for solution mining of trona that suggests using a mining solution at a temperature of the order of 100-200° C. This process requires the use of recirculating a substantial portion of the mining solution removed from the formation back through the formation to maintain high temperatures of the solution. A bleed stream from the recirculated mining solution is conducted to a recovery process during each cycle and replaced by water or dilute mother liquor. U.S. Pat. No. 3,119,655 entitled “Evaporative Process for Producing Soda Ash from Trona” by Frint et al discloses a process for the recovery of soda ash from trona and recognizes that trona can be recovered by solution mining. This process includes introduction of water heated to about 130° C., and recovery of a solution from the underground formation at 90° C.
Directional drilling from the ground surface has been used to connect dual wells for solution mining bedded evaporite deposits and the production of sodium bicarbonate, potash and salt. Nahcolite solution mining utilizes directionally drilled boreholes and a hot aqueous solution comprised of dissolved soda ash, sodium bicarbonate and salt. Development of nahcolite solution mining cavities by using directionally drilled horizontal holes and vertical drill wells is described in U.S. Pat. No. 4,815,790, issued in 1989 to E. C. Rosar and R. Day, entitled “Nahcolite Solution Mining Process”. The use of directional drilling for trona solution mining is described in U.S. Patent Application Pre-Grant Publication No. US 2003/0029617 entitled “Application, Method and System For Single Well Solution Mining” by N. Brown and K. Nesselrode.
However, to improve the lateral expansion of a solution mined cavity in the evaporite deposit, multiple boreholes are needed, either by a plurality of well pairs for injection and production and/or by a plurality of lateral boreholes in various configurations such as those described in U.S. Pat. No. 8,057,765, issued in November 2011 to Day et al, entitled “Methods for Constructing Underground Borehole Configurations and Related Solution Mining Methods”. The cost of drilling horizontal boreholes and/or of directional drilling can add up. As a result, the benefit in cost savings sought by using solution mining may be negated by the use of expensive drilling operations to improve lateral development of cavity and/or expanding mining area.
Alternatively or additionally, in order to force and control the expansion of the cavity in the horizontal direction, the contact between the solvent and the roof of the ore may be prevented by a blanket fluid less dense than the solvent (such as a liquid lighter than water, e.g., diesel or liquefied petroleum gas, or a gas, e.g., pressurized air). This blanket is also useful to minimize contamination of the solvent and resulting brine from the overburden. However, because the blanket prevents contact of solvent with a large surface area of trona on the cavity ceiling, the dissolution rate can be greatly reduced.
As explained previously, a bed of trona ore typically overlays a floor made of oil shale, and shale bands typically overlays the roof of the trona ore, Oil shale is a substantially water-insoluble incongruent material whereby the lower (floor) and upper (roof) interfaces between trona and oil shale form a natural plane of weakness. The comparative tensile strengths, in pounds per square inch (psi) or kilopascals (kPa), of trona and shale in average values are substantially as follows:

- Shale: 70-140 psi (482-965 kPa)
- Trona: 290-560 psi (2,000-3,861 kPa)

Both the immediately overlying shale layer and the immediately underlying shale layer are substantially weaker than the main trona bed. Recovery of the main trona bed, accordingly, essentially comprises removing the only strong layer within its immediate vicinity.
If a sufficient amount of hydraulic pressure is applied at these interfaces, the two dissimilar substances (trona and shale) should easily separate. A separation at the floor interface can be obtained by lifting the trona bed and its overburden from the underlying oil shale thereby exposing a large free-surface of trona upon which a suitable solvent can be introduced for in situ solution mining and/or a similar separation at the roof interface can be obtained by lifting the overburden from the underlying trona ore.
In the late 1950's-early 1960's, hydraulic fracturing of trona has been proposed, claimed or discussed in patents as a means to connect two wells positioned in a trona bed by FMC Corporation. See for example U.S. Pat. No. 2,847,202 (1958) by Pullen, entitled “Methods for Mining Salt Using Two Wells Connected by Fluid Fracturing”; U.S. Pat. No. 2,952,449 (1960) by Bays, entitled “Method of Forming Underground Communication Between Boreholes”; U.S. Pat. No. 2,919,909 (1960) by Rule entitled “Controlled Caving For Solution Mining Methods”; U.S. Pat. No. 3,018,095 (1962) by Redlinger et al, entitled “Method of Hydraulic Fracturing in Underground Formations”; and GB 897566 (1962) by Bays entitled “Improvements in or relating to the Hydraulic Mining of Underground Mineral Deposits”.
In the 1980's, a trona solution mine attempt by FMC Corporation involved connecting multiple conventionally drilled vertical wells along the base of a preferred trona bed by the use of hydraulic fracturing. FMC published a report (Frint, Engineering & Mining Journal, September 1985, “FMC's Newest Goal: Commercial Solution Mining Of Trona” including “Past attempts and failures”) promoting the hydraulic fracture well connection of well pairs as the new development that would commercialize trona solution mining. According to FMC's 1985 article though, the application of hydraulic fracturing for trona solution mining was found to be unreliable. Fracture communication attempts failed in some cases and in other cases gained communication between pre-drilled wells but not in the desired manner. The fracture communication project was eventually abandoned in the early 1990's.
These attempts of in situ solution mining of virgin trona in Wyoming were met with less than limited success and technologies using hydraulic fracturing to connect wells in a trona bed failed to mature.
In the field of oil and gas drilling and operation however, hydraulic fracturing is a mainstay operation, and it is estimated that more than 60% new wells in 2011 used hydraulic fracturing to extract shale gas. Such hydraulic fracturing often employs directional drilling with a horizontal section within a shale porous formation for the purpose of opening up the formation and increasing the flow of gas therefrom to a particular single well using multi-fracking events from one horizontal borehole in the formation.
Through this technique, it has been established that fractures produced in formations should be approximately perpendicular to the axis of the least stress and that in the general state of stress underground, the three principal stresses are unequal (anisotropic conditions). Where the principal pressure on the formation is the pressure of the overburden, these fractures tend to develop in a vertical or inverted conical direction. Horizontal fractures cannot be produced by hydraulic pressures less than the total pressure of the overburden. At sufficiently shallow depths, injection pressures slightly greater than the pressure of the overburden should favor the development of a horizontal fracture, particularly in the case where the desirable target fracture lies along a known plane of weakness between two incongruent materials such as the interface between trona and oil shale.
In fracturing between spaced wells in dense underground formations, such as mineral formations and the like for the purpose of removing the mineral deposits and the like, by solution flowing between adjacent wells, the ‘fracking’ methods used in the oil and gas industry are not suitable to accomplish the desired results. Because the depth of the hydraulically-fractured shale formation is generally greater than 1,000 meters (3280 ft), the injection pressures in oil and gas field are high, even though they are still less than the overburden pressure; this favors the formation of vertical fractures which increases permeability of the exploited shale formation. The main goal of ‘fracking’ methods in the oil and gas industry is to increase the permeability of shale. Overburden gradient is generally estimated to be between 0.75 psi/ft (17 kPa/m) and 1.05 psi/ft (23.8 kPa/m), thus what is called the fracture gradient′ used in oil and gas fracking is less than the overburden gradient, preferably less than 1 psi/ft (22.6 kPa/m), preferably less than 0.95 psi/ft (21.5 kPa/m), sometimes less than 0.9 psi/ft (20.4 kPa/m). The fracture gradient′ is a factor used to determine formation fracturing pressure as a function of well depth in units of psi/ft. For example, a fracture gradient of 0.7 psi/ft (15.8 kPa/m) in a well with a vertical depth of 2,440 m (8,000 ft) would provide a fracturing pressure of 5,600 psi (38.6 MPa).
Water-soluble evaporite formations, and particularly trona formations, usually consist in nearly horizontal beds of various thicknesses, underlain and overlain by water-insoluble sedimentary rocks like shale, mudstone, marlstone and siltstone. The surface of separation between trona and the underlying or overlying non-evaporite stratum is usually sharply defined and at any given point lies substantially in a horizontal plane. In the U.S. Green River Basin, the depth of the surface of separation between the trona and oil shale strata is shallow, typically 3,000 ft (914 m) or less, preferably a depth of 2,500 ft (762 m) or less, more preferably a depth of 2,000 ft (610 m) or less. Unlike the oil and gas exploration from porous/permeable shale formations where it is desirable to produce numerous vertical fractures near the center of the shale formation to recover the most oil and/or gas there from, in the recovery of a soluble mineral from underground evaporite formations, it is desirable to produce a single fracture substantially along the lower interface between the floor of the trona ore to be removed and the top of the underlying stratum so that the soluble trona will be dissolved from the bottom up.
This bottom-up approach for dissolving trona ore from a bed offers a number of advantages. The less concentrated and less saturated solvent flowing along the floor of the evaporite stratum rises to a top layer of the solvent body and contacts the floor of the trona stratum, dissolves the evaporite mineral therefrom and as the solvent becomes more saturated, settles to a lower layer of the solvent body so that the top of the cavity of the evaporite stratum is always exposed to dissolution by less concentrated solvents. The insoluble materials present in the evaporite ore bed can settle through the underlying solvent layer to the bottom of the solution-mining cavity and deposit thereon so that only clear solutions are recovered from the production wells. A further advantage is that the bottom-up approach will help to avoid contamination of the solvent from chloride-rich minerals typically found in the green shale layers found above the trona bed.
In reality, the ideal situation of a sole horizontal fracture is not likely to happen even with careful estimation of an optimum fracture gradient. A mineral deposit is a natural material that has been subjected to tectonic forces which have created weakness planes and natural fractures that extend away from the desired separation interface and such interface imperfections between mineral/shale strata would permit the solvent to flow in various undesirable directions. The application of hydraulic pressure (induced hydraulic fracturing) thus will develop both vertical and horizontal fractures. At shallow depths though (e.g., less than 800 m deep), the horizontal fracture development should be predominant but with vertical fractures still occurring.
Transverse fractures (vertical or slanted with respect to the main line interface) which cross through a portion of the thickness of the evaporite stratum are not in themselves bad since they do provide additional free mineral surface for dissolution. However, these fractures will likely cross layers containing other minerals, and because the other mineral(s) may be soluble in the same solvent as the desirable mineral, these other mineral(s) may be considered ‘contaminants’. As an example, halite (NaCl) and other chloride based minerals are known to occur in shales that overlay the trona beds. If solvent flow in these transverse fractures is allowed to occur so as to reach contaminated overlying layers, this would allow contaminants from these overlying layers to contact the solvent, to dissolve into the solvent, and to “poison” the resulting brine rendering it useless or at least very expensive for further processing. Such poisoning by sodium chloride from these minerals may occur during solution mining of trona, and it is suspected that the solution mining efforts by FMC in the 1980's in the Green River Basin were mothballed in the 1990's due to high NaCl contamination.
Therefore, it is desirable to carry out in-situ solution mining in such a way to avoid bringing significant volumes of these undesirable water-soluble minerals to come into contact with the solvent.
The present invention thus proposes a method for preventing contamination of brine from overburden, such as minimizing contact and dissolution of water-solution contaminants in one or more overlying strata with the aqueous solvent used for solution mining of trona ore and/or reducing leakage of contaminant-laden water percolating from overburden into the ore cavity which is being mined.

SUMMARY OF THE INVENTION

To allow for the development of a bottom-up solution mining approach of a shallow-depth evaporite mineral ore stratum (e.g., trona stratum or bed) to dissolve a desired solute (e.g., sodium sesquicarbonate) in horizontal or near-horizontal plane, Applicants have developed, in a first embodiment of a first aspect, a method for minimizing brine contamination from overburden, particularly from the immediately overlying non-evaporite stratum or strata.
One advantage of such method according to this embodiment is to prevent or limit contact of the ore roof with the solvent and thereby eliminate the potential contamination by undesirable (inorganic and/or organic) water-soluble contaminants from minerals through dissolution from roof material and interburden.
Another advantage of such method is to prevent seepage of water percolating downward through the overburden, particularly through a contaminant-containing layers or band in the interburden into the ore cavity to be mined or being mined and thus avoiding poisoning of the solvent used to dissolve the ore and/or the resulting brine being generated from such ore dissolution.
Yet another advantage of such method is to prevent fractures within the ore stratum (whether they be native and/or induced fractures) to grow beyond the ore roof so as to lessen the flow paths of least resistance which would cause the solvent and brine to escape from the confines of the trona stratum being mined.
According to the first embodiment of the first aspect to the present invention, the method relates to the in situ solution mining of an ore bed containing a desired water-soluble solute in a manner effective to dissolve the desired solute in an aqueous solvent while preventing or limiting contact of the aqueous solvent with the roof material and thereby eliminating the potential contamination by undesirable (inorganic and/or organic) solutes by dissolution of some ore roof material.
For example, in the case of trona solution mining, the method according to the first embodiment of the first aspect thereby minimizes or even eliminates the potential contamination of the resulting brine by undesirable chloride, sulfate, and/or water-soluble organic compounds originating from the overburden.
In particular terms, in an underground formation containing a trona stratum comprising sodium sesquicarbonate lying above one or more substantially-insoluble strata containing water-soluble contaminants selected from the group consisting of chloride, sulfate, and water-soluble organics, said trona stratum comprising an ore roof with a parting upper interface above which is defined an overburden up to the ground and below which an aqueous solvent will be injected in a cavity to dissolve trona and to form a brine which is recovered at least in part at the ground surface, according to the first embodiment of the first aspect to the present invention, the method for minimizing brine contamination from overburden during in situ trona solution mining of a cavity formed in the trona stratum comprises:
(a) applying a hydraulic pressure which is greater than the overburden pressure at the upper interface to lithologically displace the overburden from the trona roof, thereby forming an interface gap;
(b) flowing a composition selected from the group consisting of a liquid settable composition, a sealing agent, and combinations thereof into the upper interface gap; and
(c) allowing such liquid composition to stay into the upper interface gap for a time sufficient to form a barrier inside said upper interface gap, wherein such barrier is water-impermeable and optionally gas-impermeable.
A water-impermeable barrier may also be impermeable to gas, such as methane, air, nitrogen, CO₂, or any combinations thereof.
The steps (a) and (b) may be performed at the same time by injecting the composition selected from the group consisting of the liquid settable composition, the sealing agent, and combinations thereof to apply said hydraulic pressure at the upper interface and for its flowing into said upper interface gap.
The step (b) may be carried out by injection the composition selected from the group consisting of the liquid settable composition, the sealing agent, and combinations thereof via a vertical well which is drilled from the ground surface through the trona stratum and past the floor of the trona bed, and wherein the vertical well is cased and cemented through its entire length, but comprises an in situ injection zone being in fluid communication with the upper interface, said in situ injection zone of said vertical well comprising a downhole end opening and/or casing perforations.
The hydraulic pressure may be applied in step (a) by using a fracture gradient between 0.95 psi/ft and 1.5 psi/ft, preferably between 1 psi/ft and 1.3 psi/ft, more preferably between 1.05 psi/ft and 1.15 psi/ft; and the hydraulic pressure in step (b) is maintained to the hydraulic pressure used in step (a) when steps (a) and (b) are not carried out simultaneously.
The liquid settable composition may comprise water-insoluble particles, optionally water-soluble particles, a binder, water, optionally one or more additives for controlling viscosity and/or setting time, density, or a catalyzing agent. For example, the liquid settable composition may comprise calcium compound; fused or colloidal silica or silica flour; water-insoluble matter recovered from a mechanically-mined mineral after its dissolution in water or aqueous medium; tailings (insolubles) recovered from a mineral surface refinery; biological solid matter; agricultural solid matter; sand; cementing compositions, bentonite, fly ash, slag, aggregate, plastic, rubber, at least one standard cementing material used in well completion or construction activities; one or more polymer resin (such as epoxy resin); or combinations thereof.
The liquid settable composition is preferably a cementing composition.
The sealing agent may comprise water-insoluble particles, said water-insoluble particles comprising at least one water-insoluble calcium compound, fused or colloidal silica, water-insoluble matter recovered from a mechanically-mined mineral after its dissolution in water or aqueous medium, tailings recovered from a mineral surface refinery, biological solid matter, agricultural solid matter, sand, cement, or any combinations thereof.
The liquid composition may be a liquid settable and sealing composition.
The upper interface of the trona stratum is preferably at a shallow depth of 2,500 feet or less.
The defined upper interface is preferably horizontal or near-horizontal (with a dip of 5 degrees or less), but not necessarily.
The step (c) may be carried out for a time sufficient to allow the water-impermeable barrier to achieve a compressive strength of at least 2300 psi or at least 2500 psi, preferably of at least 3000 psi, more preferably of at least 3500 psi.
The composition injected into the upper interfacial gap in step (b) may be selected and the step (c) may be carried out in order for the formed water-impermeable barrier to also be gas-impermeable.
When the composition used in step (b) is a liquid settable composition, the step (c) may be carried out for a setting time period of at least 24 hours to permit the water-impermeable barrier to set completely.
The method may further comprise:
(d) releasing the hydraulic pressure after the barrier is formed in the upper interface gap in order to form a tight seal between the barrier and the immediately-above stratum and between the barrier and the trona ore immediately located underneath the barrier;
e) forming the cavity in the trona stratum at or above a floor interface between the trona stratum and an underlying substantially water-insoluble stratum, such as an oil shale, preferably after steps (a)-(d) are performed; said cavity formation step (e) comprising:

- (e1) lithological displacement of the trona stratum at the floor interface by injecting a lifting fluid at the floor interface through the same well through which the liquid settable composition and/or sealing agent is injected in step (b) or through a different well; or
- (e2) forming at least one uncased horizontal borehole from a directionally drilled well, said at least one uncased horizontal borehole being in fluid communication with the well through which the liquid settable composition and/or sealing agent is injected in step (b).

The trona stratum may be immediately above a substantially water-insoluble stratum and comprises a defined parting floor interface between the two strata.
In a second embodiment of the first aspect, the method may further comprise:

- (a′) applying a hydraulic pressure which is greater than the overburden pressure at the floor interface to lithologically displace the trona stratum, thereby forming a lower interface gap between the strata and exposing a main trona free-surface, wherein said application of hydraulic pressure further induces formation of new undesirable transverse fractures and/or intersects natural undesirable transverse fractures in the trona stratum, thereby exposing minor trona free-surfaces in said undesirable fractures;
- (b′) flowing a sealing agent into the lower interface gap and into the transverse fractures; and
- (c′) maintaining such sealing agent in said lower interface gap and said transverse fractures to form a solidified matter inside said transverse fractures and optionally in said lower interface gap.

The step (b) and (b′) may be carried out from the same well.
The sealing agent may comprise water-insoluble particles, said water-insoluble particles comprising at least one water-insoluble calcium compound, fused or colloidal silica, water-insoluble matter recovered from a mechanically-mined mineral after its dissolution in water or aqueous medium, tailings recovered from a mineral surface refinery, biological solid matter, agricultural solid matter, sand, cement, or combinations thereof.
The step (b) may include:
before injecting the liquid settable composition and/or sealing agent into the cavity via a well, forming a drillable plug whose top edge does not block the flow of liquid settable composition and/or sealing agent to the upper interface and whose top edge is located inside the well near and below the upper interface to prevent said liquid settable composition and/or sealing agent to flow down in the well; and wherein after the barrier is formed in the upper interface gap, the method further comprises: removing the plug by drilling it out.
The method may further comprising:
(f) injecting an aqueous solvent into the cavity formed in the trona stratum and which is located underneath said barrier to dissolve some of the trona ore and to form a brine comprising sodium carbonate and/or bicarbonate in the cavity; and
(g) extracting at least a portion of the resulting brine to the ground surface; wherein said water-impermeable barrier formed at the trona upper interface minimizes contact and dissolution of at least one water-soluble contaminant from an overlying stratum with the aqueous solvent and resulting brine, and/or reduces leakage of contaminant-laden water percolating from overburden into the cavity which is being mined.
In preferred embodiments, the extracted brine may have a chloride content being equal to or less than 0.5 wt %.
The step (b) and (f) may be carried out from the same well, and step (g) may be carried out from one or more different wells.
The step (b) and (g) may be carried out from the same well, and step (f) may be carried out from one or more different wells.
In a third embodiment of the first aspect, in an underground formation containing a trona stratum comprising sodium sesquicarbonate lying above one or more substantially-insoluble strata containing water-soluble contaminants selected from the group consisting of chloride, sulfate, and water-soluble organics, said trona stratum comprising an ore roof with a parting upper interface above which is defined an overburden up to the ground and below which an aqueous solvent will be injected in a cavity to dissolve trona and to form a brine which is recovered at least in part at the ground surface,
a method for minimizing brine contamination from overburden during in situ trona solution mining of a cavity formed in the trona stratum, this method comprises the following steps:
(A) applying a hydraulic pressure greater than the overburden pressure at the interface to lithologically displace (lift) the overlying overburden from the underlying trona stratum, thereby forming a gap (main fracture) at the upper interface, wherein said application of hydraulic pressure further induces formation of new undesirable transverse fractures and/or intersects pre-existing undesirable transverse fractures in the trona stratum;
(B) flowing a sealing agent into the upper interface gap and into the transverse fractures; and
(C) maintaining the sealing agent in the upper interface gap and in said undesirable transverse fractures to form a solidified matter inside the fractures and the upper interface gap.
Prior to applying the hydraulic pressure in step (a) or step (A), the method comprises:

- placing a drillable plug in the casing slightly below the upper interface; and
- perforating or cutting the casing at the upper interface to allow fluid communication between the upper interface gap and the inside of the casing.

After performing step (c) or (C), the method further comprises:

- drilling the drillable plug positioned slightly below the upper interface and optionally any excess possible matter which is solidified from the injected composition (e.g., sealing agent, settable liquid) in a region of the casing which is immediately above the plug.

After drilling the drillable plug and optionally any excess solidified matter, the method further comprises:

- perforating or cutting the casing to provide casing opening(s) at at a lower interface between said trona stratum and an underlying stratum to allow fluid communication between the lower interface and the inside of the casing; and
- after this cutting step, a lifting fluid is applied to the lower interface to lift the trona stratum from said underlying stratum, said lifting fluid comprising a solvent being suitable for dissolving the trona and to form a brine.

In any of the embodiments according to the present invention, the extracted brine may have a chloride content being equal to or less than 0.5 wt %.
In the fourth embodiment of the first aspect, in an underground formation containing a plurality of trona ore strata comprising sodium sesquicarbonate and being of various heights and located at different depths, said trona ore strata being separated by a series of substantially-insoluble interburdens containing water-soluble contaminants selected from the group consisting of chloride, sulfate, and water-soluble organics, each trona ore stratum comprising an ore roof with an upper interface with the immediately-overlying interburden,
a method for minimizing brine contamination from interburden during in situ trona solution mining of two or more trona ore strata from said plurality, comprising:

- selecting two or more trona strata to be mined from the top down of said plurality based on selection criteria comprising a minimum of 60 wt % sodium sesquicarbonate in such trona ore and a minimum stratum height of at least one meter;
- carrying out sequentially in the selected trona ore strata to be mined from the top down, the following steps (a) to (h) as follows:

steps (a) to (c) of the method disclosed herein on a selected trona stratum using a well (preferably vertical) drilled through said selected trona ore stratum;
step (d): releasing the hydraulic pressure after the barrier is formed in the upper interface gap;
step (e): forming a cavity at or near and above the floor interface with the underlying interburden comprising a technique selected from the group consisting of lithological displacement of the trona ore stratum at the floor; and forming at least one uncased horizontal borehole;
step (f): injecting a solvent in the formed cavity to dissolved trona and thereby enlarging the cavity and to form a brine;
step (g): extracting at least a portion of the resulting brine to the ground surface via one or more of production wells;
step (h): stopping steps (f) and (g) when the brine extracted from the cavity has a level of said contaminant exceeding a threshold content above which is not acceptable for make a salable product or when the cavity is enlarged by dissolution to reach the roof of said cavity; and

- repeating steps (a) through (h) on another selected trona ore stratum meeting said selection criteria and being the next one to-be-mined from the top down of said plurality located underneath the previously-mined trona stratum, preferably using the same well (preferably vertical) used in steps (a) to (c) with the previously-mined trona ore stratum, optionally drilling said well further down if necessary past the floor of the to-be-mined trona ore stratum, and using one or more of the same production wells used in step (g) during mining of the previously-mined trona ore stratum, optionally drilling said one or more production wells further down if necessary past the floor of the to-be-mined trona ore stratum.

The method may further comprise step (i): injecting a blanket gas inside the cavity. This blanket gas, being more buoyant that the brine inside the cavity, stays below the ceiling of the cavity, thus preventing the solvent from contacting the roof material.
Some underground gas may be released during solution mining. In the case of trona mining, even though the trona itself contains very little carbonaceous material and therefore liberates very little methane, a trona stratum may be interbedded with and surrounded by methane-bearing oil shale which may liberate methane during trona mining. When such underground gas release occurs during cavity expansion (by dissolution), the released gas may accumulate inside the cavity.
The present method may further comprise step (j): purging at least some of the gas from the cavity to the surface. The gas which is purged may comprise released underground gas (such as methane) and/or blanket gas (such as air, nitrogen, CO₂, or combinations thereof) which is injected into the cavity during step (i). Step (j) may be performed to relief some pressure inside the cavity.
Applicants have further developed, in a second aspect, a method for minimizing gas migration into the overburden from the immediately underlying cavity which is solution mined in the evaporite stratum.
One advantage of such method according to the second aspect would be to keep inside the cavity any gas (such as methane) which may be released during solution mining of the mineral ore and which may accumulate inside the cavity which is solution mined. Trapping any released methane may be indeed advantageous for the extraction of this released methane to the surface and recovery of its energy for example in a surface refinery which processes the brine to make one or more valuable products.
Another advantage of such method according to the second aspect would be to keep a blanket gas (such as air, nitrogen, CO₂, or combinations thereof)—which is typically used to control ore dissolution rates and geometry—from migrating out of the target cavity.
According to this second aspect to the present invention, in an underground formation containing a trona stratum comprising sodium sesquicarbonate and further containing one or more methane-containing strata, said trona stratum comprising an ore roof with a parting upper interface above which is defined an overburden up to the ground and below which an aqueous solvent will be injected in a cavity to dissolve trona and to form a brine which is recovered at least in part at the ground surface, the method for minimizing gas migration into the overburden from the immediately underlying cavity which is solution mined in the trona stratum, comprising:
applying a hydraulic pressure which is greater than the overburden pressure at the upper interface to lithologically displace the overburden from the trona roof, thereby forming an interface gap;
flowing a composition selected from the group consisting of a liquid settable composition, a sealing agent, and combinations thereof, into the upper interface gap; and
allowing such composition to stay into the upper interface gap for a time sufficient to form a gas-impermeable barrier inside said upper interface gap.
The method may further comprise step (i): injecting a blanket gas into the cavity, and the formed gas-impermeable barrier prevents the injected gas to migrate out of the cavity into the overburden.
The method may further comprise step (j): releasing some methane during trona solution mining into the cavity and extracting methane from the cavity to the ground surface, and the formed gas-impermeable barrier prevents the released methane gas to migrate out of the cavity into the overburden.
In this second aspect, the method may comprise carrying out steps (a) to (c) or steps (A) to (C), as specified above, except that the barrier or solidified matter which is formed inside the upper interface gap in step (c) or (C) is gas-impermeable.
In this second aspect, the method may further comprise carrying out any of the additional optional steps (d) through (h) as described herein.
A third aspect of the present invention relates to a manufacturing process for making one or more sodium-based products from an underground cavity in an evaporite mineral stratum comprising trona ore, said process comprising:
carrying out the method according to the first aspect of the present invention to dissolve trona ore from the underground cavity which is solution mined to obtain a brine comprising sodium carbonate and/or bicarbonate; and
passing at least a portion of said brine through one or more units selected from the group consisting a crystallizer, a reactor, and an electrodialysis unit, to form at least one sodium-based product.
Yet a fourth aspect of the present invention relates to a sodium-based product selected from the group consisting of sodium sesquicarbonate, sodium carbonate monohydrate, sodium carbonate decahydrate, sodium carbonate heptahydrate, anhydrous sodium carbonate, sodium bicarbonate, sodium sulfite, sodium bisulfite, sodium hydroxide, and other derivatives, said product being obtained by the manufacturing process according to the present invention.
The foregoing has outlined rather broadly the features and technical advantages of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter that form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying methods or processes or designing other structures for carrying out the same purposes of the present invention. It should also be realized by those skilled in the art that such equivalent constructions or methods or processes do not depart from the spirit and scope of the invention as set forth in the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings which are provided for example and not limitation, in which:

FIG. 1 illustrates the lithological displacement step (a), in side-view, being carried out in the method according to the first aspect according to the present invention;

FIG. 2a illustrates step (b), in a close-up 2-dimensional side-view, in which the liquid settable composition and/or sealing agent is flowing at the trona upper (roof) interface thereby lifting the overburden at this interface while positioning the liquid settable composition and/or sealing agent inside the created interface gap;

FIG. 2b illustrates step (b), in a close-up 3-dimensional side-view, in which the liquid settable composition and/or sealing agent is injected at the trona roof interface via casing perforations;

FIG. 3 illustrates step (c), in side-view, being carried out in the method according to the first aspect according to the present invention;

FIG. 4 illustrates an embodiment of step (e) using lithological displacement at the floor interface to form a cavity in the trona stratum after the water-impermeable barrier is formed according to the first aspect according to the present invention;

FIG. 5 illustrates step (b), in a close-up side-view, in which the liquid settable composition and/or sealing agent is injected at the trona roof interface via casing perforations;

FIG. 6 illustrates a technique to seal transverse fractures in the trona seam using steps (a′)-(c′) according to an embodiment of the first aspect of the present invention;

FIG. 7 illustrates steps (e) and (f), in side-view, according to the first aspect of the present invention, in which the trona cavity is subjected to solution mining with an aqueous solvent.

FIG. 8 illustrates steps (e) and (f), in plan-view, according to the first aspect of the present invention, in which the trona cavity is subjected to solution mining with an aqueous solvent of a trona cavity which is positioned underneath the water-impermeable barrier and using three injections wells and one production well;

FIG. 9 illustrates another embodiment of step (e) using uncased horizontal boreholes near and above the floor interface to form a cavity in the trona stratum after the water-impermeable barrier is created according to the first aspect according to the present invention;

FIG. 10 illustrates steps (e) and (f), in plan-view, from a trona cavity initiated by uncased horizontal boreholes according to the first aspect of the present invention, in which the trona cavity is subjected to solution mining with an aqueous solvent of 3 merged trona cavities which are all positioned underneath the water-impermeable barrier and using three injections wells and one production well;

FIG. 11 illustrates another embodiment according to the present invention, in which some selected trona strata in the same formation which are separated by interburden are sequentially solution mined from the top down and the selected bed are initiated by the method according to the present invention.

On the figures, identical numbers correspond to similar references.
Drawings have are not to scale or proportions. Some features may have been blown out or enhanced in size to illustrate them better.

DEFINITIONS AND NOMENCLATURES

For purposes of the present disclosure, certain terms are intended to have the following meanings.
The term ‘evaporite’ is intended to mean a water-soluble sedimentary rock made of, but not limited to, saline minerals such as trona, halite, nahcolite, sylvite, wegscheiderite, that result from precipitation driven by solar evaporation from aqueous brines of marine or lacustrine origin. The preferred evaporite mineral is trona.
The term “fracture” when used herein as a verb refers to the propagation of any pre-existing (natural) fracture(s) and the creation of any new fracture or fractures; and when used herein as a noun, refers to a fluid flow path in any portion of a formation, stratum or deposit which may be natural or hydraulically generated (induced).
As used herein, the term “liquid settable composition” is a substance which is used to block off certain water permeable zones of an evaporite mineral stratum into which a liquid flow is undesirable, and also which may be used to prevent liquid contact with water-soluble contaminant-laden mineral to minimize contaminant dissolution.
As used herein, the term “sealing agent” is a substance which is used to plug or block off certain water permeable zones (fractures, interface gap) of an evaporite mineral stratum into which a liquid flow is undesirable, and also which may be used to coat the mineral free-surface in these permeable zones to prevent liquid contact with such mineral surface to prevent mineral dissolution.
The term lithological displacement′ as used herein to include a hydraulically-generated vertical displacement of an evaporite stratum (lift) at its interface with an (overlying or underlying) non-evaporite stratum. A “lithological displacement” may also include a lateral (horizontal) displacement of the evaporite stratum (slip), but slip is preferably avoided.
The term ‘overburden’ is defined as the column of material located above the target interface up to the ground surface. This overburden applies a pressure onto the interface which is identified by an overburden gradient (also called ‘overburden stress’, ‘gravitational stress’, lithostatic stress′) in a vertical axis.
The term ‘TA’ or ‘Total Alkali’ as used herein refers to the weight percent in solution of sodium carbonate and/or sodium bicarbonate (which latter is conventionally expressed in terms of its equivalent sodium carbonate content) and is calculated as follows: TA wt %=(wt % Na₂CO₃)+0.631 (wt % NaHCO₃). For example, a solution containing 17 weight percent Na₂CO₃and 4 weight percent NaHCO₃would have a TA of 19.5 weight percent.
The term ‘liquor’ or ‘brine’ or ‘pregnant solution’ as used herein represents a solution containing solvent and dissolved solute (such as dissolved trona). As the solvent passes through the mineral ore stratum, the solvent gets impregnated with dissolved solute. Such solution may be unsaturated or saturated in desired solute.
The terms “solubility”, “soluble”, “insoluble” as used herein refer to solubility/insolubility of a compound in water or in an aqueous solution, unless otherwise stated in the disclosure.
The term “solute” as used herein refers to a compound which is soluble in water or an aqueous solution, unless otherwise stated in the disclosure.
The term “solution” as used herein refers to a composition which contains at least one solute in a solvent.
The term “unsaturated solution” as used herein refers to a composition which contains a dissolved solute at a concentration which is below the solubility limit of such solute under the temperature and pressure of the composition.
The term “saturated solution” as used herein refers to a composition which contains a solute dissolved in a liquid phase at a concentration equal to the solubility limit of such solute under the temperature and pressure of the composition.
The term “slurry” as used herein refers to a composition which contains solid particles and a liquid phase.
The term “colloidal suspension” as used herein refers to a composition which contains solid particles maintained in suspension in a liquid phase.
The term “gel” as used herein is understood to mean a composition comprising particles dispersed in colloidal form in a liquid phase. The dispersed particles form spatial networks stabilized by means of Van der Waals' forces. In a hydrogel, the liquid phase is water.
The term “thixotropic gel” as used herein is understood to mean a thixotropic aqueous suspension comprising particles dispersed in colloidal form in an aqueous phase, preferably having a viscosity at rest of at least 100 cps, most particularly preferably of at least 200 cps. The dispersed particles form space lattices, stabilized by means of van der Waals forces. The gel is thixotropic, that is to say that when it is subjected to a shear stress its viscosity decreases, but returns to its initial value when the shear stress stops. The physical property of thixotropy is more particularly defined as follows: left at rest, the thixotropic fluid will be restructured until it has the appearance of a solid (infinite viscosity), whereas under a constant stress that is high enough to break up the structure formed at rest for example, the fluid will be broken down until it is in its liquid state (low viscosity).
The term “(bi)carbonate” as used herein refers to the presence of both sodium bicarbonate and sodium carbonate in a composition, whether being in solid form (such as trona) or being in liquid form (such as a liquor or brine). For example, a (bi)carbonate-containing stream describes a stream which contains both sodium bicarbonate and sodium carbonate.
The term “substantially insoluble stratum” refers to a stratum which contains at least 75% by weight of matter insoluble in the solvent used in solution mining, preferably at least 80 wt % insoluble matter, more preferably at least 85 wt % insoluble matter. An oil shale stratum is substantially water-insoluble but may contain water-soluble material such as chloride-containing and/or sulfate-containing inorganic minerals and water-soluble organic material.
A ‘surface’ parameter is a parameter characterizing a fluid, solvent and/or brine at the ground surface (terranean location), e.g., before injection into an underground cavity or after extraction from a cavity to surface.
An ‘in situ’ parameter is a parameter characterizing a fluid, solvent and/or brine in an underground cavity (subterranean location).
The term ‘comprising’ also includes “consisting essentially of” and also “consisting of”.
A plurality of elements includes two or more elements.
Any reference to ‘an’ element is understood to encompass one or more′ elements. The use of the singular ‘a’ or ‘one’ herein includes the plural (and vice versa) unless specifically stated otherwise.
The phrase ‘A and/or B’ refers to the following choices: element A; or element B; or combination of A and B (A+B).
The phrase ‘A1, A2, . . . and/or An’ with n 3 refers to the following choices: any single element Ai (i=1, 2, . . . n); or any sub-combinations of less than n elements Ai; or combination of all elements Ai.
In the present Application, where an element or component is said to be included in and/or selected from a list of recited elements or components, it should be understood that in related embodiments explicitly contemplated here, the element or component can also be any one of the individual recited elements or components, or can also be selected from a group consisting of any two or more of the explicitly listed elements or components, or any element or component recited in a list of recited elements or components may be omitted from this list. Further, it should be understood that elements and/or features of compositions, processes or methods described herein can be combined in a variety of ways without departing from the scope and disclosures of the present teachings, whether explicit or implicit herein.
In addition, if the term “about” is used before a quantitative value, the present teachings also include the specific quantitative value itself, unless specifically stated otherwise. As used herein, the term “about” refers to a +/−10% variation from the nominal value unless specifically stated otherwise.
It should be understood that throughout this specification, when a range is described as being useful, or suitable, or the like, it is intended that any and every amount within the range, including the end points, is to be considered as having been stated. Furthermore, each numerical value should be read once as modified by the term “about” (unless already expressly so modified) and then read again as not to be so modified unless otherwise stated in context. For example, “a range of from 1 to 1.5” is to be read as indicating each and every possible number along the continuum between about 1 and about 1.5. In other words, when a certain range is expressed, even if only a few specific data points are explicitly identified or referred to within the range, or even when no data points are referred to within the range, it is to be understood that the inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that the inventors have possession of the entire range and all points within the range.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The following detailed description illustrates embodiments of the present invention by way of example and not necessarily by way of limitation.
It should be noted that any feature described with respect to one aspect or one embodiment is interchangeable with another aspect or embodiment unless otherwise stated.
Any mention of the water-impermeable barrier in the present description according to the first aspect also includes herein embodiments in which the barrier or solidified matter formed in the upper interface gap in step (a) or (A) is gas-impermeable according to the second aspect of the present invention.
The invention will now be described with reference to the following drawings: FIGS. 1, 2 a, 2 b, 3 to 11.
Although FIGS. 1, 2 a, 2 b, 3 to 11 are illustrated in the context of a trona/shale system and the application of hydraulic pressure at their underground upper interface, with respect to any or all embodiments of the present invention, the mineral stratum or ore to which the present method can be applied may be any suitable ore containing a desirable mineral solute. The evaporite mineral stratum may comprise a mineral which is soluble in the solvent to form a brine which can be used for the production of rock salt (NaCl), potash (KCl), soda ash, and/or derivatives thereof. The mineral stratum may comprise a water-soluble mineral selected from the group consisting of trona, nahcolite, wegscheiderite, wegscheiderite, shortite, northupite, pirssonite, dawsonite, sylvite, carnalite, halite, and combinations thereof. Preferably, the mineral stratum comprises any deposit containing sodium bicarbonate and/or sodium carbonate. The mineral stratum more preferably comprises a water-soluble mineral selected from the group consisting of trona, nahcolite, wegscheiderite, and combinations thereof. Most preferably, the mineral stratum contains trona.
The present invention relates to a method for trona solution mining which includes the lithological displacement of an evaporite mineral bed in a dense impervious underground formation at a defined plane of weakness. This formation preferably contains a lithological mineral stratum which is soluble in a removal liquid, lying immediately below a non-evaporite stratum which is substantially insoluble in such removal liquid. The underground formation has a defined parting surface interface between the two strata.
Particularly, in an underground formation containing a trona stratum comprising sodium sesquicarbonate lying below one or more substantially-insoluble strata containing water-soluble contaminants selected from the group consisting of chloride, sulfate, and water-soluble organics, said trona stratum comprising an ore roof with an upper interface above which is defined an overburden up to the ground and below which an aqueous solvent is injected in a cavity formed in the trona stratum to dissolve trona and to form a brine which is recovered at least in part at the ground surface,
a method for preventing contamination of the brine from overburden, comprising
(a) applying a hydraulic pressure which is greater than the overburden pressure at the upper interface to lithologically displace the overburden from the trona roof, thereby forming an upper interface gap;
(b) flowing a liquid settable composition and/or sealing agent into the upper interface gap; and
(c) allowing such liquid settable composition and/or sealing agent to set in said upper interface gap to form a water-impermeable barrier inside said gap.
The following may apply to any or all embodiments of the various aspects according of the present invention.
When the ore stratum is a trona stratum, an overlying water-insoluble stratum may include oil shale or any substantially water-insoluble sedimentary rock that has a weak bond upper interface with the trona stratum roof, and the underlying water-insoluble stratum may include oil shale or any substantially water-insoluble sedimentary rock that also has a weak bond lower interface with the trona stratum bottom.
An alternate embodiment of the first aspect of the present invention relates to a method for sealing or plugging undesirable fractions penetrating the trona stratum during lithological displacement. This method comprises the following steps:
(A) applying a hydraulic pressure greater than the overburden pressure at the interface to lithologically displace (lift) the overlying overburden from the underlying trona stratum, thereby forming a gap (main fracture) at the upper interface, wherein said application of hydraulic pressure further induces formation of new undesirable transverse fractures and/or intersects pre-existing undesirable transverse fractures in the trona stratum;
(B) flowing a sealing agent into the upper interface gap and into the transverse fractures; and
(C) maintaining the sealing agent in the upper interface gap and in said undesirable transverse fractures to form a solidified matter inside the fractures and the upper interface gap.
The defined parting upper interface may be horizontal or near-horizontal, but not necessarily.
Prior to performing step (a) or (A) described herein, the method preferably comprises:

- placing a drillable plug in the casing slightly below the upper interface (the top of the trona stratum); and
- perforating or cutting the casing at the upper interface to allow fluid communication between the upper interface gap and the inside of the casing.

After performing step (c) or (C), the method preferably method may further comprise:

- drilling the drillable plug positioned slightly below the upper interface as well as any possible matter which may be cured or solidified (from the liquid settable region and the sealing agent) in the casing region immediately above the plug.

After drilling the drillable plug and possible excess solidified matter, the method may further comprise:

- perforating or cutting the casing (to provide casing opening(s)) at the lower interface to allow fluid communication between the lower interface and the inside of the casing.

After this cutting step, a lifting fluid may be used to lift the trona stratum from the overburden to create a trona free surface, which can be now subjected to dissolution. The lifting fluid is preferably a solvent suitable for dissolving trona.
In some preferred embodiments with a trona bed, the method comprises the following steps:

- Placing a drillable plug into the casing slightly below the top of the trona bed (upper interface);
- Perforating the casing or cut a slot in the casing at the trona bed—overlying shale upper interface;
- Injecting an appropriate settable liquid or a sealing agent under a hydraulic pressure slightly greater than the overburden pressure in order to seal or glue that interface and the natural occurring joints which are intersecting this interface, by forming a solidified matter, which preferably creates a water-permeable barrier;
- Drilling the drillable plug;
- Perforating the casing and/or cutting a slot in the casing at the trona bed-underlying shale interface; and
- Injecting a suitable solvent under a hydraulic pressure slightly greater than the overburden pressure at the bottom of the bed (lower interface) to create a lower interface gap and thereby exposing a trona free surface which is.
  The advantages of this method applying to trona beds would be as follows:
- Limit the NaCl contamination from the trona beds' interburden;
- Seal the natural joints penetrating the trona bed to be mined;
- Create a barrier at the top of the trona bed that could potentially keep the fracture(s) within the trona bed, thus preventing a stair-stepping fracturing process or limiting fracture growth not to go beyond this barrier;
- while at the same time, keep the lower interface free from any gluing agent or settable material that could make the subsequent lithological displacement more challenging.

In FIG. 1 a trona stratum 5 is overlying a non-evaporite stratum 10 and is underlying another non-evaporite stratum 11. In preferred embodiments, the non-evaporite strata 10 and 11 comprise an oil shale. There is a defined parting line lower interface 20 between the strata 5 and 10. There may also be a defined parting line upper interface 21 between the strata 5 and 11. For the lithological displacement step, the application of a hydraulic pressure can be carried out at either interface.
The defined parting interface 20 between the strata 5 and 10 and the upper interface 21 between the strata 5 and 11 are preferably horizontal or near-horizontal, but not necessarily. The interfaces 20 and/or 21 may be characterized by a dip of 5 degrees or less; preferably with a dip of 3 degrees or less; more preferably with a dip of 1 degrees or less. The defined parting interface 20 and/or 21 may have a dip greater than 5 degrees up to 45 degrees or more.
The trona/ shale interface 20 and 21 maybe at a shallow depth of less than 3,280 ft (1,000 m) or at a depth of 3,000 ft (914 m) or less, preferably at a depth of 2,500 ft (762 m) or less, more preferably at a depth of 2,000 ft (610 m) or less. The trona/shale interfaces 20 and/or 21 may at a depth of more than 800 ft (244 m).
In the Green River Basin, the trona/oil shale parting interface 20 or 21 may be at a shallow depth of from 800 to 2,500 feet (244-762 m).
The trona stratum 5 is preferably at a shallow depth of 3,000 ft (914 m) or less, preferably of 2,500 feet (762 m) or less.
The trona stratum 5 may contain up to 99 wt % sodium sesquicarbonate, preferably from 25 to 98 wt % sodium sesquicarbonate, more preferably from 50 to 97 wt % sodium sesquicarbonate, more preferably from 60 to 95 wt % sodium sesquicarbonate.
The trona stratum 5 may contain various contents of sodium chloride. Some trona strata may have low NaCl contamination, such as up to 1 wt % sodium chloride, preferably up to 0.8 wt % NaCl, yet more preferably up to 0.2 wt % NaCl. NaCl-rich trona strata may have more substantial amounts of NaCl contamination (e.g., more than 2 wt %). Even if the trona stratum contains low NaCl contamination, sources of chloride contamination may be at least in part chloride salts of some naturally occurring minerals in roof shales above most trona beds.
The solution mining method of the present invention is particularly well suited for use with trona ore deposits that contain chloride salts of some naturally occurring minerals as contaminant(s) in the roof rock. Low-NaCl and NaCl-contaminated trona beds are often located in close proximity, in strata, and confinement of the solution mining cavity to a single bed may not be feasible for most solution mining techniques. This fact makes the solution mining method of the present invention especially appropriate for the efficient recovery of available ore reserves in a single geographic region, despite salt contamination in the roof of some trona ore beds.
The trona stratum 5 may comprise naturally existing fissures and/or hydraulically-generated fractures which are at an angle with respect to the main axis of the interface 20 (identified as 25 in FIG. 1), and may comprise naturally existing fissures and/or hydraulically-generated fractures which are at an angle with respect to the main axis of the interface 21 (identified as 26 in FIG. 1), and which Applicants call ‘transverse fractures’.
Although trona is the preferred evaporite mineral stratum to which the present invention applies, the present method is applicable to the mining of nahcolite or wegscheiderite-containing stratum.
An overburden, defined as the column of material located above the target interface up to the ground surface, applies a pressure onto this interface which is identified by an overburden gradient (also called ‘overburden stress’, ‘gravitational stress’, lithostatic stress′) in a vertical axis.

Step (a): Lithologically Displacement at the Upper Interface

The method comprises: (a) applying a hydraulic pressure which is greater than the overburden pressure at the upper interface to lithologically displace the overburden from the trona roof, thereby forming an interface gap.
FIG. 1 illustrates such step (a).
In FIG. 1, a trona stratum 5 is separated from an underlying non-evaporite stratum 10 by a lower interface 20 and separated from an overlying non-evaporite stratum 11 by an upper interface 21.
A lifting fluid 50 is preferably injected at the upper interface 21 via a well 30 to carry out the lifting step (a). The well 30 preferably has downhole casing openings, such as perforations 37 a (shown in FIGS. 2a and 2b ) through which the fluid 50 exits into the upper interface. The lifting fluid 50 may be an aqueous solvent or may be the liquid settable composition used in step (b) or may be a sealing agent used in step (B) for sealing the upper interface. A plug 35 a is placed inside the well 30 underneath the upper interface 21 so as to keep the fluid 50 from flowing down into the well 30.
A fracture will open in the direction perpendicular to minimum principal stress. To propagate a fracture in an isotropic medium in the horizontal direction, the minimum principal stress must be vertical. The vertical stress at the interface 21 coincides with the overburden pressure. It is generally prudent to select a fracture gradient for lithological displacement to be slightly higher than the overburden gradient to propagate a horizontal fracture initiated at the injection zone 40 a along the parting interface 21.
A hydraulic pressure which is slightly higher than the overburden pressure is preferably applied underground at the interface 21 between the trona stratum 5 and the overlying stratum 11, thereby lifting (vertical displacement) the overburden and at the same time the overlying stratum 11, thereby creating a gap (main fracture) at the upper interface 21. This hydraulic pressure application is significantly different than the commercially-available hydraulic fracturing using very high pressures in deep porous formations, like in shale fracturing where the intent is the creation of numerous vertical fractures in the actual rock mass at much greater depth (>4,000 ft=1,219 m) under much greater overburden pressure.
The fracture gradient used will be estimated depending on the local underground stress field and the tensile strength of the trona/shale interface. The fracture gradient used for estimating the target lifting pressure for lithological displacement is equal to or greater than 0.9 psi/ft, or equal to or greater than 0.95 psi/ft, preferably equal to or greater than 1 psi/ft. The fracture gradient used for estimating the target lifting pressure for lithological displacement may be 1.5 psi/ft or less; or 1.4 psi/ft or less; or 1.3 psi/ft or less; or 1.2 psi/ft or less; or 1.1 psi/ft or less; or even 1.05 psi/ft or less.
The fracture gradient may be between 0.9 psi/ft (20.4 kPa/m) and 1.5 psi/ft (34 kPa/m); preferably between 0.90 and 1.30 psi/ft; yet more preferably between 1 and 1.25 psi/ft; most preferably between 1 and 1.10 psi/ft. The fracture gradient may alternatively be from 0.95 psi/ft to 1.2 psi/ft; or from about 0.95 psi/ft to about 1.1 psi/ft, or from about 1 psi/ft to about 1.05 psi/ft. For example, for a depth of 2,000 ft for interface 21, a minimum target hydraulic pressure of 2,000 psi may be applied at interface 21 by the injection of the fluid to lift the overburden with the stratum 5 immediately above the targeted zone to be lifted, which represents the interface 21 between the trona 5 and the overlying stratum 11.
The fracture gradient used will be estimated depending on the local underground stress field and the tensile strength of the trona/shale interface. The fracture gradient used for lithological displacement may be 1 psi per foot or higher, preferably between 1.05 and 1.50 psi/ft. That is to say, for a depth of 2,000 ft for interface 20, a minimum hydraulic pressure of 2,000 psi may be applied at the interface 20 by the injection of the fluid 50. However, the targeted block of trona stratum 5 to be lifted is located at shallow depth where the vertical stress should be sufficiently low, and it is known to have very low tensile strength, considerably weaker than either the trona or the oil shale. The combination of both low vertical stress and a very weak horizontal interface creates very favorable conditions for the propagation of a horizontal hydraulically induced lithological displacement.
The lifting hydraulic pressure during step (a) may be at least 0.01% greater, or at least 0.1% greater, or at least 1% greater, or at least 3% greater, or at least 5% greater, or at least 7% greater, or at least 10% greater, than the overburden pressure at the depth of the upper (roof) interface 21. The hydraulic pressure during the lifting step (a) may be at most 50% greater, or at most 40% greater, or at most 30% greater, or at most 20% greater, than the overburden pressure at the depth of the upper (roof) interface 21. The lifting hydraulic pressure may be from 0.01% to 50% greater (preferably from 1% to 50% greater) than the overburden pressure at the depth of the upper (roof) interface 21. The lifting hydraulic pressure preferably may be just above the pressure (e.g., about 0.01% to 1% greater) necessary to overcome the sum of the overburden pressure and the tensile strength of the upper (roof) interface 21.
The hydraulic pressure applied in step (a) may be selected by using a fracture gradient which is higher than the overburden gradient. The hydraulic pressure which is applied in step (a) may use a fracture gradient from about 0.9 psi/ft (20.4 kPa/m) to about 1.5 psi/ft (34 kPa/m).
The hydraulic pressure is applied in step (a) by using a fracture gradient between 0.95 psi/ft and 1.5 psi/ft, preferably between 1 psi/ft and 1.3 psi/ft, more preferably between 1.05 psi/ft and 1.2 psi/ft or even between 1.05 psi/ft and 1.15 psi/ft.
The fluid 50 (which may comprise or may be the liquid settable agent and/or sealing agent) is preferably injected at a volumetric flow rate selected from about 1 to 50 barrels per minute (or from about 9.5 m³/hr to about 477 m³/hr); or from about 2.1 BBL/min to about 31.4 BBL/min (or from 20 m³/hr to 300 m³/hr), to allow the hydraulic pressure to rise at the in situ injection zone 40 until it reaches the target hydraulic pressure (estimated to be the depth of interface times the selected fracture gradient). At this point, the hydraulic pressure is maintained by adjusting the flow in order to steadily increase the diameter of the gap (main fracture). It is expected that some fluid flow will leave the main fracture and will necessarily be accounted for in the field during the injection process.
The injected lifting fluid used for lithological displacement of the trona stratum may comprise a solvent suitable for dissolving the mineral.
The injected lifting fluid may comprise water or an aqueous solution, such as sodium (bi)carbonate-containing solution and/or caustic solution. The injected fluid may comprise an aqueous alkaline solution. The injected lifting fluid may comprise an unsaturated aqueous solution comprising sodium carbonate, sodium bicarbonate, sodium hydroxide, calcium hydroxide, or combinations thereof. The injected lifting fluid may consist essentially of water.
The injected lifting fluid may comprise or consist of a slurry comprising particles suspended in water or the aqueous solution. The particles may be any suitable water-insoluble matter. The particles may comprise tailings and/or a proppant. The particles may comprise tailings used as proppant. Such tailings may be obtained during refining of mineral such as mechanically-mined trona. A proppant may be any suitable insoluble solid material with a size distribution that will “prop” open the hydraulically-induced gap in such a way as to allow passage and flow of fluid in the gap when using a lower hydraulic pressure in a later dissolution step.
The method of the present invention may further comprise: before carrying step (a), forming at least one fully cased and cemented well 30 which intersects the strata upper interface 21.
Well 30 may be drilled from ground surface through the trona stratum 5 and intersects the trona upper (roof) interface 21 and also preferably intersects the trona lower (floor) interface 20. The well 30 may be a vertical well or less preferably a directionally drilled well. The well 30 may be cemented and cased from the ground surface past the lower interface 20 down to an underground location below the trona floor thereby intersecting the lower (floor) interface 20.
In addition to being used to inject the fluid (50) for step (a), this well 30 may serve as an injection well and/or may serve as an extraction well during solution mining.
Forming the well 30 may include drilling from the surface to at least the depth of a target injection zone which is located near or at the upper interface 21 between the selected block of trona stratum and the overlying stratum 11, followed by casing and cementing the well.
The well 30 is preferably fully cemented and cased, but as illustrated in FIGS. 2a and 2b , the well is provided with at least one in situ injection zone 40 which is in fluid communication with the upper interface 21. The in situ injection zone 40 should allow for the fluid 50 to be injected into the well 30 and to be directed at the interface 21. The in situ injection zone 40 is preferably, albeit not necessarily, designed to laterally inject the fluid 50 in order to avoid injection of fluid in a vertical direction. The in situ injection zone 40 allows the fluid to force a path at the interface 21 by vertically displacing the stratum 5 to create an interface gap. The one in situ injection zone 40 may be a portion of the fully cemented and cased well 30 which comprises at least one casing opening (which provides at least one in situ injection zone) which is in fluid communication with the strata upper interface 21. The lifting fluid 50 (e.g., solvent or the liquid settable composition, and/or sealing agent) can flow through the casing opening(s) 37 a between the inside of the well and the strata upper interface 21. To obtain the casing opening(s) 37 a, the casing of the well 30 may be perforated or cut by a downhole perforating or cutting tool. Examples of casing opening(s) are perforations 37 a in FIG. 2a and FIG. 2 b.
When the well 30 is vertical (as illustrated), the in situ injection zone 40 may comprise or consist of perforations 37 a (casing openings) in a downhole section of the well casing, preferably aligned alongside the strata upper interface 21. When the vertical well 30 goes through the upper interface 21 which is horizontal or near horizontal, perforations 37 a (casing openings) are preferably positioned on at least one casing circumference of this downhole section, such casing circumference being aligned alongside the plane of the strata upper interface 21.
In some embodiments, these perforations are preferably aligned with respect to the plane of the strata upper interface 21 (such as in a row). For example, using a downhole perforating tool, perforations 37 a may be cut through the casing and cement at a well circumference aligned with the interface 21 to form the in situ injection zone 40. However alignment of perforations 37 a with the interface 21 is not required to provide an adequate lifting of the stratum 5 at the interface 21.
The method may further comprise perforating the well casing on at least one circumference on a vertical section of well 30, so as to create the casing perforations 37 a aligned alongside the upper interface 21. When the interface 21 is horizontal or near-horizontal, this perforating step may be carried out to allow passage of the injected fluid 50 in a preferential lateral way through the formed perforations 37 a towards the horizontal or near-horizontal interface 21.
In some embodiments, the in situ injection zone 40 may be intentionally widened to form a ‘pre-lift’ slot between the overlying evaporite stratum and the underlying insoluble stratum, this ‘pre-lift’ slot providing a pre-existing “initial lifting surface” which would allow the hydraulic pressure exerted by the injected fluid to act upon this initial lifting surface preferentially in order to begin the initial separation of the two strata. The pre-lift slot may be created by directionally injecting a fluid (preferably comprising a solvent suitable to dissolve the mineral) under pressure via a rotating jet gun.
The fluid 50 can flow inside the casing of well 30 or may be injected via a conduit (not shown) all the way to the in situ injection zone 40. The openings (such as perforations 37 a) on the casing may be in fluid communication with a conduit inserted into the well 30 to facilitate fluid flow from the ground surface to this well in situ injection zone 40 (not illustrated). Such conduit may be inserted inside the injection well 30 to facilitate injection of fluid 50. The conduit may be inserted while the injection well 30 is drilled, or may be inserted after drilling is complete. The injection conduit may comprise a tubing string, where tubes are connected end-to-end to each other in a series in a somewhat seamless fashion. The injection conduit may comprise or may consist of a coiled tubing, where the conduit is a seamless flexible single tubular unit. The injection conduit may be made of any suitable material, such as for example steel or any suitable polymeric material (e.g., high-density polyethylene). The injection conduit inside well 30 should be in fluid communication with the in situ injection zone 40.
Additionally, a section of the well 30 which is underneath the interface 21 may be plugged for the lifting step (a) and also for the subsequent steps (b) and (c).
In some embodiment the plug 35 a (illustrated in FIGS. 2a and 2b ) may be placed, preferably before the lifting step (a), but certainly before step (b), that is to say, before injecting the liquid settable composition and/or sealing agent via well 30 into the upper interface gap which is created by lifting the overburden at the upper interface 21. At the same time, the liquid settable material and/or sealing agent intersects some of the natural (pre-existing) and/or hydraulically induced fractures 26 transversely crossing the upper interface and penetrating some of the top of the stratum 5 and the overlying stratum 11 (as illustrated in FIG. 1), and as this liquid settable material and/or sealing agent flows in these intersecting transverse fractures, it solidifies and creates a barrier or/and seal or plug in these fractures 26 which intersect its (see sealed fractures 26 transversing the upper interface 21 in FIG. 3).
The present method may further include placing, inside the casing, a drillable plug 35 a whose top edge 38 does not block the flow of the lifting fluid 50 (e.g., solvent or liquid settable composition) to the upper interface 21 and whose top edge 38 is located inside the well 30 near and below the upper interface 21 to prevent the lifting fluid 50 (e.g., solvent or liquid settable composition and/or sealing agent) from flowing down in the well 30 towards the well bottom.
The method may further comprise: removing the plug 35 a by drilling it out after the water-impermeable barrier 41 or a solidified matter (illustrated in FIG. 3) is formed in the upper interface gap.
The gap formed at the strata upper interface in this lithological displacement step would extend laterally in all directions away from the in situ injection zone 40 for a considerable lateral distance from 30 meters (about 100 feet), up to 150 m (about 500 ft), up to 300 m (about 1,000 ft), up to 500 m (about 1,640 ft), or even up to 610 m (about 2,000 ft) away. Because it is expected that the stresses are not equal in all directions, the lateral expansion will not be even in the horizontal plane and will likely form an imperfect but more or less circular or elliptical gap (‘pancake’ shaped) centered more or less around the in situ point of injection 40 at the downhole section of the injection well 30. The width (also called height) of the gap however would be much less than 1 cm, generally from about 0.5-1 cm near the injection zone 40 up to 0.25 cm or less at the extreme edges of its lateral expanse. The width of the gap is highly dependent upon the flow rate of the injection fluid 50 during lithological displacement.

Step (b)

The present method comprises: (b) flowing a liquid settable composition, a sealing agent, or both into the upper interface gap.
The steps (a) and (b) may be performed at the same time; the injection of the liquid settable composition and/or sealing agent provides said hydraulic pressure at the upper interface and its flowing into said upper interface gap. In such instance where the steps (a) and (b) are carried out simultaneously, the injection of the liquid settable composition and/or sealing agent is done via the vertical well 30 as illustrated in FIGS. 2a and 2 b.
Although less preferred, the steps (a) and (b) may be performed sequentially, step (a) being carried out by injecting a lifting fluid comprising water or consisting of water to apply said hydraulic pressure at the upper interface to form said upper interface gap; and after evacuating the lifting fluid used in step (a), step (b) is carried out by flowing the liquid settable composition and/or sealing agent into said upper interface gap. In such instance where the steps (a) and (b) are carried out sequentially, the injection of the lifting fluid and the liquid settable composition and/or sealing agent are preferably done via the same vertical well 30. The hydraulic pressure in step (b) is preferably the same than the hydraulic pressure used in step (a), when steps (a) and (b) are not carried out simultaneously. For injection fluid 50, water may be used initially to create the main gap at the strata interface 21. The fluid 50 initially injected for lithological displacement may be evacuated by flowback. And then to initiate cementing, the liquid settable composition and/or sealing agent is subsequently used as the injection fluid 50. In this case, steps (a) and (b) of the present method are carried sequentially.
The step (b) is preferably carried out by injection of the liquid settable composition and/or sealing agent via an in situ injection zone being in fluid communication with the upper interface, this in situ injection zone of such vertical well comprising casing perforations 37 a (shown in FIG. 2b ).
The liquid settable composition and/or sealing agent which is flowing into the upper interface gap exerts a hydraulic pressure also greater than the overburden pressure present at the upper interface.
The liquid settable composition and/or sealing agent may be injected from the ground surface to the upper (roof) interface 21 via perforations 37 a of well 30.
In some embodiments, the liquid settable composition and/or sealing agent may be injected from the ground surface to the upper interface at a surface temperature which is at least 20° C. higher than the ambient rock temperature (the in situ temperature of the mineral stratum); and the formation of the water-impermeable barrier from said liquid settable composition and/or sealing agent in step (c) may be effected by setting the liquid settable composition and/or sealing agent as it naturally cools while being maintained in the upper interface gap.
Alternatively, the liquid settable composition and/or sealing agent may be injected from the ground surface to the upper interface at a surface temperature which is near the ambient rock temperature (the in situ temperature) at the injection depth. The surface temperature of the liquid settable composition and/or sealing agent may be within +/−5° C. of the in situ temperature, preferably within +/−3° C.
Since the in situ temperature of a trona stratum is estimated to be about 30-36° C. (86-96.8° F.), preferably 31-35° C. (87.8-95° F.), the surface temperature of the liquid settable composition and/or sealing agent may be between about 25 and about 41° C. (about 77-106° F.).
The surface temperature of the liquid settable composition and/or sealing agent may be at least 20° C. higher than the in situ temperature of the trona stratum.
The liquid settable composition and/or sealing agent may be preheated to a predetermined temperature higher than the in situ temperature of the trona stratum.
The liquid settable composition is described here below, while the sealing agent will be described later.
Liquid Settable Composition
The liquid settable composition under surface conditions may be a slurry or gel comprising an aqueous phase in which particles are suspended. The liquid settable composition may comprise a slurry with one or more water-insoluble materials of a suitable size suspended in water or an aqueous solution.
Such composition may comprise a component which swells when in contact with water
The liquid settable composition comprises water-insoluble particles, optionally water-soluble particles, a binder, water, and one or more additives for controlling viscosity and/or setting time,
such water-insoluble particles comprising at least one water-insoluble calcium compound, fused or colloidal silica or silica flour, water-insoluble matter recovered from a mechanically-mined trona after its dissolution in water or aqueous medium, tailings recovered from a trona surface refinery (insoluble material recovered from a soda ash surface refinery which uses mechanically-mined trona), biological solid matter, agricultural solid matter, sand, cementing compositions, bentonite, fly ash, slag, aggregate, plastic, rubber or combinations thereof;
said binder comprising at least one standard cementing material used in well completion or construction activities, one or more polymer resin (such as epoxy resin), or combinations thereof; and
one or more additives used to adjust composition viscosity, setting time, density, or catalyzing agent.
In preferred embodiments, the liquid settable composition is a cementing composition. Cementing compositions including standard cementing material used in well completion or construction activities may be utilized as a component of said liquid settable composition. Suitable cementing compositions may include Portland cement and/or a sulfate-resistant clinker powder mixed with calcium sulfate hemihydrate to form insoluble anhydrite and water, where additives and/or setting retardants can be added to this mixture.
In some embodiments, the composition may comprise water-insoluble particles of an appropriate size range suspended in an unsaturated or saturated aqueous solution. The composition may contain two or more populations of particles of different average sizes, preferably smaller than the width of the interface gap. It is desirable to have wide distribution of particles sizes in order to provide a minimum of void space remaining in the gap so as to effectively plug the gap. Several particulate populations with multimodal particulate size distribution will be useful, and the particles in the various populations may have the same composition, or preferably have different compositions.
The liquid settable composition preferably comprises water-insoluble particles. The water-insoluble particles may comprise water-insoluble calcium compounds (e.g., lime, limestone), fused or colloidal silica or silica flour or silica flour, sand, cement, fly ash, slag, bentonite, water-insoluble solid matter recovered from a mechanically-mined mineral after its dissolution in water or aqueous medium, tailings (insolubles) recovered from a mineral surface refinery, biological and/or agricultural solid matter (such as hulls, shells), or combinations thereof.
Tailings in trona processing represent a water-insoluble matter recovered after a mechanically-mined trona is dissolved (generally after being calcined) in a surface refinery. During the mechanical mining of a trona stratum, some portions of the underlying floor and overlying roof rock which contain oil shale, mudstone, and claystone, as well as interbedded material, get extracted concurrently with the trona. The resulting mechanically-mined trona feedstock which is sent to the surface refinery may range in purity from a low of 75 percent to a high of nearly 95 percent trona. The surface refinery dissolves this feedstock (generally after a calcination step) in water or an aqueous medium to recover alkali values, and the portion which is non-soluble, e.g., the oil shale, mudstone, claystone, and interbedded material, is referred to as ‘insols’ or ‘tailings’. After trona dissolution, the tailings are separated from the sodium carbonate-containing brine by a solid/liquid separation system. The particles size in tailings may vary depending on the surface refinery operations. Typical trona tailings may have particle sizes ranging between 1 micron and 250 microns, although bigger and smaller sizes may be obtained. More than 50% of the particles in tailings generally have a particle size between 5 and 100 microns.
The full range of the mineral tailings may be used as water-insoluble particles in the liquid settable composition. Alternatively, a fraction of the full range of tailings may be used as insolubles in the liquid settable composition. For example, a size-separation apparatus (e.g., wet sieve apparatus) may be used to isolate a specific particles fraction, such as isolating particles passing through a sieve with a specific size cut-off (such as 44 μm=325 mesh) from particles retained by the sieve. The finer particles of tailings (passing through the sieve) may be used as water-insoluble particles in the sealing agent. Alternatively although less preferred, the coarser particles of tailings (retained on the sieve) may be used as water-insoluble particles in the liquid settable composition. The specific size cut-off for the sieve may be 74 microns or lower (200 mesh or higher), preferably 44 microns or lower (325 mesh or higher). In some instances, the specific size cut-off for the sieve may be 37 microns or lower (400 mesh or higher). The fraction of tailings used as water-insolubles in the liquid settable composition may be isolated using two sieves with two size cutoffs, in that the tailings particles in such fraction will pass through a coarser sieve (such as 200-mesh sieve) but will be retained by a finer sieve (such as a 400-mesh sieve). In some embodiments, various size fractions of tailing particles may be used in the liquid settable composition.
The liquid settable composition may comprise water-soluble particles and water-insoluble particles.
When the evaporite stratum comprises trona; and the overlying non-evaporite stratum comprises oil shale, in such instance, the liquid settable composition may comprise, in particulate form and/or in dissolved form, at least a sodium component selected from the group consisting of sodium sesquicarbonate, sodium bicarbonate, sodium carbonate and any of its hydrated forms, and any combinations thereof; and/or the liquid settable composition may comprise particles comprising at least one component of the oil shale.
In some embodiments, the liquid settable composition may comprise trona particles (which may be calcined or uncalcined), particles of a water-insoluble calcium compound (such as calcium hydroxide), a water-insoluble fraction comprising slag particles, fly ash, epoxy cement, Portland cement powder and/or a water-insoluble fraction derived from mechanically-mined trona from a different evaporite stratum or the same evaporite stratum, such as tailings which contain insoluble matter recovered after dissolution of the mechanically-mined trona in a surface refinery.
The liquid composition may be a liquid settable and sealing composition.
In some embodiments, the liquid settable composition may comprise a thixotropic gel containing particles in colloidal suspension in water or an aqueous solution. Silica flour or fly ash can be added to the compositions to make a thixotropic gel.
In preferred embodiments, the liquid settable composition is essentially free of soluble chloride, i.e., contains less than 0.05 wt % soluble chloride, preferably less than 0.03 wt % soluble chloride; more preferably less than 0.01 wt % soluble chloride
In additional or alternate preferred embodiments, the liquid settable composition is essentially free of soluble sulfate, i.e., contains less than 0.05 wt % soluble soluble sulfate; preferably less than 0.03 wt % soluble sulfate; more preferably less than 0.01 wt % soluble sulfate.
In some embodiments, at least one component of the liquid settable composition may undergo a transformation while being in situ to allow it to bond with or bind to the native mineral present in the free mineral surfaces exposed to the liquid settable composition, and/or leave behind compacted or coagulated solid particles to form solidified matter in the upper interfacial gap that will inhibit the future passage of solvent fluid. This step preferably comprises injecting the liquid settable composition in the upper interfacial gap, and maintaining such liquid settable composition in the upper interfacial gap until a change in the physical and/or chemical state of said liquid settable composition or of at least one of its components occurs to form the solidified matter.
The change in the physical and/or chemical state may be bonding with or binding to particles in the composition and/or to the mineral surfaces exposed to the liquid settable composition.
The change in the physical and/or chemical state may be depositing a compacted or coagulated material in the gap that will inhibit future solvent flow.
The change in the physical and/or chemical state may be caused by reaction and/or adsorption of the carrier liquid (preferably water) with at least one water-swelling component of the liquid settable composition. Swelling occurring in the gap will significantly reduce the permeability inside it and inhibit future solvent flow.
The change in the physical and/or chemical state preferably comprises crystallization or precipitation, particles coagulation, particles compaction, cross-linking of at least one liquid settable composition component with liquid settable composition's particles, coagulation of particles (gel formation), water-swelling due to water adsorption and/or reaction with water of at least one liquid settable composition component, and/or wall building of at least one liquid settable composition component with mineral surfaces, to form in situ a solidified matter which covers the mineral free-surfaces which come in contact with the liquid settable composition and to seal or plug the gap thereby preventing access to future solvent flow. As the liquid settable composition is maintained in the remaining open spaces in the upper interfacial gap, more change in the physical and/or chemical state may occur with more bonding or binding.
In some embodiments, the liquid settable composition may include or may consist of a slurry of particles in a water-based carrier liquid. These particles may be:

- water-swelling particles (which may include delayed water-swelling particles) made at least in part from a water-swelling material;
- non-water-swelling particles; or
- a combination of water-swelling particles and non-water-swelling particles of the same or different size distributions.

The water-swelling material in the particles may be a super-absorbing material. Super-absorbing materials are formed from polymers that are water soluble but that have been internally crosslinked into a polymer network to an extent that they are no longer water soluble. Such materials have the tendency to swell or absorb water. Examples of super-absorbing materials are described in U.S. Pat. No. 4,548,847; U.S. Pat. No. 4,725,628, U.S. Pat. No. 6,841,229, US2002/0039869, and US2006/0086501, all incorporated herein by reference. Non-limiting examples of super-absorbing materials include crosslinked polymers and copolymers of acrylate, acrylic acid, amide, acrylamide, saccharides, vinyl alcohol, water-absorbent cellulose, urethane, or any combinations of these materials. Particles of the super-absorbing material may have an unswollen particle size of from about 50 microns to about 1 mm or more.
Water-swelling materials in the particles that are not super-absorbent materials as defined above may also be used. These may include natural water-swelling materials such as water-swelling clays. Non-limiting examples of water-swelling clay materials include bentonite, montmorillonite, smectite, nontronite, beidellite, perlite and vermiculite clays or any combinations of two or more thereof. The water-swelling particles may have an unswollen particle size of from about 50 microns to about 1 mm or more, but typically less than 2 mm.
The water-swelling particles may include delayed water-swelling particles. A delayed water-swelling particle may include a particle having a core of a water-swelling material and a coating substantially surrounding the core that temporarily prevents contact of water (used as liquid carrier) with the water-swelling material. The coating may be formed from a layer of water degradable material or a non-water-degradable, non-water-absorbent encapsulating layer. A non-limiting example of delayed water-swelling particles is described in US2008/108524, incorporated herein by reference.

Step (c)

The present method comprises step (c): allowing the composition selected from the group consisting of the liquid settable composition, the sealing agent, and combinations thereof to stay in the upper interfacial gap for a time sufficient to form a water-impermeable barrier inside the upper interface gap.
This step is illustrated by FIG. 3, in which the composition selected from the group consisting of the liquid settable composition, the sealing agent, and combinations thereof which was flowing inside the upper gap at interface 21 is set while maintaining the hydraulic pressure used in step (b).
If the hydraulic pressure is released too soon, before the liquid settable composition and/or the sealing agent has/have time to cure and/or to solidify, the composition which is in the process of solidifying in the upper interface gap may be squeezed out thereby leaving not much of an effective barrier inside the upper interface gap.
The formation of the water-impermeable barrier in step (c) in underground conditions preferably results in sealing or plugging the gap completely and rendering it water-tight.
Step (c) is preferably carried out for a setting time period of at least 24 hours. This allows a sufficient amount of time after which the settable agent is now hardened or the sealing agent is now solidified and has formed the water-impermeable barrier 41 (illustrated in FIG. 3).
Because the composition is injected inside the well 30 before flowing inside the wells, some of that composition rests on top of the plug 35 a and also solidify in situ and form a pack 41 a immediately above the plug 35 a.
Step (c) is preferably carried out for a time sufficient to permit the water-impermeable barrier 41 to achieve a compressive strength of at least 2300 psi or at least 2500 psi, preferably of at least 3000 psi, more preferably of at least 3500 psi.
The water-impermeable barrier may be formed in step (c) when a change in the physical and/or chemical state of the composition or of at least one of its components occurs.
The water-impermeable barrier may be formed in step (c) by at least one mechanism selected from the group consisting of coagulation, cross-linking, curing, swelling, cementing, grouting, and combinations of two or more thereof.
The water-impermeable barrier may be formed in step (c) by at least cementing, curing, catalyzing, swelling, or grouting of the at least one composition component.
In additional or alternate embodiments, the water-impermeable barrier may be formed during step (c) by at least binding or bonding of at least one component of the composition with the free surface (newly created during step (a)) of the substantially insoluble stratum (ceiling of the upper interface gap) to form a water-impermeable barrier.
During step (c), sealing or plugging the gap may be effected at least in part by a wall-building mechanism in which the water-impermeable barrier may bind to or bond with the native trona from the free ore face (provided by the floor of the upper interface gap) in the upper interface gap.
During step (c), sealing or plugging the gap may be effected at least in part by a wall-building mechanism in which the water-impermeable barrier may bind to or bond with the substantially insoluble material in the open face (provided by the ceiling of the upper interface gap).
Step (c) should significantly reduce the permeability of the material in the upper interface gap.
One objective would be to reduce the permeability of the so-obtained barrier material to approach the permeability of the surrounding matrix (native mineral).
One objective would be to reduce the permeability of the material in the upper interface gap so that the so-obtained barrier material is impervious to liquids and optionally even to gases therethrough.

Step (d)

The method may further comprise: (d) releasing the hydraulic pressure for the overburden to compress the layer of the water-impermeable barrier formed in the gap and/or to squeeze out any uncured liquid settable composition and/or unsolidified sealing agent remaining in the gap.

Step (e)

Once the liquid-impermeable barrier 41 is formed at the upper interface 21 and the hydraulic pressure is released (after steps (a)-(d) are performed) preferably slowly by opening, the present method further comprises step e): forming the cavity in the trona stratum at or above the lower floor interface between the trona stratum and an underlying substantially water-insoluble stratum, such as an oil shale.
The cavity formation step (e) may comprise:

FIG. 4 illustrates step (e1).
The lifting fluid 54 is injected into the same well 30 (same well used for steps (a)-(e)) and into the lower interface gap via injection zone 40 a (in fluid communication between well 30 and interface gap created at lower interface 20).
The injection zone 40 a may be similar to the one previously described for step (a) and/or (b).
As illustrated in FIG. 5, the in situ injection zone 40 a of well 30 is in fluid communication with the lower interface 20. The in situ injection zone 40 a comprises perforations 37 b through which the lifting fluid 54 (e.g., solvent or a sealing agent) can flow from the inside of the well 30 to the gap created in the strata lower interface 20. To obtain the openings 37 b, the casing of the well 30 may be perforated by a perforating gun or a waterjet cutting tool.
The well casing perforations 37 b of the in situ injection zone 40 a preferably are preferably aligned with respect to the plane of the strata lower interface 20. When the well 30 is vertical (as illustrated), the perforations 37 b of the in situ injection zone 40 a may be aligned alongside the strata lower interface 20. When the vertical well 30 goes through the lower interface 20 which is horizontal or near horizontal, perforations 37 b (casing openings) are preferably positioned on at least one casing circumference of this downhole section, such casing circumference being aligned alongside the plane of the strata lower interface 20. The plug 35 a and hardened pack41 a formed near the upper interface 21 were drilled out of the well 30 so that the flow path for the lifting fluid 54 is clear inside well 30.
The method may further comprise perforating the well casing on at least one circumference on a vertical section of well 30, so as to create the casing perforations 37 b aligned alongside the lower interface 20. When the interface 20 is horizontal or near-horizontal, this perforating step may be carried out to allow passage of the injected fluid 54 in a preferential lateral way through the formed perforations 37 b towards the horizontal or near-horizontal interface 20.
The openings 37 b on the casing may be in fluid communication with a conduit inserted into the well 30 to facilitate fluid flow from the ground surface to this well in situ injection zone 40 a (not illustrated).
Additionally, a section of the well 30 which is underneath the interface 20 may be plugged for the lithological displacement step (e1)) and also for the optional steps (a′) to (c′).
In some embodiment the plug 35 b (illustrated in FIG. 5) may be generated preferably before the step (e1). The present method thus may further include forming a drillable plug 35 b whose top edge 38 b does not block the flow of the lifting fluid 54 (e.g., solvent or liquid settable composition) to the lower interface 20 and whose top edge 38 b is located inside the well 30 near and below the lower interface 20 to prevent the lifting fluid 54 (e.g., solvent or sealing agent) to flow down in the well 30 towards the bottom.
The method may further comprise: removing the plug 35 b by drilling it out after a sealing agent is injected (a step illustrated in FIG. 6) in the gap created at the lower interface 20.
One or more vertical wells which may be used as production wells are drilled at a distance from the vertical well 30 which may be used as an injection well. Two vertical wells 45 a, 45 b are illustrated in FIG. 4, although one production well may suffice or more than two production wells may be used. The production wells 45 a, 45 b may be spaced by a distance of at least 50 meters, or at least 100 meters, or at least 200 meters from vertical injection well 30. The wells 45 a, 45 b may be spaced from vertical injection well 30 by a distance of at most 1000 meters, or at most 800 meters, or at most 600 meters. Preferred spacing between production and injections wells may be from 100 to 600 meters, preferably from 100 to 500 meters. The wells 45 a, 45 b are preferably cemented and cased from the ground surface all the way down to, and perhaps below, the lower interface 20 except for a downhole section which is perforated where each well intersects the lower interface 20. Using a downhole perforating tool, perforations may be cut through the casing and cement of each well so that these perforations are in proximity to the interface 20. This perforated downhole section of wells 45 a, 45 b should allow fluid communication with the interface 20.
For the first phase of lithological displacement, the production wells 45 a, 45 b are capped. The injection well 30 is also capped but will allow the fluid 50 to be injected therethrough.
The expanse of the lower interface gap intercepts during lithological displacement the cased and cemented but perforated downhole ends of at least one of the production wells 45 a, 45 b. In this manner, a fluid communication is established between the injection well 30 and at least one production well 45 a, 45 b. In FIG. 4, it is illustrated that fluid communication is established with both production well 45 a, 45 b.
The gap formed at the strata lower interface 20 in this lithological displacement step (e1) would extend laterally in all directions away from the in situ injection zone 40 a for a considerable lateral distance from 30 meters (about 100 feet), to 150 m (about 500 ft), to 300 m (about 1,000 ft), to 500 m (about 1,640 ft), or even up to 610 m (about 2,000 ft) away.
The interface gap formed at the strata lower interface 20 provides an initial cavity from which a solution mining process can be initiated.
FIG. 9 illustrates a system in which a cavity is formed by step (e2).
Two directionally drilled wells 55 a, 55 b were drilled near the floor of the trona stratum 5, each one having at least one uncased horizontal borehole 56 a and 56 b respectively being in fluid communication with the well 30. This well 30 was the injection well through which the liquid setting composition and/or sealing agent was injected in step (b) to provide the water-impermeable barrier 41 at the upper interface 21. The well 30 and the uncased horizontal boreholes 56 a and 56 b are hydraulically connected to a sump 49 in which the brine can collect. A sump pump or a surface pump can push or pull the brine 65 out of the well 30. These hydraulically-connected uncased horizontal boreholes 56 a and 56 b form a suitable cavity from which solution mining of trona can be initiated.
Referring back to the “lithological displacement” step (e1) to be carried out at the lower (floor) interface 20 between the trona stratum 5 and the underlying stratum 10 to form a cavity from which solution mining can be initiated, the depth of the lower interface 20 must be sufficiently shallow so as to encourage the development under hydraulic pressure of a substantially horizontal main fracture extending laterally away from the injection zone 40 a at this interface 20 (lower interface gap) between the trona stratum 5 and the underlying stratum 10, although minor transverse fractures 25 may be exposed (naturally existing) and/or may be newly created. Some of these fractures 25 may grow upwards due to the hydraulic pressure being applied at this interface 20. But thanks for the presence of the water-impermeable barrier, the extended shoots 27 of the fractures 25 do not grow beyond the water-impermeable barrier 41; this lessens the likelihood that a solvent used to dissolve trona from the cavity formed at the lower interface as well as the resulting brine to would escape the confines of the trona stratum 5 being mined.

Optional Sealing Step at the Floor Interface

As this lithological displacement step progresses at the floor interface, it is likely that the injected fluid flow path will intersect a near vertically oriented plane of weakness such as naturally existing faults, joints, lineaments, fissures, voids, or vugs (termed ‘pre-existing fractures’) and/or will artificially induce the formation of new transverse fractures by hydraulic pressure. A pre-existing or new fracture will divert the flow path of the injected fluid upwardly until a new horizontal weakness plane is encountered. It is then conceivable that this “lithological displacement” process would repeat itself many times in many places making one or more “stair-step” fractures which would be difficult to use or completely unsuitable for the purposes of mineral exploitation via solution mining.
Applicants thus propose to use a sealing agent which is injected at the target interface 20 and which would preferentially seal or plug at least a portion of these undesirable transverse fractures 25 and their extensions 27, whether being pre-existing and/or being hydraulically-generated.
This technique is illustrated in FIG. 6, in which a sealing agent 58 is injected via the in situ injection zone 40 a of vertical well 30 located at or near the lower interface 20.
After forming the water-impermeable barrier by applying a liquid settable composition and/or sealing agent at the upper interface using an injection well, the method may comprise:

- (a′) applying a hydraulic pressure which is greater than the overburden pressure at the floor interface to lithologically displace the trona stratum, thereby forming a lower interface gap and exposing a main trona free-surface, wherein said application of hydraulic pressure further induces formation of undesirable transverse fractures and/or intersects natural undesirable transverse fractures in the trona stratum, thereby exposing minor trona free-surfaces in said undesirable fractures;
- (b′) flowing a sealing agent into the lower interface gap and into the transverse fractures; and
- (c′) maintaining such sealing agent in said lower interface gap and said transverse fractures to form a solidified matter inside said transverse fractures and optionally in said lower interface gap.

As shown in FIG. 6, the in situ conditions under which the sealing agent 58 is maintained should be sufficient for the new solidified matter to fill the fractures completely and also to fill at least a portion of the lower interface gap (although it is not necessary to fill this gap entirely) with this step and in some instances also to bond with or bind with the mineral free-surfaces of the fracture 25 and the lower interface gap.
If the hydraulic pressure is released, there may be some or little flowback of liquid. Because the hydraulic pressure is no longer applied, the dominant stress (overburden) will take over. Because of the additional solidified matter which has being formed in the lower interface gap at the bottom of the trona stratum 5, the solidified matter in the gap may be squeezed out of the gap.
A new interface may be formed between the solidified matter in the (filled or partially-filled) lower interface gap and the underlying non-evaporite stratum 10. To initiate solution mining, a solvent (such as fluid 60 in FIG. 7) will then be injected at the depth of the new interface 23 to lift the overlying stratum. The solvent may be effective in flushing at least a portion of the solidified matter present in the gap (acting as a flushing agent) (not illustrated). The solvent may be effective in initiating dissolution of the trona face in the lower interface gap.

Sealing Agent

The sealing agent may be used as the composition or a component of the composition which is injected into the upper interface gap in step (b) and/or as the agent which is injected into the lower interface gap in step (b′).
The injected sealing agent (illustrated as fluid 60 in FIG. 6) may preferentially seal or plug at least a portion of these undesirable transverse fractures by at least one of the following mechanisms:

- crystallization or precipitation;
- cementation;
- compaction or agglomeration of particles;
- coagulation or cross-linking or other reactive mechanism between various components of the sealing agent;
- swelling of the sealing agent (that is to say, increasing its volume) by reaction and/or absorption of at least one sealing agent component with a carrier liquid (e.g., water);
- wall-building of at least one component of sealing agent with native evaporite mineral; or
- any combinations of these mechanisms or equivalents thereof.

Crystallization or precipitation may result from a change from the surface conditions (e.g., temperature, pH, pressure) to different in situ conditions (e.g., temperature, pH, pressure), this change favoring crystals formation or reducing the solubility limit of one or more sealing agent components.
Cementation may result from the time dependent chemical and physical reaction of the materials constituting the sealing agent with one another in order to form a more or less solidified mass within the fracture(s).
Compaction or agglomeration of particles may result from the applied pressure which pushes solid particles being present in the sealing agent and/or being formed in the fraction during step (c) against the solid walls of the fractures, thereby creating particles agglomerates.
Coagulation or cross-linking or other reactive mechanism between various components of the sealing agent may result from in situ conditions favoring reactions between these various components so as to form ionic or covalent bonds between these components form at least a portion of the solidified matter.
Swelling of a component in the sealing agent by reaction with and/or adsorption of water provides a volume expansion inside the fractures, thereby reducing the permeability therein.
Wall-building of at least one component of sealing agent with native evaporite mineral may result from in situ conditions favoring reactions between a component of the sealing agent and the native mineral exposed to the agent in the walls of the fracture so as to form ionic or covalent bonds between the component and native mineral form at least a portion of the solidified matter.
When sealing or plugging the fractures is effected by two or more of these mechanisms during step (c), it may be called a ‘hybrid’ sealing step.
In the course of this lithological displacement′ step (e1), new mineral surfaces may be created in the ‘walls’ surrounding the open space of the fractures. These new walls created in the course of such lithological displacement′ may be referred to as fracture faces′. Such fracture faces may exhibit different types and levels of reactivity. In some instances, fracture faces may exhibit an increased tendency to undergo reactions, including chemical and physical processes that move a portion of a mineral and/or convert the mineral into some other mineral form in the presence of water. In other instances, fracture faces also may exhibit an increased tendency to react with substances in injected fluids that are in contact with those fracture faces, such as water, insoluble solid matter, and other substances which may be found in these fluids, which may become anchored to the fracture face. This reactivity would further decrease the permeability of the mineral stratum by the obstruction of these fractures by any molecules that have become anchored to the fracture faces. This reactivity may be based on pressure solution and precipitation processes. Where two water-wetted mineral surfaces are in contact with each other at a point under strain, the localized mineral solubility near that contact point increases, causing the minerals to dissolve. Minerals in solution may diffuse through the water film outside of the region where the mineral surfaces are in contact (e.g., in the pore spaces of a sealing slurry), where they may precipitate out of solution. The dissolution and precipitation of minerals in the course of these reactions may clog the fractures with mineral precipitate and/or collapsing those fractures by dissolving solid mineral in the surfaces of those fractures.
Although the purpose of the sealing agent in the present disclosure is to prevent liquid flow in the trona stratum's transverse fractures so as to prevent premature dissolution of mineral from the fractures faces, the lithological displacement step (e1) may also enhance and/or create fissures or otherwise zones of permeability in the underlying non-evaporite stratum. The injected sealing agent thus may also be effective in plugging these fissures in the underlying non-evaporite stratum. Although this diverts a portion of the sealing agent to the unexploited non-evaporite stratum and thus increases the consumption of the sealing agent, preventing fluid flow into the underlying stratum's fissures by plugging them with the sealing agent also serves to minimize loss of fluid to the underground formation during the extraction phase of the mineral with a production solvent.
The sealing agent may be categorized in various classes depending on its main components and the various mechanisms used for sealing the undesirable fractures. These sealing agent classes may be defined as follows:
Class I—sodium brines (crystallization/precipitation)

- An unsaturated solution comprising sodium carbonate, sodium bicarbonate, or combination thereof; or
- A saturated solution comprising sodium carbonate, sodium bicarbonate, or combination thereof;
  Class II—slurries/gels containing water-soluble particles (crystallization/precipitation and compaction/agglomeration)
- A slurry or gel comprising solid particles of one or more sodium carbonate species (sesquicarbonate, carbonate, any of its hydrates, bicarbonate) in a saturated or unsaturated solution comprising sodium carbonate, sodium bicarbonate, or combination thereof;
- A slurry or gel comprising at least a first population of water-soluble solid particles of one or more sodium carbonate species: sesquicarbonate, carbonate, any of its hydrates, bicarbonate, and at least a second population of water-insoluble particles, these populations being suspended in a saturated or unsaturated solution comprising sodium carbonate, sodium bicarbonate, or combination thereof;
  Class III—slurries or gels containing water-insoluble particles (compaction/agglomeration)
- A slurry comprising water-insoluble particles suspended in water, in a sodium brine (a saturated or unsaturated solution comprising sodium carbonate, sodium bicarbonate, or combinations thereof), or in a non-sodium brine, the water-insoluble particles for example comprising a clay material (such as bentonite, montmorillonite), limestone, lime, cement, sand, biological and/or agricultural solid matter (such as ground-up hulls, shells), and/or tailings particles (a fraction of tailings particles may be isolated based on size e.g., via sieve to obtain fine tailings particles of a specific size range such as of 44 microns or less, or even of 37 microns or less);
- A colloidal gel comprising water-insoluble particles in colloidal suspension in water, in a sodium brine, or in a non-sodium brine;
  Class IV—reactive non-sodium brines/slurries/gels (wall-building)
- A brine comprising one or more non-sodium solutes that will interact in situ with evaporite mineral to form a water-insoluble wall-building precipitate which interlocks crystal lattice with evaporite mineral on walls;
- A slurry or gel comprising one or more non-sodium particles and/or one or more non-sodium solutes that will interact in situ with evaporite mineral to form a water-insoluble wall-building precipitate which interlocks crystal lattice with evaporite mineral on walls;
  Class V—reactive slurries or gels containing water-insoluble and optionally water-soluble particles (wall-building, cross-linking, compaction, cementation, and crystallization/precipitation)
- a slurry or gel comprising water-insoluble particles and optionally water-soluble particles in a brine containing at least one solute, in which at least one type of particles and/or the solute react with each other and/or react with native evaporite mineral from fractures' walls or with the liquid carrier to form a solidified matter; the particles may comprise water-soluble sodium particles of one or more sodium carbonate species: sesquicarbonate, carbonate, any of its hydrates, bicarbonate, and one or more water-insoluble materials (e.g., trona insolubles also called tailings), particles of crystallized solute(s) (e.g., calcium hydroxide and/or carbonate), and/or one or more water-swelling particles (particularly, clays, bentonite being preferred);
- same as above except that the particles are suspended in a sodium brine comprising one or more solutes that will react in situ with evaporite mineral to form a wall-building solidified matter and/or that will react in situ with the sodium solute to form a cross-linked or precipitated matter.
  Class VI—reactive organic/inorganic slurries (cross-linking, coagulation, compaction)
- a slurry or gel comprising water-insoluble particles and/or water-swelling in a polymeric solution that will react in situ to form a coagulated, swollen, and/or cross-linked solidified matter.

Any solid material in the sealing agent may be particulates, which individually are solid in the sense that fluid does not pass through each particulate. The solid material may or may not be rigid and may change in state while in situ to provide a fluid blocking function to plug the fractures.
In some embodiments, two or more particles populations or fractions of different average particle sizes may be simultaneuously used during one injection of sealing agent.
The sealing agent may contain two or more populations of particles of different average sizes, although their average sizes should be smaller than the width of the pre-existing and/or new transverse fractures to be sealed. Smaller particles can block the pore spaces formed by the larger particles. It may be desirable to have a wide distribution of sizes of the particles of the solid material in order to allow good compaction with a minimum of void space remaining in the fractures so as to effectively seal or plug the fractures. For example, two or three particulate materials, at least one of which being preferably insoluble in an aqueous medium, with different size ranges being “disjointed” may be used in the sealing agent. Suitable “bimodal” or “trimodal” combinations of particulates may comprise any two or three particulate populations having the following average sizes: “large” (average size of 100-500 micrometers); “medium” (average size of 10-50 micrometers); “fine” (average size of 1-5 micrometer); or “very fine” (average size of 0.1-0.50 micrometers). Examples of such multimodal particulate distribution can be found in U.S. Pat. No. 5,518,996 by Maroy et al entitled “Fluids for oilfield use having high-solids content”. Several particulate populations with multimodal particulate size distribution will be useful, and the particles in the various populations may have the same composition, or preferably have different compositions. For example, two particulate populations: particulate solid matter from tailings and trona particles (e.g., T200® powder) may be mixed in water or aqueous solution to form a slurry with a bimodal particulate distribution which can be used as a sealing agent in the present invention.
In alternate embodiments, two or more particles populations or fractions of different average particle sizes may be used in successive injections of the sealing agent.
The particles size in tailings may vary depending on the surface refinery operations. Typical trona tailings may have particle sizes ranging between 1 micron and 250 microns, although bigger and smaller sizes may be obtained. More than 50% of the particles in tailings generally have a particle size between 5 and 100 microns. The full range of the mineral tailings may be used as water-insoluble particles in the sealing agent. Alternatively, a fraction of the full range of tailings may be used as insolubles in the sealing agent. For example, a size-separation apparatus (e.g., wet sieve apparatus) may be used to isolate a specific particles fraction. The fraction of tailings used as water-insolubles in the sealing agent may be isolated using two sieves with two size cutoffs, in that the tailings particles in such fraction will pass through a coarser sieve (such as 200-mesh sieve) but will be retained by a finer sieve (such as a 400-mesh sieve). In some embodiments, various size fractions of tailing particles may be used in the the sealing agent.
In alternate embodiments, various particles populations or fractions having different average sizes may be used successively in the sealing agent. In particular, the average particle size may be decreased in the sealing agent over time during the sealing agent injection, either in a continuous fashion or in a step-wise fashion. For example, a sealing agent comprising particles of a first average particle size may be first injected at the interface for a given period of time, and subsequently a sealing agent comprising particles of a second average particle size which is less than the first average particle size is injected at the interface for another period of time. By using various particles populations or fractions having decreasing average sizes in the sealing agent, it is expected that the particles of larger size get initially placed inside the fractures leaving some void spaces and forming a sort of mesh, and thereafter the particles of smaller size fill in the void spaces between the particles of larger size, thereby reducing the permeability of the solidified matter (packed particles) inside the fractures. It would be thus preferred if the second average particle size of the (smaller) particles is equal to or less than the average size of the void spaces left in the interstices between the larger particles. There may be more than two successive injection stages, each stage using a lower average particle size than the preceding stage. Any two or more particulate populations having the following average sizes: “large” (average size of 100-500 micrometers); “medium” (average size of 10-50 micrometers); “fine” (average size of 1-5 micrometer); or “very fine” (average size of 0.1-0.50 micrometers) may be used in succession in the sealing agent, so long as the average particle size decreases over time during the duration of sealing agent injection.
The concentration of the solid material in the sealing agent may range from 0.0001 to 1500 pound per barrel of liquid phase (carrier for the particles). The total amount of solid material has to be enough to seal or plug the fractures.
In another embodiment, the sealing agent may comprise or consist of a settable material so that it becomes a solid after setting inside the fractures, but the settable material initially flows into the gap and fractures as a liquid.
In yet another embodiment, the sealing agent may also be used a liquid settable material.
In yet another embodiment, a liquid settable material may be utilized as carrying liquid along with a solid material.
In some embodiments, the step (c′) is carried out until no more void space is available in the undesirable fractures, thereby plugging them completely with this solidified matter. Once plugged, these transverse fractures would no longer be available to allow a production solvent, injected at the target lower interface, to deviate course through these undesirable fractures. Instead, the production solvent would be confined to flow through the near-horizontal target lower interface created in the lower interface gap between the new layer of solidified matter and the underlying non-evaporite stratum where the discontinuity between the solidified matter, and the incongruent underlying non-evaporite stratum (oil shale) will once again provide a plane of weakness upon which a lithological displacement may again take place.
In the case of trona overlying a shale stratum, the sealing agent composition is carefully selected for sealing or plugging these undesirable fractures but also to form a new interface with a new layer of solidified matter inside the gap and the underlying shale stratum, in such a way that the incongruence between the newly-created overlying solidified matter layer and the underlying shale layer would remain. In this instance, when a production solvent is injected later at pressures slightly above the overburden lifting pressure, the exerted hydraulic pressure would once again separate the overlying layer away from the oil shale stratum in order for exploitation of the trona via dissolution to begin.
Without wishing to be bound by a particular theory, Applicants believe that several conditions must be satisfied to provide a good outcome in this “lithological displacement” technique using such sealing agent. These conditions are as follows:

- 1. The targeted injection plane should be at a depth below the surface that would favor the formation of a main horizontal hydraulic fracture (at a depth less than 3,000 feet, preferably depth of 2,500 feet or less, more preferably depth of 2,000 feet or less); trona beds lying at a depth of from 800 to 2,500 feet below ground surface would typically qualify for such injection.
- 2. Since a fracture will follow the path of less resistance, its propagation and orientation are mainly determined by the local stress field and the tensile strength of the formation; as such, horizontal fractures will develop only when the vertical stress (weight of the overburden) is lower then the horizontal (tectonic) stress; this is what normally happens at the shallow depths described above.
- 3. The target zone of evaporite stratum should have a natural weakness plane with the underlying stratum. (In the case of trona, trona and oil shale are very dissimilar materials and form a very weak bond between them.)
- 4. The evaporite mineral should be soluble to varying degrees in an appropriate solvent at various temperatures. The material in the overlying and/or underlying strata should be substantially insoluble in the applied solvent. (Trona would qualify as a suitable evaporite mineral as it is soluble in water, while the overlying and/or underlying shale layers are, for the most part, insoluble in water.)
- 5. The sealing agent which is injected at the lower interface between the trona stratum and an underlying stratum may comprise at least one component which undergoes a physical and/or chemical change to form a solidified matter, and the sealing agent should satisfy specific conditions:
  - it should flow relatively freely into the lower interface gap (main fracture) which is hydraulically-created at the strata lower interface and into the undesirable transverse fractures (whether they may be pre-existing and/or newly hydraulically-created);
  - at least one of its components should undergo a physical and/or chemical state change at the target bed in situ conditions such as crystallization or precipitation, solid compaction/agglomeration, coagulation, cementation, reactive wall-building with mineral in fractures' walls, coagulation and/or cross-linking with a solute and/or particles present in the sealing agent composition, thereby creating a solidified matter and sealing the undesirable fractures against future solvent flow;
  - the solidified matter (e.g., crystallized/precipitated, cross-linked, coagulated, cemented, agglomerated, and/or compacted matter) may or may not dissolve upon contact with a production solvent which is introduced at the lower interface after the undesirable transverse fractures of the target block of the trona stratum have been sealed. In preferred embodiments the solidified matter may be insoluble and impervious to the production solvent, but could be, in most part, removed by injecting an intermediary solvent designed to specifically target the removal of such solidified matter in the main fracture (lower interface gap) resulting from the hydraulically-induced lithological displacement, or by simply reducing the pressure after injection to be less than the overburden pressure and thus allow the weight of the overburden to displace the sealing agent from the lower interface gap. Or the solidified matter may be insoluble in the production solvent but having a poor bond to the underlying non-evaporite stratum (e.g., oil shale) such that the new near-horizontal plane of weakness between the layer of solidified matter deposited in the lower interface gap (main fracture) and the underlying non-evaporite stratum will still exist and could be flushed out of such gap via injection of a production solvent at an appropriate pressure. Or the solidified matter may be insoluble in the production solvent, but having only a weak bond with the overlying trona ore upon which the hydraulic pressure can once again act to separate the evaporite stratum from the underlying solidified layer at just over the overburden lifting pressure, but the solidified matter remains trapped and impenetrable in the undesirable transverse fractures.

For sealing or plugging undesirable fractures in a lithologically displaced trona bed by the sealing agent (also termed as ‘trona glue’), a suitable sealing agent may be selected from:

- a solution comprising sodium carbonate and/or bicarbonate which is at least 95% saturated (preferably at least 98% saturated, more preferably at least 99% saturated, most preferably saturated) at the surface injection temperature and which is supersaturated at the underground in situ (trona bed) mineral temperature and pressure;
- a slurry or gel comprising water-soluble particles, water-insoluble particles, or combinations thereof in suspension in a liquid phase; or
- combination of the two.

The solidified matter plugging these undesirable fractures should be nearly impenetrable to fluid flow after sealing or plugging. However in preferred embodiments, the solidified matter has, at the mouth opening of a plugged fracture, a free solid surface which may be available for dissolution upon contact with an appropriate solvent and/or for chemical attack upon contact with an appropriate reactant. This free solid surface of the solidified matter at the mouth opening of a plugged fracture may be eroded by exposure to a solvent or reactive agent.
Although various liquids and solids may be combined to make such a suitable sealing agent to seal or plug unwanted fractures in a block of trona, the properties of the most suitable materials for a ‘trona glue’ should be as follows:

- the initial sealing agent composition at the surface before injection, i.e., the liquid phase components and particles if any are used, and the in situ sealing agent composition obtained after injection, i.e., the crystallized or crosslinked or otherwise solidified matter, should be compatible with solution mining of trona—(that is to say a non-contaminant, or a compound which can be easily removed after dissolution during surface refining);
- the solidified matter created in situ and/or compacted/agglomerated particles used in the initial sealing agent composition are not substantially water-soluble or are otherwise removable at in situ temperature in the most appropriate solvent (such as water);
- the sealing agent in the form of a solution or slurry or gel is capable of flowing easily under pressure;
- for a slurry or gel in particular, particles contained herein should stay more or less in suspension in the liquid phase of the sealing agent;
- in some embodiments, the solidified matter forms a barrier to inhibit the flow of a production solvent inside the undesirable fractures at some future time during a production phase—however any free-surface of the solidified matter which comes in contact with the production solvent during solution mining should be substantially resistant to dissolution upon contact;
- in some embodiments for ‘trona glue’, a slurry or gel containing particles in a solution (liquid phase) which is saturated under in situ conditions forms crystals capable of forming a crystal lattice between slurry particles and the native trona which comes in contact with the injected fluid—a preferred crystalline form would be crystals of a hydrated form of sodium carbonate such as sodium carbonate decahydrate or heptahydrate.
  Preferred gluing materials for trona lithological displacement are selected from:
- an aqueous solution comprising a sodium salt selected from the group consisting of sodium carbonate, sodium bicarbonate, and any combinations thereof, such solution being at least 95% saturated (preferably at least 98% saturated, more preferably at least 99% saturated, most preferably 100% saturated) in said sodium inorganic salt when at the surface injection conditions and which is saturated or supersaturated when at the in situ (trona stratum) conditions of temperature, pH;
- a slurry or gel comprising water-soluble sodium-based particles at various size distributions suspended in an aqueous liquid phase (carrier fluid), wherein the aqueous liquid phase is saturated or supersaturated in a sodium salt selected from the group consisting of sodium carbonate, sodium bicarbonate, and any combinations thereof, when at the surface injection conditions and at the in situ (trona bed) conditions, and wherein the sodium particles comprises a sodium compound selected from the group consisting of sodium carbonate, sodium bicarbonate, sodium sesquicarbonate, and any combinations thereof;
- a slurry or gel comprising water-insoluble non-sodium particles at various size distributions suspended in water or an aqueous liquid phase, wherein the water-insoluble non-sodium particles may be particles comprising or consisting of silica particles, silica-alumina, trona tailings (the full range of tailings size or one or more tailings particle size fractions), calcium oxide, calcium hydroxide, and wherein the aqueous liquid phase may include or may exclude any sodium salt selected from the group consisting of sodium carbonate, sodium bicarbonate, and any combinations thereof;
- a slurry or gel comprising varying densities and percentages of at least one of the following particle populations: water-soluble particles comprising sodium carbonate, sodium bicarbonate, sodium sesquicarbonate, or mixtures of these particles, and water-insoluble particles comprising silica particles, shale particles, pulverized tailings from mechanically-mined trona, insoluble calcium inorganic compounds (e.g., Ca(OH)2 and/or CaO), at various size distributions dispersed in an aqueous liquid phase, wherein the aqueous liquid phase may be water; may include or may exclude any sodium salt selected from the group consisting of sodium carbonate, sodium bicarbonate, and any combinations thereof, in which case the aqueous liquid phase is preferably saturated or supersaturated in sodium carbonate and/or bicarbonate when at the surface injection conditions and at the in situ (trona bed) mineral conditions;
- a slurry in a water-based carrier liquid comprising water-swelling particles (which may include delayed water-swelling particles formed at least in part from a water-swelling material), preferably water-swelling particles may comprise a water-swelling clay such as bentonite, montmorillonite, smectite, nontronite, beidellite, perlite and vermiculite clays or any combinations of two or more thereof; or
- combinations thereof.
  More preferably, the sealing agent for trona lithological displacement may be:
- a slurry or gel with uncalcined or calcined trona particles at various size distributions suspended in an aqueous liquid phase, wherein the aqueous liquid phase is at least 95% saturated (preferably at least 98% saturated, more preferably at least 99% saturated, most preferably 100% saturated) in sodium carbonate when at the surface injection and saturated or supersaturated in sodium carbonate when at the in situ (trona bed) mineral temperature;
- a slurry or gel with uncalcined or calcined trona particles at various size distributions, milk of lime, and tailings from mechanically-mined trona, these particles being suspended in an aqueous liquid phase which may include a sodium salt selected from the group consisting of sodium carbonate, sodium bicarbonate, and any combinations thereof;
- a slurry or gel with uncalcined or calcined trona particles at various size distributions and particles of calcium hydroxide (milk of lime may be used), these particles being suspended in an aqueous liquid phase which may be include a saturated calcium hydroxide solution and optionally a sodium salt selected from the group consisting of sodium carbonate, sodium bicarbonate, and any combinations thereof—milk of lime is a suspension of calcium hydroxide particles in limewater (saturated solution of calcium hydroxide) with a pH of 12.3.
- a slurry or gel with particles of calcium hydroxide (milk of lime) and tailings from mechanically-mined trona, these particles being suspended in an aqueous liquid phase which may be include a saturated calcium hydroxide solution and which may include or exclude a sodium salt selected from the group consisting of sodium carbonate, sodium bicarbonate, and any combinations thereof.
- a slurry comprising particles of tailings obtained from processing of mechanically-mined trona or nahcolite in a surface refinery, these particles having various sizes and being suspended in water or in an aqueous liquid phase which may, but not necessarily, include a sodium salt selected from the group consisting of sodium carbonate, sodium bicarbonate, and any combinations thereof.
- a slurry or gel with particles and chemically reactive agents such as tricalcium silicate, dicalcium silicate, tricalcium aluminate, tetracalcium aluminoferrite and their oxides in various ratios, any mixtures of these calcium-based compounds, and/or other chemicals known to make good cementing agents;
- a slurry in a water-based carrier liquid comprising water-swelling particles (which may include delayed water-swelling particles formed at least in part from a water-swelling material), comprising a water-swelling clay (preferably Na bentonite, Ca bentonite, and/or montmorillonite); or
- any combinations thereof.

The uncalcined or calcined trona particles may have a D50 of 100 microns or less; preferably a D50 of 75 microns or less; more preferably a D50 of 50 microns or less. A suitable source for trona particles is T-200® trona, which is a mechanically refined trona ore product available from Solvay Chemicals, Inc. produced in Green River, Wyo. T-200® trona contains about 97.5% sodium sesquicarbonate and has a mean particle size of about 24-28 microns.
The aqueous phase is preferably saturated in sodium carbonate when at the surface injection and supersaturated in sodium carbonate at the in situ (trona bed) temperature.
The initial (surface) solid content of the sealing agent in form of slurry or gel at the time of injection may be 2 wt % or more; or 2.5 wt % or more; or 3 wt % or more. Thick slurries of solid contents greater than about 10 wt % will form solidified matter in situ more rapidly in the fractures. However solid content impacts flowability of the slurry or gel. So there is a trade-off between slurry/gel pumpability and time necessary for forming the solidified matter in step (c).
The in situ content in solidified matter in the injected sealing agent in form of slurry or gel after injection should be higher than the initial (surface) solid content. The in situ content in solidified matter in the injected sealing agent after undergoing the physical and/or chemical change in situ should be at least 30 wt %, or at least 50 wt %, or at least 75 wt %, or at least 80 wt %.
The remaining void in the sealed fractures should be 30% in volume or less, preferably 20% in volume or less, more preferably 17% in volume or less.
In some embodiments, the sealing agent for trona lithological displacement may be a thixotropic gel. The thixotropic gel preferably comprises particles in colloidal suspension in an aqueous liquid phase, said particles having a D50 of 10 microns or less; preferably a D50 of 5 microns or less; a D50 of 2 microns or less. The particles preferably comprise sodium sesquicarbonate or trona, sodium carbonate, silica, bentonite, montmorillonite, or combinations thereof; more preferably the particles comprise trona. Additionally or alternatively, the particles in the slurry or gel may comprise or consist of colloidal silica. Colloidal silicas are suspensions of fine amorphous nonporous silica particles in a liquid phase. The silica particles may be nanosized. In some embodiments, the particles in the slurry or gel may comprise or consist of bentonite. A bentonite suspension for example would provide a good thixotropic sealing agent.
The aqueous phase in the thixotropic gel may be at least 95% saturated (preferably at least 98% saturated, more preferably at least 99% saturated, most preferably 100% saturated) in sodium carbonate when at the surface temperature and saturated or supersaturated in sodium carbonate when at the in situ (trona bed) temperature. Alternatively, the aqueous phase in the thixotropic gel may be water.
In some embodiment, the sealing agent maybe either comprise water or a saturated or unsaturated aqueous solution acting simply as a carrier of solid water-insoluble material such as tailings (obtained from mechanically-mined trona), lime, shale insolubles, . . . designed to seal or plug the undesirable gaps through the mechanism of wall-building (via surface binding and/or bonding) and/or compaction. In one variant of this embodiment, a solute or solutes of the aqueous solution may also react with the free-surface of trona in the undesirable fractures to form a bound material with the insoluble material.
In a particular embodiment, the sealing agent comprises water or a dilute alkali solution acting as a carrier liquid for water-swelling particles designed to seal or plug the undesirable gaps through the mechanism of swell upon contact with water. In one variant, the water-swelling particles contain Na bentonite or Ca bentonite. Natural Wyoming bentonite contain predominantly Na, while the natural European bentonites contain predominantly Ca. Ca bentonite can adsorb between 150% and 200% water relative to its own weight, while Na bentonite can adsorb between 500% and 700% water relative to its own weight. Dispersion of bentonite is aided by the addition of a small amount of an electrolyte; but too high ion concentration can flocculate bentonite. Additionally, if the initial hydration of bentonite to make the slurry is carried out in a strong electrolyte (e.g., concentrated sodium carbonate solution), no swelling will take place. So it is preferred to use water or a dilute sodium-based solution as the carrier liquid in the slurry. In the instance when Ca bentonite carried by a water-based carrier liquid is used in the sealing agent, it may be useful to convert the Ca bentonite to Na bentonite by an ion-exchange process, called ‘activation’. Based on GB4770, a soda-activation by an exchange of the Ca²⁺ions by Na⁺ions in the montmorillonite (major component of bentonite) improves most of the properties of the basic Ca bentonite:
Ca²⁺−Montmorillonite+Na2CO3→2 Na⁺−Montmorillonite+CaCO3 The Ca²⁺ions react with the CO3²⁻anions forming calcium carbonate of low solubility.
This soda-activation can be carried out inside the fractures when the water dissolves trona from the water-exposed trona faces in the fractures thus providing sodium cations to exchange with Ca cations in the bentonite. According to this process, the Na⁺ions can completely replace the Ca²⁺ions if the amount of sodium carbonate dissolved in water inside the fractures is sufficient to correspond to the cation exchange capacity of the Ca bentonite. As a result the swelling property of the bentonite is increased in situ.
In yet another embodiment, a sealing agent may comprise a non-sodium component in a liquid phase, such as calcium hydroxide and/or oxide in the form of water-insoluble particles suspended in the liquid phase and/or as a solute in the liquid phase, wherein such non-sodium component of the sealing agent after being injected may react with native trona on the walls of the gap and fractures to form a new water-insoluble compound. The non-sodium component in a liquid phase may be for example calcium hydroxide and/or oxide in the form of water-insoluble particles suspended in the liquid phase and/or as a solute in the liquid phase. The reaction would form solid calcium carbonate (precipitate) which would have substantially more volume than the initial dissolved and/or suspended calcium component and would form a strong water-insoluble seal or plug in the undesirable fractures. The calcium carbonate formed in the target gap could then be removed later by a flushing agent. The bound and compacted calcium carbonate in the gap may be flushed by flowing a weak acidic solvent (e.g., a dilute hydrochloric acid solution, for example, 0.5-5% HCl).
The sealing agent used in methods of the present invention optionally may comprise any number of additional additives, including, but not limited to, surfactants, gel stabilizers, acids, foamers, corrosion inhibitors, scale inhibitors, catalysts, clay control agents, biocides, bactericides, friction reducers, antifoam agents, bridging agents, dispersants, flocculants, lubricants, viscosifiers (such as guar gum), weighting agents, pH adjusting agents (e.g., buffers), relative permeability modifiers, solubilizers, and the like. A person skilled in the art, with the benefit of this disclosure, will recognize the types of additives that may be included in the displacement fluids for a particular application.
Optional Steps after Optional Sealing Step
In some embodiments, the method may be effective in preparing a free mineral face suitable for solution mining exploitation of the evaporite mineral, as follows:
(d′)—releasing hydraulic pressure to squeeze solidified matter out of gap or flushing solidified matter out of gap out by flushing agent;
(e′)—injecting a propping agent;
(f′)—injection of a flushing′ fluid (different than the sealing agent) after the sealing step (c′).
Step (d′) may comprise releasing the hydraulic pressure to reach hydrostatic pressure to squeeze solidified matter and/or remaining unsolidified sealing agent out of the gap. This step (d′) may be carried out after the sealing step (c′).
In some embodiments, in which the solidified matter is not bound, or is weakly bound, to the native mineral on the bottom of the trona stratum inside the floor interface gap, the method may further comprise step (e′): injection of a flushing′ fluid (different than the sealing agent) after sealing step (c′). Step (e′) may be used to flush at least a portion of this solidified mass from the lower interface gap, while keeping the solidified matter in the unwanted sealed fractures. The bottom edge of the solidified matter in the sealed transverse fractures may be eroded by this flushing′ fluid, but the bulk of the solidified matter should be maintained in place inside the transverse fractures. Step (e′) may be used in lieu of the step (d′).
In yet additional or alternate embodiments, the method may further comprise: (f′) injection of a propping fluid.

- Step (f′) may be carried out at the same time as step (b) or (b′).

In order to maintain and/or enhance the flow-ability of the main hydraulically-created fracture (lower interface gap) in the trona stratum, particulates with high compressive strength (often referred to as “proppant”) may be deposited in the open space of the main fracture, for example, by introducing a fluid carrying the solid proppant into the main fracture. The proppant may prevent the main fracture from fully closing upon the release of the hydraulic pressure, forming fluid flow channels through which a production solvent may flow to a production well. Once the main fracture is created and the proppant is substantially in place in the main fracture, the liquid which carries the proppant may have a lower viscosity than the previously-injected fluids (e.g., sealing agent, flushing agent) and the production solvent may be recovered from the trona stratum. The process of placing proppant in a fracture is referred to herein as “propping” the fracture. Although it may be desirable to use proppant in maintaining fluid flow paths in the main fracture, dissolution of trona by the solvent will enlarge the fracture over time. As such, the proppant may be needed only at the beginning of cavity development, and in some instances this propping step (f′) may be omitted from the method.
This optional propping step (f′) may be carried out after the sealing step (c′) without releasing the hydraulic pressure or preferably after releasing the hydraulic pressure and re-applying a hydraulic pressure by flowing the propping fluid. This step (f′) may be carried out after a flushing step (e′) without releasing the hydraulic pressure, or after releasing the hydraulic pressure and which also will evacuate some of the flushing agent loaded with solidified matter and re-applying a hydraulic pressure by flowing the propping fluid.
Solution Mining with a Solvent and Extraction of Brine
The method may further comprise:

- (f) injecting an aqueous solvent into the cavity formed (generally at or near the floor) in the trona stratum and which is located underneath said created water-impermeable barrier to dissolve some of the trona ore and to form a brine comprising sodium carbonate and/or bicarbonate in the cavity; and
- (g) extracting at least a portion of the resulting brine to the ground surface. The water-impermeable barrier formed at the trona upper interface minimizes contact and dissolution of at least one water-soluble contaminant from an overlying stratum with the aqueous solvent and resulting brine, and/or reduces leakage of contaminant-laden water percolating from overburden into the cavity which is being mined.

Step (b) and (f) may be carried out from the same well, and step (g) is carried out from one or more different wells.
Step (b) and (g) are carried out from the same well, and step (f) is carried out from one or more different wells.
FIG. 7 shows the same setup as illustrated in FIG. 4 or 6, but illustrates a solution mining step subsequent to forming the cavity in the trona ore (step (e)) in which a fluid 60 is injected into wells 45 a, 45 b to flow into the cavity to come in contact with trona ore, and a brine 65 is collected to the surface via well 30. It is to be noted that in this embodiment, the well 30 which was used initially to make the barrier 41 and to form the lower interface gap, is now used as a production well. However, well 30 may continue to be used as an injection well, if one of the wells 45 a, 45 b is down dip and can be used as a production well.
The fluid 60 may be injected at a volumetric flow rate selected from about 20 m³/hr to 300 m³/hr or from about 2.8 to 42 barrels/min (preferably within 10% of the flow rate selected for the injection of fluid 54 when the trona stratum initially was lithologically displaced at the lower interface), to allow the hydraulic pressure to rise at the in situ injection zone 40 until it reaches, within +/−10%, the target hydraulic pressure used during the cavity forming step. Care should be taken here not to create new vertical fractures.
If the technique of sealing or plugging the transverse fractures is used to prepare the cavity, the fluid 60 may dislodge and/or dissolve the layer of new solidified matter left in between the trona stratum 5 and the stratum 10 in the gap which was created during hydraulic displacement (fluid 60 acting as flushing fluid). Then the fluid 60 may start dissolving the free trona face at the bottom of the trona stratum 5. The fluid 60 may also erode the fluid-exposed surface of the solidified matter present at the opening of the sealed fractures. In any or all of the embodiments of the in situ solution mining method and system according to the present invention, the fluid 60 used as a flushing agent may comprise a dilute acid aqueous solution (e.g., comprising 1-5% HCl).
If the technique of sealing or plugging the transverse fractures was not used in preparing the cavity, the fluid 60 used for trona dissolution (production solvent) may be water or may comprise an aqueous solution comprising a desired solute (e.g., at least one evaporite mineral component such as at least one alkali value). A production solvent employed in such in-situ trona solution mining method may contain or may consist essentially of water or an aqueous solution unsaturated in desired solute in which the desired solute is selected from the group consisting of sodium sesquicarbonate, sodium carbonate, sodium bicarbonate, and mixtures thereof. The water in the fluid 60 may originate from natural sources of fresh water, such as from rivers or lakes, or may be a treated water, such as a water stream exiting a wastewater treatment facility. The fluid 60 may be caustic. An aqueous solution in the fluid 60 may contain a soluble compound, such as sodium hydroxide, caustic soda, any other bases, one or more acids, or any combinations of two or more thereof.
In the case of trona stratum, the fluid 60 may be an aqueous solution containing a base (such as caustic soda), or other compound that can enhance the dissolution of trona in the solvent. The fluid 60 may comprise at least in part an aqueous solution which is unsaturated in the desired solute, for example a solution which is unsaturated in sodium carbonate and which is recycled from the same solution-mined target trona bed and/or from another solution-mined trona bed which may be adjacent to or underneath the target trona bed.
The fluid 60 may be preheated to a predetermined temperature to increase the solubility of the solidified matter to be removed from the gap when it is used as a flushing fluid, or to increase the solubility of one or more desired solutes present in the mineral ore when it is used as a production solvent.
The fluid 60 employed as a solvent in the in-situ trona solution mining step may comprise or may consist essentially of a weak caustic solution for such solution may have one or more of the following advantages. The dissolution of sodium values with weak caustic solution is more effective, thus requiring less contact time with the trona ore. The use of the weak caustic solution also eliminates the ‘bicarb blinding’ effect, as it facilitates the in situ conversion of sodium bicarbonate to carbonate (as opposed to performing the conversion ex situ on the surface after extraction). It also allows more dissolution of sodium bicarbonate than would normally be dissolved with water alone, thus providing a boost in production rate. It may further leave in the mined-out cavity an insoluble carbonate such as calcium carbonate which may be useful during the mining operation.
It should be noted that the composition of the solvent used as fluid 60 may be modified during the course of the trona solution mining operation. For example, water as fluid 60 may be used to form initially a mined-out cavity at the trona free face, while sodium hydroxide may be added to water at a later time in order to effect for example the conversion of bicarbonate to carbonate during the solution mining production step, hence resulting in greater extraction of desired alkaline values from the trona stratum 5.
The surface temperature of the injected fluid 60 can vary from 32° F. (0° C.) to 250° F. (121° C.), preferably up to 220° F. (104° C.).
The temperature of fluid 60 may be between 0° F. and 200° F. (17.7-104° C.), or between 104 and 176° F. (40-80° C.), or between 140 and 176° F. (60-80° C.), or between 100 and 150° F. (37.8-65.6° C.). The higher the injected fluid temperature, the higher the rate of dissolution at and near the point of injection.
The brine 65 which is removed to the surface may have a surface temperature generally lower than the surface temperature of the fluid 60 at the time of injection. The surface temperature in the extracted brine 65 may be at least 3° C. lower, or at least 5° C. lower, or at least 8° C. lower, or even at least 10° C. lower, than the surface temperature of the injected fluid 60.
The extracted brine 65 preferably has a chloride content being equal to or less than 0.5 wt %.
The temperature of the injected fluid 60 generally changes from its point of injection as it gets exposed to trona. Because the fluid temperature at time of injection is generally higher than the in situ temperature of the trona stratum, the brine loses some heat as it flows through the mined cavity until the brine 65 gets extracted via well 30.
The flow of fluid 60 may depend on the size of the cavity, such as the length of its flow path inside the cavity, the desired time of contact with ore to dissolve the mineral from the free face, as well as the stage of cavity development whether it be nascent for ongoing formation or mature for ongoing production. For example, the injected fluid flow rate in wells 45 a, 45 b may vary from 9 to 477 cubic meters per hour (m³/hr) [42-2100 gallons per minute or 1-50 barrels per minute]; from 11 to 228 m³/hr [50-1000 GPM or 1.2-23.8 BBL/min]; or from 13 to 114 m³/hr (60-500 GPM or 1.4-11.9 BBL/min); or from 16 to 45 m³/hr (70-200 GPM or 1.7-4.8 BBL/min); or from 20 to 25 m³/hr (88-110 GPM or 2.1-2.6 BBL/min).
The dissolution generally leaves a layer of insolubles at the bottom of the solution-mined cavity, such insolubles layer providing a (porous) flow channel in the cavity for the brine to flow therethrough.
The dissolution of the desired solute may be carried out under a pressure lower than hydrostatic head pressure, or be carried out at hydrostatic head pressure. The pressure may vary depending on the depth of the target ore bed. The dissolution of the desired solute may be carried out under a pressure lower than hydrostatic head pressure (at the depth at which the solution—mined cavity is formed) during the hydraulic displacement. The dissolution of the desired solute may be carried out at hydrostatic head pressure after a mined-out cavity is formed, for example during a production phase in which the voided space in the trona stratum containing insolubles is filled with liquid solvent.
The solution mining step may further comprise step (i): injecting a compressed gas into the mining cavity. This step (i) is preferably carried out to prevent dissolution of the ore roof into the solvent.
The solution mining step may comprise a cavity formation phase with lateral expansion where the cavity is not filled with liquid, followed by a production phase where the cavity is filled with liquid.
It is envisioned that brine aliquots may be analyzed continuously or intermittently for desired solute content as well as for contaminant levels. For example, in the case of the trona solution mining, brine aliquots may be analyzed for TA content and chloride content. Rising chloride contents in successive brine aliquots may be used as an indication that the solution-mined cavity is approaching a chloride-laden stratum near the trona roof.
The solution mining step may be carried out in a continuous mode, in which a production solvent is injected and passed through the mined-out cavity, while at the same time the brine is removed to the surface.
The solution mining step may be carried out in a batch mode, which may be termed a ‘fill-and-soak’ mining method. The production solvent injection is initiated to fill up the void created below the trona face and then stopped, so that the non-moving solvent dissolves the desired solute further cutting the exposed trona free face until the production solvent gets impregnated with desired solute (preferably until it reaches at least 12% TA) or gets saturated with desired solute, at which point the resulting brine is removed (pumped or pushed) to the surface. Once the mined-out cavity is drained, fluid 60 as production solvent is injected again, and the batch process (filling cavity to contact trona faces, stopping solvent flow, dissolution, brine collection) is repeated.
Another embodiment of the solution mining step may include multiple vertical or horizontal wells used as injection and/or production wells whereby the production solvent can be directed in such a way as to expose the trona to a slow but continuous flow of solvent with sufficient residence time to become saturated.
FIG. 8 illustrates a plan view of a solution mining exploitation from an initial cavity created by lithological displacement (step (e1)) with a lower interface gap 62 of similar extent that the water-impermeable barrier 41 created by the steps (a)-(c) from the same well 30. This solution mining process uses 3 injections wells 45 a, 45 b, 45 c and a center production well 30, the surface position of the respective wellhead of wells 45 a, 45 b, 45 c being with the extent of the water-impermeable barrier 41 created by the steps (a)-(c).
FIG. 10 illustrates a plan view of a solution mining exploitation from an initial cavity created by horizontal boreholes (step (e2)) interconnected by the well 30 with a cavity extent 63 being within the extent of the water-impermeable barrier 41 created by the steps (a)-(c) from the same well 30. This solution mining process uses 3 injection directionally drilled wells 55 a, 55 b, 55 c with their respective uncased horizontal boreholes 56 a, 56 b, 56 c and a center production well 30 in fluid communication with each horizontal boreholes 56 a, 56 b, 56 c, the surface position of the respective wellhead of wells 55 a, 55 b, 55 c being with the extent of the water-impermeable barrier 41 created by the steps (a)-(c).
With respect to any or all embodiments of the present invention, a periodic (or intermittent or continuous) injection of insoluble materials (such as tailings) concurrently with the solvent may be carried out. The injection of insoluble materials may comprise: periodically mixing a specified amount of insoluble material with the solvent and injecting the combined mixture directly into the cavity. Such injection of insoluble materials may form islands of insoluble material that would shift the solvent flow to fresh ore (e.g., trona) and/or would form some support for any possibility of downward-moving ore roof. In this manner, a support system of insoluble material may be constructed to halt the roof movement to a desired point while flow channels created by dissolution of the solute in the ore region surrounding the insoluble material would allow for movement of the brine through this region of the ore. Deposits of insoluble materials (such as tailings) may also be employed to block certain flow pathways, especially those which may short-circuit passing over (or bypass) fresh ore, such as observed with the phenomenon of ‘channeling’.
It is to be understood that, either due to the nature of the roof rock or through the way in which this process will gradually allow the roof to sag and lay down without much fracturing, brine contamination from roof material may not be a major issue especially if the water-impermeable barrier does not crack of break. Should this be the case, Applicants believe that the system can still be operated much more aggressively in terms of solvent flow rates.
For this reason, when an underground formation comprises a plurality of trona strata separated by a series of interburdens, the present invention provides for the sequential solution mining of selected trona strata from the top down. If one intends to mine an upper stratum once a lower stratum has been extracted, there is a possibility that the upper interface at the top of the upper stratum may no longer be clearly parting, and that overburden subsidence may have modified the lithological placement of these weak interfaces. It is believed that the created water-impermeable barrier remains effective if there is little subsidence of the overburden which would have caused changes to the interfaces profiles and/or if there was some cracking of this barrier permitting leakage from this interburden and contact from solvent underneath this barrier.
In an underground formation containing a plurality of trona strata comprising sodium sesquicarbonate and having various heights and located at different depths, said trona strata being separated by a series of substantially-insoluble interburdens containing water-soluble contaminants selected from the group consisting of chloride, sulfate, and water-soluble organics, each trona stratum comprising an ore roof with an upper interface with the immediately-overlying interburden,
a method for minimizing brine contamination from interburdens during in situ trona solution mining of two or more trona strata from said plurality, comprising:

- selecting a trona stratum being the first trona stratum from the top down of said plurality which contains a minimum of 60% sodium sesquicarbonate and which has a stratum height of at least one meter;
- carrying steps (a) to (c) of the method according to the first aspect of the present invention in said first selected trona stratum using a vertical well drilled through said first trona stratum;
- carrying step (d) in which the hydraulic pressure is released after the water-impermeable barrier is set in the upper interface gap of the first selected trona stratum in order to form a tight seal between the barrier and the immediately-overlying interburden and between the barrier and the trona ore immediately located underneath this barrier;
- carrying out step (e), preferably after steps (a) to (d) are completed, in which a first cavity is formed in said first selected trona stratum by a technique comprising:
  - lithological displacement of the first trona stratum at the floor interface by injecting a lifting fluid at such interface through the same well through which the liquid settable composition and/or sealing agent is injected in step (b) or through a different well; or
  - forming at least one uncased horizontal borehole from a directionally drilled well, said at least one uncased horizontal borehole being in fluid communication with the well through which the liquid settable composition and/or sealing agent is injected in step (b).
- carrying out step (f) in which an aqueous solvent is injected into the first cavity formed in the first selected trona stratum and which is located underneath said barrier so as to dissolve some of the trona ore and to form a brine comprising sodium carbonate and/or bicarbonate in the first cavity; and
- carrying out step (g) in which at least a portion of the resulting brine is extracted to the ground surface via one or more of production wells;

wherein said water-impermeable barrier formed at the trona upper interface minimizes contact and dissolution of at least one water-soluble contaminant from the interburden with the aqueous solvent and resulting brine, and/or reduces leakage of contaminant-laden water percolating from overlying interburden into the first cavity which is being mined;

- carrying step (h) in which steps (f) and (g) are stopped when the brine extracted from the first cavity has a level of said contaminant exceeding a threshold content above which is not acceptable for make a salable product or when the first cavity is enlarged by dissolution to reach the roof of said first cavity;
- selecting a second trona stratum being the next trona stratum located underneath the first trona stratum from the top down of said plurality which contains a minimum of 60% sodium sesquicarbonate and which has a stratum height of at least one meter;
  - repeating steps (a) through (h) on said second trona stratum, preferably using the same vertical well used in steps (a) to (c) with the first trona stratum, optionally drilling further down if necessary past the floor of the second trona stratum, and using one or more of the same production wells used in step (g) with the first trona stratum, optionally drilling said one or more production wells further down if necessary past the floor of the second trona stratum.

FIG. 11 illustrates an underground formation in which two strata (105, 108) were previously solution mined according to the present invention using the formation of a water-impermeable barrier, and in which solution mining of a virgin trona stratum 110 is initiated by injected the liquid settable composition and/or sealing agent 50 into the well 30 as described in relation to FIG. 1. Although only one well is illustrated in FIG. 11, more than one well is generally used in the solution mining of a cavity It is to be understood that should some of the wells used in the exploitation of the previous stacked cavities (such as from strata 105, 108) and the development of stratum 110 get compromised (displaced, crushed, stacked . . . ), In such instance, a new well may be drilled down to continue the exploitation.
The other trona strata (106 107, 109, 111) are not selected as suitable strata to solution mine as they are not meeting at least one criterion, such as a criterion being selected from the group consisting of:
having a height of 1 meter of more; and
having a sodium sesquicarbonate content of 60 wt % or more, preferably a sodium sesquicarbonate content of 65 wt % or more.
For any or all embodiments of the present invention, some underground gas may be released from the underlying stratum (especially comprising oil shale) or when part of the overburden susceptible to gravitational loading and crushing cracks and falls into the cavity. This released underground gas may contain methane. Indeed, in the case of trona mining, even though the trona itself contains very little carbonaceous material and therefore liberates very little methane, the underlying and overlying methane-bearing oil shale strata may liberate methane during lithological displacement and/or during mining. When such underground gas release occurs during lithological displacement, purges of the released gas may be performed periodically to remove the gas and relieve pressure so as to prevent gas buildup and/or to minimize safety concerns. It is recommended to stop solvent flow downhole during such gas purge. Purge of released gas may be effected by passage to the surface via the well used for brine production. Alternatively, the purge of released gas may be effected by one or more secondary purge wells (not illustrated in figures). It is also conceived that much of the gas may dissolve in the solvent/brine and in which case dissolved gas may leave the liquid freely under low pressure conditions at the surface.
The present method may further comprise step (j): purging some of the gas from the cavity to the surface. The gas which is purged may comprise released underground gas (such as methane) and/or blanket gas (such as air or nitrogen, CO₂, or combinations thereof) which may be injected during step (i). Step (j) may be performed periodically to relief pressure inside the cavity.
A brine collection zone (for example sump 49 in FIGS. 7 and 9] may be created at a downhole end of production wells (generally below the trona stratum floor) to facilitate the recovery of the brine from the trona mined-out cavity. The formation of the collection zone may be by mechanical means (such as drilling past the trona/shale interface) and optionally by chemical means (such as solution mining with a localized application of unsaturated solvent at the base of the mineral stratum).
A region of the collection zone may have a lower elevation (greater depth) than the bottom of the trona stratum.
A pumping system may be installed so that the brine can be pumped to the surface for recovery of the alkali values. Suitable pumping system can be installed at the downhole end of production wells or at the surface end of these wells. This pumping system might be an ‘in-mine’ system at bed level or a ‘terranean’ system from the surface. A brine return pipe may be placed into the downhole collection zone in fluid communication with a terranean pumping system to allow the brine 65 to be pumped or pushed to the surface.
The brine 65 extracted at the surface may be saturated in sodium carbonate, but in most instances the brine 65 is unsaturated in sodium carbonate. A portion 66 of such brine 65 may be processed for recovery of the sodium values, while another portion 67 may be re-injected though an injection well.
Such solution mining step may be carried out in a continuous mode in which the fluid 60 (production solvent) is injected, so that the moving solvent dissolves the desired solute from the exposed free-surface, while at the same time at least a portion of the brine is removed to the surface.
However, it is also envisioned that the solution mining step may be carried out in a batch mode, which may be termed a ‘cut-and-soak’ mining method. In such case, the solvent injection is first injected until the solvent fills the mined-out cavity and thereafter the solvent flow is stopped to let the non-moving solvent dissolve in place the exposed trona free-surface until the brine gets laden with sodium values (for example reaches at least 12% TA). The resulting brine is removed to the surface. Once the mined-out cavity is drained, more solvent can be injected, and the batch method is repeated.
The system may be operated under pressure allowing the surrounding rock to maintain or exert a pressure to the local strata minimizing any local ground pressures. The pressure on the surrounding rock may be exerted by liquid, or exerted by gas by utilizing injection of air or some natural ground gas in the cavity. The temperature, flow rates of the solvent and the density of the resulting solution may be monitored.
Overall this cavity development may be effectively provided to desired areas through the use of tailings to direct flows and varying flow rates, temperature and saturation levels of the injected solvent. The tailings may also act to form a barrier from the underlying floor (shale floor) and contaminants potentially falling from the upper areas of the trona stratum, keeping liquid from contamination by the overlying shale layer if the water-impermeable barrier has discontinuities of roof coverage (e.g., uneven distribution of liquid settable composition during step (b); or cracking of the barrier 41 due to settling of the roof during mining. The solvent thus may include tailings which then deposit on the floor of the mined-out cavity. Deposited tailings change flow paths through damming effects and direct the solvent flow.
In yet another embodiment of the present invention, the solution mining step for trona ore uses the layer of insoluble rock that is deposited in the formed mined-out cavity by the dissolution of trona. This layer of insoluble separates the floor and ceiling of the mined-out cavity, while mechanically supporting the cavity ceiling, the latter one being the bottom interface for the trona rubble and the trona stratum above it. Such insoluble layer gets thicker as more and more of the trona overburden get dissolved, and provides, through its porosity, a channel through which the solvent can pass through.
In the second aspect, the invention relates to a method for minimizing gas migration into the overburden from the immediately underlying cavity which is solution mined in the evaporite stratum.
One advantage of such method according to the second aspect would be to keep inside the cavity any gas (such as methane) which may be released during solution mining of the mineral ore (e.g., trona) and which may accumulate inside the cavity which is solution mined. In the case of trona mining, trapping any released methane may be indeed advantageous for the extraction of methane to the surface and recovery of its energy for example in a surface refinery which processes the brine to make one or more valuable products.
Another advantage of such method according to the second aspect would be to keep a blanket gas (such as air, nitrogen, CO₂, or combinations thereof)—which is typically used to control ore dissolution rates and geometry—from migrating out of the target cavity.
According to this second aspect to the present invention, in an underground formation containing a trona stratum comprising sodium sesquicarbonate lying above one or more methane-containing strata, said trona stratum comprising an ore roof with a parting upper interface above which is defined an overburden up to the ground and below which an aqueous solvent will be injected in a cavity to dissolve trona and to form a brine which is recovered at least in part at the ground surface, the method for minimizing gas migration into the overburden from the immediately underlying cavity which is solution mined in the trona stratum comprises steps (a) to (c) or steps (A) to (C), as specified above, except that the barrier or solidified matter which is formed inside the upper interface gap in step (c) or (C) is gas-impermeable.
In this second aspect, the method may further comprise any of the additional steps (d) through (h) as described herein.
The method according to the second aspect may further comprise step (i) as described herein, and the formed barrier or solidified solid prevents the injected gas to migrate out of the solution-mined cavity into the overburden.
The method according to the second aspect may further comprise step (j) as described herein, and the formed barrier or solidified solid prevents the released underground gas to migrate out of the solution-mined cavity into the overburden.
In the case of methane release during trona mining, since methane has a relative density compared to air of about 0.55, this buoyancy allows methane to move upwards in the cavity to collect at the ceiling of the cavity which is underneath the gas-impermeable barrier which has been formed at the upper interface gap. This gas-impermeable barrier should minimize the migration of methane above the overburden. In this way, a significant portion of the released methane can be kept underneath the ore roof. This collected gas comprising methane can be purged directly to the surface through a vent bore. The methane extraction from the cavity may be performed periodically or continuously. Periodical purges of this underground gas comprising methane may be preferred in step (j), and the solvent flow into the cavity would be momentarily interrupted during the periodic gas purges. A methane-powered pump or exhauster may be used to facilitate the flow of underground gas through the vent well.
The recovered underground gas which comprises the released mine methane can have a very high methane content. In addition to methane, the recovered underground gas may further comprise nitrogen, (diatomic) oxygen, nitrogen-containing compounds, ethane, propane, butane, other non-methane hydrocarbons, water, ammonia, carbon dioxide, or any mixtures thereof.
If a gas blanket is maintained in order to protect the roof while the cavity is being developed inside a trona stratum, and if methane is released, the released methane will mix with the gas blanket (such as nitrogen, air, CO₂, or combinations thereof). In the case of downhole injection of a gas blanket inside the cavity, periodical purges of the resulting gas mixture may be performed to remove the methane diluted with blanket gas.
Purge gas quality may range from nearly 100% methane to as low as 25% methane. In some embodiments, the recovered purge gas may comprise at least 30% methane, or at least 50% methane. In preferred embodiments, the recovered purge gas may have a concentration of at least 70% methane, more preferably at least 80% methane, most preferably at least 90% methane. In additional or alternate preferred embodiments, the recovered purge gas may comprise at most 98% methane. In some embodiments, the purge gas may comprise any methane content between 25% and 98%, or between 70% and 98%.
The invention can advantageously provide a source of energy for the surface facility which processes the mined non-combustible ore in order to extract the desired mineral, such as processing mined trona in a soda ash refinery. It is recommended that at least a part of the recovered methane be directed to the surface refinery which processes the brine in order for this methane to be used as fuel for the operation of one or more pieces of equipment used in the surface refinery. Examples of use may be for generation of heat, steam, and/or electricity by boilers, furnaces, and/or turbines.
In the case of trona mining according to the invention, the brine resulting from solution mining of trona may be evaporated in one or more evaporators. Evaporators require heat and/or steam generation, which can be provided by burning (combusting) at least a portion of the recovered purge gas (comprising mine methane) in a furnace or boiler.
One other possible use for the recovered methane might be to heat any fluid which is to be injected. For example, any of the following streams: composition 50 in FIG. 1, 2 a, 2 b; sealing agent used in composition 50 in FIG. 1, 2 a, 2 b and sealing agent 58 in FIG. 6; lifting fluid 55 in FIG. 4,5; and injected fluid 60 in FIG. 7, may be preheated before being injected into the interface gaps or cavity. A portion of such heat may be provided by burning (combusting) at least a portion of the recovered purge gas (comprising mine methane).
Yet another possible use for the recovered methane might be to dry any wet solid product resulting from the processing of the brine in the surface refinery (such as any sodium-based product related to the fourth aspect of the present invention).
For the purpose of purge gas use as a fuel, the lower content in methane of the recovered purge gas compared to commercial-grade natural gas is not an issue. As such, the recovered purge gas containing the mine methane can replace an equivalent energy content of a certain quantity of natural gas that would otherwise need to be purchased.
In the case of trona mining according to the invention, the method further comprises: combusting the recovered methane in a flare (also termed flared) or using the recovered methane as an energy source in the surface refinery. This step allows the reduction of “Greenhouse Gas” (GHG) emissions by converting methane emission into carbon dioxide. It has been determined that methane is 21 times more potent than carbon dioxide as a GHG. Thus, conversion of mine methane purged from the cavity to carbon dioxide by combustion (e.g., burning in the surface refinery and/or flaring) will reduce GHG emissions by a factor of 18.25 tons of carbon dioxide equivalent per ton of mine methane, after accounting for the GHG contribution of carbon dioxide produced by combusting the mine methane.
In the third aspect, the present invention also relates to a manufacturing process for making one or more sodium-based products from an evaporite mineral stratum comprising a water-soluble mineral selected from the group consisting of trona, nahcolite, wegscheiderite, and combinations thereof, said process comprising:
carrying out any aspect or embodiment of the method according to the present invention to solution mine the trona stratum and to dissolve trona from the main mineral free-surface created at the strata interface into a solvent to obtain a brine comprising sodium carbonate and/or bicarbonate, and
passing at least a portion of said brine through one or more units selected from the group consisting a crystallizer, a reactor, and an electrodialysis unit, to form at least one sodium-based product.
In trona solution mining, the brine extracted to the surface may be used to recover alkali values.
Examples of suitable recovery of sodium values such as soda ash, sodium sesquicarbonate, sodium carbonate decahydrate, sodium bicarbonate, and/or any other sodium-based chemicals from a solution-mined brine can be found in the disclosures of U.S. Pat. No. 3,119,655 by Frint et al; U.S. Pat. No. 3,050,290 by Caldwell et al; U.S. Pat. No. 3,361,540 by Peverley et al; U.S. Pat. No. 5,262,134 by Frint et al.; and U.S. Pat. No. 7,507,388 by Ceylan et al., and these disclosures are thus incorporated by reference in the present application.
Another example of recovery of sodium values is the production of sodium hydroxide from a solution-mined brine. U.S. Pat. No. 4,652,054 to Copenhafer et al. discloses a solution mining process of a subterranean trona ore deposit with electrodialytically-prepared aqueous sodium hydroxide in a three zone cell in which soda ash is recovered from the withdrawn mining solution. U.S. Pat. No. 4,498,706 to Ilardi et al. discloses the use of electrodialysis unit co-products, hydrogen chloride and sodium hydroxide, as separate aqueous solvents in an integrated solution mining process for recovering soda ash. The electrodialytically-produced aqueous sodium hydroxide is utilized as the primary solution mining solvent and the co-produced aqueous hydrogen chloride is used to solution-mine NaCl-contaminated ore deposits to recover a brine feed for the electrodialysis unit operation. These patents are hereby incorporated by reference for their teachings concerning solution mining with an aqueous solution of an alkali, such as sodium hydroxide and concerning the making of a sodium hydroxide-containing aqueous solvent via electrodialysis.
The manufacturing process may comprise: passing at least a portion of the brine comprising sodium carbonate and/or bicarbonate:

- through a sodium sesquicarbonate crystallizer under crystallization promoting conditions to form sodium sesquicarbonate crystals;
- through a sodium carbonate monohydrate crystallizer under crystallization promoting conditions to form sodium carbonate monohydrate crystals;
- through a sodium carbonate crystallizer under crystallization promoting conditions to form anhydrous sodium carbonate crystals;
- through a sodium carbonate hydrate crystallizer under crystallization promoting conditions to form crystals of sodium carbonate decahydrate or heptahydrate;
- to a sodium sulfite plant where sodium carbonate is reacted with sulfur dioxide to form a sodium sulfite-containing stream which is fed through a sodium sulfite crystallizer under crystallization promoting conditions suitable to form sodium sulfite crystals; and/or
- through a sodium bicarbonate reactor/crystallizer under crystallization promoting conditions comprising passing carbon dioxide to form sodium bicarbonate crystals.

In any embodiment of the present invention, the process may further include passing at least a portion of the brine through one or more electrodialysis units to form a sodium hydroxide-containing solution. This sodium hydroxide-containing solution may provide at least a part of the lifting fluid to be injected into the gap for the lifting step and/or may provide at least a part of the production solvent to be injected into the cavity for the dissolution step.
In any embodiment of the present invention, the process may further comprise pre-treating and/or enriching with a solid mineral and/or purifying (impurities removal) the extracted brine before making such product.
The fourth aspect of the present invention further relates to a sodium-based product obtained by the manufacturing process according to the present invention, said product being selected from the group consisting of sodium sesquicarbonate, sodium carbonate monohydrate, sodium carbonate decahydrate, sodium carbonate heptahydrate, anhydrous sodium carbonate, sodium bicarbonate, sodium sulfite, sodium bisulfite, sodium hydroxide, and other derivatives.
The present invention having been generally described, the following Examples are given as particular embodiments of the invention and to demonstrate the practice and advantages thereof. It is understood that the examples are given by way of illustration and is not intended to limit the specification or the claims to follow in any manner.

EXAMPLES

Example 1

Several small (¼-inch diameter) holes were drilled in a block of trona, and the exposed holes were covered by a piece of oil shale. A settable concrete mixture was injected into the holes and at the interface between the trona and the oil shale, and the trona/oil shale sandwiched assembly was submerged in water inside a beaker. After 24 hours, the concrete had hardened even while the assembly was being held in water. The concrete bonded the oil shale and to the trona surface with which it was in contact. Dissolution of the trona from trona block surfaces exposed to water initiated while the block was been submerged, and as trona dissolved around the concrete, a concrete ‘pad’ remained at the interface and continued to bond with the oil shale.
This disclosure of all patent applications, and publications cited herein are hereby incorporated by reference, to the extent that they provide exemplary, procedural or other details supplementary to those set forth herein.
Should the disclosure of any of the patents, patent applications, and publications that are incorporated herein by reference conflict with the present specification to the extent that it might render a term unclear, the present specification shall take precedence.
Accordingly, the scope of protection is not limited by the description set out above, but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims.
Each and every claim is incorporated into the specification as an embodiment of the present invention. Thus, the claims are a further description and are an addition to the preferred embodiments of the present invention.
While preferred embodiments of this invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit or teaching of this invention. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of systems, methods, and processes are possible and are within the scope of the invention.
What we claimed is:

Claims

1. In an underground formation containing a trona stratum comprising sodium sesquicarbonate lying above one or more substantially-insoluble strata containing water-soluble contaminants selected from the group consisting of chloride, sulfate, and water-soluble organics, said trona stratum comprising an ore roof with a parting upper interface above which is defined an overburden up to the ground and below which an aqueous solvent is to injected in a cavity to dissolve trona and to form a brine which is recovered at least in part at the ground surface,

a method for minimizing brine contamination from overburden during in situ trona solution mining of a cavity formed in the trona stratum, comprising:

(a) applying a hydraulic pressure which is greater than the overburden pressure at the upper interface to lithologically displace the overburden from the trona ore roof, thereby forming an interface gap;

(b) flowing a composition selected from the group consisting of a liquid settable composition, a sealing agent, and combinations thereof, into the upper interface gap; and

(c) allowing such composition to stay for a time sufficient to form a barrier inside said upper interface gap, said barrier being water-impermeable and optionally gas-impermeable.

2. The method according to any of the preceding claims, wherein the steps (a) and (b) are performed at the same time by injecting said composition to apply said hydraulic pressure at the upper interface and for its flowing into said upper interface gap.

3. The method according to claim 1, wherein step (b) is carried out by injection of said composition via a vertical well which is drilled from the ground surface through the trona stratum and past the floor of the trona bed, and wherein the vertical well is cased and cemented through its entire length, but comprises an in situ injection zone being in fluid communication with the upper interface, said in situ injection zone of said vertical well comprising a downhole end opening and/or casing perforations.

4. The method according to claim 1, wherein the hydraulic pressure is applied in step (a) by using a fracture gradient between 0.95 psi/ft and 1.5 psi/ft, preferably between 1 psi/ft and 1.3 psi/ft, more preferably between 1.05 psi/ft and 1.15 psi/ft; and wherein the hydraulic pressure in step (b) is maintained to the hydraulic pressure used in step (a) when steps (a) and (b) are not carried out simultaneously.

5. The method according to claim 1, wherein said composition comprises water-insoluble particles, optionally water-soluble particles, a binder, water, optionally one or more additives for controlling viscosity and/or setting time, density, or a catalyzing agent; wherein said water-insoluble particles comprise a calcium compound; fused or colloidal silica; silica flour; tailings recovered from a trona surface refinery; biological solid matter; agricultural solid matter; sand; cementing compositions; bentonite; fly ash; slag; aggregate; plastic; rubber; at least one cementing material used in well completion or construction activities; one or more polymer resins; or combinations thereof.

6. The method according to claim 5, wherein said composition is a liquid settable cementing composition.

7. The method according to claim 1, wherein said upper interface of said trona stratum is at a shallow depth of 2,500 feet or less.

8. The method according to claim 1, wherein said defined upper interface is horizontal or near-horizontal.

9. The method according to claim 1, wherein step (c) is carried out for a time sufficient to permit said barrier to achieve a compressive strength of at least 2500 psi.

10. The method according to claim 1, wherein step (c) is carried out for a setting time period of at least 24 hours to permit said barrier to set completely.

11. The method according to claim 1, wherein said barrier formed in step (c) is also gas-impermeable.

12. The method according to claim 11, further comprising step (i): injecting a blanket gas into the cavity, wherein said formed gas-impermeable barrier prevents said injected blanket gas to migrate out of the cavity into the overburden.

13. The method according to claim 11, further comprising step (j): releasing methane during trona solution mining into the cavity and extracting at least some of the methane from the cavity to the ground surface, and wherein said formed gas-impermeable barrier prevents the released methane to migrate out of the cavity into the overburden.

14. The method according to claim 1, further comprising:

(d) releasing the hydraulic pressure after said barrier is formed in said upper interface gap in order to form a tight seal between said barrier and said immediately-above stratum and between said barrier and said trona ore immediately located underneath said barrier.

15. The method according to claim 1, further comprising:

e) forming the cavity in the trona stratum at or above a floor interface between said trona stratum and an underlying substantially water-insoluble stratum, after steps (a)-(d) are performed;

said cavity formation step (e) comprising:

lithological displacement of said trona stratum at said floor interface by injecting a lifting fluid at said floor interface through the same well through which said composition is injected in step (b) or through a different well; or

forming at least one uncased horizontal borehole from a directionally drilled well, said at least one uncased horizontal borehole being in fluid communication with said well through which said composition is injected in step (b).

16. The method according to claim 1, wherein said trona stratum is immediately above a substantially water-insoluble stratum and comprising a defined parting floor interface between the two strata, and wherein said method further comprises:

(a′) applying a hydraulic pressure which is greater than the overburden pressure at said floor interface to lithologically displace said trona stratum, thereby forming a lower interface gap between said strata and exposing a main trona free-surface, wherein said application of hydraulic pressure further induces formation of new undesirable transverse fractures and/or intersects natural undesirable transverse fractures in said trona stratum, thereby exposing minor trona free-surfaces in said undesirable fractures;

(b′) flowing a sealing agent into said lower interface gap and into said transverse fractures; and

(c′) maintaining such sealing agent in said lower interface gap and said transverse fractures to form a solidified matter inside said transverse fractures and optionally in said lower interface gap.

17. The method according to claim 16, wherein step (b) and (b′) are carried out from the same well.

18. The method according to claim 16, wherein said sealing agent comprises water-insoluble particles, said water-insoluble particles comprising at least one water-insoluble calcium compound, fused or colloidal silica, bentonite, water-insoluble matter recovered from a mechanically-mined trona after its dissolution in water or aqueous medium, tailings recovered from a mineral surface refinery, biological solid matter, agricultural solid matter, sand, cement, or combinations thereof.

19. The method according to claim 16, wherein step (b) includes,

before injecting said composition into the cavity via a well, forming a drillable plug whose top edge does not block the flow of said composition to the upper interface and whose top edge is located inside the well near and below the upper interface to prevent said composition to flow down in the well; and wherein after the barrier is set in said upper interface gap, the method further comprises: removing said plug by drilling said plug out.

20. The method according to claim 1, further comprising:

(f) injecting an aqueous solvent into the cavity formed in said trona stratum and which is located underneath said barrier to dissolve some of the trona ore and to form a brine comprising sodium carbonate and/or bicarbonate in the cavity; and

(g) extracting at least a portion of the resulting brine to the ground surface; wherein said barrier formed at said trona upper interface minimizes contact and dissolution of at least one water-soluble contaminant from an overlying stratum with said aqueous solvent and resulting brine, and/or reduces leakage of contaminant-laden water percolating from overburden into the cavity which is being mined.

21. The method according to claim 20, wherein step (b) and (f) are carried out from the same well, and step (g) is carried out from one or more different wells.

22. The method according to claim 20, wherein step (b) and (g) are carried out from the same well, and step (f) is carried out from one or more different wells.

23. The method according to claim 1, wherein step (b) is carried out by injection via a well with a casing, and wherein prior to applying the hydraulic pressure, the method further comprises:

placing a drillable plug in said casing slightly below said upper interface; and

perforating or cutting said casing at said upper interface to allow fluid communication between said upper interface gap and the inside of said casing.

24. The method according to claim 23, wherein after performing said maintaining step, the method further comprises:

drilling the drillable plug positioned slightly below the upper interface and optionally any possible excess matter which is solidified from said composition in a casing region immediately above said plug.

25. The method according to claim 24, wherein, after drilling said drillable plug and optionally any excess solidified matter, the method further comprises:

perforating or cutting said casing to provide casing opening(s) at a lower interface between said trona stratum and an underlying stratum to allow fluid communication between said lower interface and the inside of said casing; and

after this cutting step, a lifting fluid is applied to said lower interface to lift said trona stratum from said underlying stratum, said lifting fluid comprising a solvent being suitable for dissolving trona and to form a brine.

26. The method according to claim 1, wherein the recovered brine has a chloride content being equal to or less than 0.5 wt %.

27. In an underground formation containing a plurality of trona ore strata comprising sodium sesquicarbonate and being of various heights and located at different depths, said trona strata being separated by a series of substantially-insoluble interburdens containing water-soluble contaminants selected from the group consisting of chloride, sulfate, and water-soluble organics, each trona stratum comprising an ore roof with an upper interface with the immediately-overlying interburden,

a method for minimizing brine contamination from interburden during in situ trona solution mining of two or more trona ore strata from said plurality, comprising:

selecting two or more trona ore strata to be mined from the top down of said plurality based on selection criteria comprising a minimum of 60 wt % sodium sesquicarbonate in said trona ore and a minimum stratum height of at least one meter;

carrying out sequentially in the selected trona ore strata to be mined from the top down, the following steps (a) to (h) as follows:

steps (a) to (c) of the method according to claim 1 on a selected trona ore stratum using a well drilled through said selected trona ore stratum;

step (d): releasing the hydraulic pressure after the barrier is set in the upper interface gap of the selected trona ore stratum;

step (e): forming a cavity at or near and above the floor interface with the underlying interburden comprising a technique selected from the group consisting of lithological displacement of the trona ore stratum at the floor interface; and forming at least one uncased horizontal borehole;

step (f): injecting a solvent in the formed cavity to dissolved trona and thereby enlarging the cavity and to form a brine;

step (g): extracting at least a portion of the resulting brine to the ground surface via one or more of production wells;

step (h): stopping steps (f) and (g) when the brine extracted from the cavity has a level of said contaminant exceeding a threshold content above which is not acceptable for make a salable product or when the cavity is enlarged by dissolution to reach the roof of said cavity; and

repeating steps (a) through (h) on a selected trona stratum meeting said criteria and being the next one to-be-mined from the top down of said plurality located underneath the previously-mined trona stratum, preferably using the same vertical well used in steps (a) to (c) with the previously-mined trona stratum, optionally drilling said vertical well further down if necessary past the floor of the to-be-mined trona stratum, and using one or more of the same production wells used in step (g) during mining of the previously-mined trona stratum, optionally drilling said one or more production wells further down if necessary past the floor of the to-be-mined trona stratum.

28. In an underground formation containing a trona stratum comprising sodium sesquicarbonate lying above one or more substantially-insoluble strata containing water-soluble contaminants selected from the group consisting of chloride, sulfate, and water-soluble organics, said trona stratum comprising an ore roof with a parting upper interface above which is defined an overburden up to the ground and below which an aqueous solvent is to be injected in a cavity to dissolve trona and to form a brine which is recovered at least in part at the ground surface,

a method for minimizing brine contamination from overburden during in situ trona solution mining of a cavity formed in said trona stratum, this method comprises the following steps:

(A) applying a hydraulic pressure greater than the overburden pressure at said upper interface to lithologically displace (lift) said overlying overburden from saidunderlying trona stratum, thereby forming an interface gap at said upper interface, wherein said application of hydraulic pressure further induces formation of new undesirable transverse fractures and/or intersects pre-existing undesirable transverse fractures in saidtrona stratum;

(B) flowing a sealing agent into said upper interface gap and into the transverse fractures; and

(C) maintaining the sealing agent in said upper interface gap and in said undesirable transverse fractures to form a solidified matter inside said fractures and said upper interface gap.