Patent Application
20160356138
Not applicable.
The present invention relates to a sealing agent composition, methods for lithological displacement of an underground evaporite mineral deposit using such sealing agent to seal undesirable pre-exiting fractures and/or fractures created during application of hydraulic pressure, and methods for in situ solution mining of the lithologically-displaced evaporite mineral deposit. In particular, the present invention relates to a method for sealing undesirable pre-existing fractures and/or fractures created in a trona bed during application of hydraulic pressure at a trona/shale interface using such sealing agent in order to form a preferentially near-horizontal free face suitable for in situ solution mining of trona.
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. % NaHCO3 and 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.
15.3-15.6
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: Na2CO3.3NaHCO3.
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.
The Wyoming trona deposits are evaporites, and hence form various substantially horizontal layers (or beds). The 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 contain from about 88% 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 forseeable future needs.
In particular, 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) is located from approximately 1,200 feet (about 365 m) to approximately 1,600 feet (about 488 m) below ground surface. Presently, trona from the Wyoming deposits is economically recovered mainly from the main trona bed no. 17. 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.
The comparative tensile strengths, in pounds per square inch (psi) or kilopascals (kPa), of trona and shale in average values are substantially as follows:
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.
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.
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 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. Pike 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.
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.
Solution mining of trona could indeed reduce or eliminate the costs of underground mining including sinking costly mining shafts 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 ores containing sodium carbonate and sodium bicarbonate (trona, wegscheiderite) have 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.
Implementing a solution mining technique 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.
In 1945, Pike proposed the use of a single well comprising an outer casing and an inner casing. Hot solvent is injected through the inner casing to contact the trona bed, and the brine is withdrawn through the annulus. This method however proved unsuccessful and currently there are two approaches to trona solution mining that are being pursued.
One trona solution mining approach which is commercially used at the present time is part of an underground tailings disposal projects. Mine operators flood old workings, dissolving the pillars and recovering the dissolved sodium value. Solution mining of mine pillars was disclosed in U.S. Pat. No. 2,625,384 issued to Pike et al in 1953 entitled “Mining Operation”; it uses water as a solvent under ambient temperatures to extract trona from existing mined sections of the trona deposits. Solvay Chemicals, Inc. (SCI), known then as Tenneco Minerals was the first to begin depositing tails, from the refining process back into these mechanically mined voids left behind during normal partial extract operation. Applicants call this approach a ‘hybrid’ solution mining process as it takes advantage of the remnant voids and subsequent exposed surface areas of trona left behind from mechanical mining to both deposit insoluble materials and other contaminants (collectively called tailings or tails) and to recover sodium value from the aqueous solutions used to carry the tails.
Even though solution mining of remnant mechanically mined trona is one of the preferred mining methods in terms of both safety and productivity, there are several problems to be addressed, not the least of which is the resource itself. Hybrid solution mining processes are necessarily dependent upon the surface area and openings provided by mechanical mining to make them economically feasible and productive, but there is a finite amount of trona that has been previously mechanically mined. These ‘hybrid’ mining processes cannot exist in their present form without the necessity of prior mechanical mining in a partial extraction mode. When current trona target beds will be completely mechanically mined, the operators will eventually be forced to move into thinner beds of lower quality and to endure more rigorous mining conditions while the preferred beds are depleting and finally become exhausted.
This is where the second solution mining approach would allow the extraction of trona from less desirable beds (thin beds, poor quality beds, and/or deeper beds) which are currently less economically viable, without the negative impact of increased mining hazards and increased costs.
In this other trona solution mining approach, two or more vertical wells are drilled into the trona bed, and a low pressure connection is established by hydraulic fracturing or directional drilling.
Attempts to solution mine trona using vertical boreholes began soon after the 1940's discovery of trona in the Green River Basin in Wyoming. 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.
As explained previously, a bed of trona ore typically overlays a floor made of oil shale, which is a water-insoluble incongruent material whereby the interface between these two materials forms a natural plane of weakness. If a sufficient amount of hydraulic pressure is applied at this interface, the two dissimilar substances (trona and shale) should easily separate thereby exposing a large free-surface of trona upon which a suitable solvent can be introduced for in situ solution mining.
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 borehole 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 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 & 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 the evaporite stratum 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 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 at the bottom of the evaporite mineral stratum and along the top of the underlying insoluble non-evaporite stratum and to direct the fracture to the next adjacent well substantially horizontally along the interface between the bottom of the evaporite stratum to be removed and the top of the underlying stratum so that the soluble mineral will be dissolved from the bottom up.
This bottom-up approach for dissolving the mineral offers a number of advantages. The less concentrated and less saturated solvent flowing along the bottom of the evaporite stratum rises to a top layer of the solvent body and contacts the bottom of the evaporite stratum, dissolves the mineral therefrom and as the solvent becomes more saturated, settles to a lower layer of the solvent body so that the bottom of the evaporite stratum is always exposed to dissolution by less concentrated solvents. The insoluble materials in the evaporite formation 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 seam.
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.
The present invention thus proposes a remedial measure aimed as resolving the impact of undesirable transverse (vertical or slanted) fractures which are pre-existing (natural) and/or hydraulically-generated in the evaporite stratum under hydraulic pressure applied at or near the interface between the evaporite stratum (e.g., trona) and the underlying non-evaporite stratum (e.g., shale) during lithological displacement.
To allow for the development of a bottom-up solution mining approach of shallow-depth evaporite beds (e.g., trona beds) to dissolve the desired solute (e.g., sodium sesquicarbonate) in horizontal or near-horizontal plane, Applicants have developed a method for sealing these undesirable transverse fractures with a sealing agent.
In broad terms, in an underground formation containing an evaporite mineral stratum, wherein the mineral stratum lies immediately above a water-insoluble stratum of a different composition, and wherein said formation comprises a defined weak parting interface between the two strata and above which strata is defined an overburden up to the ground surface, one aspect of the present invention relates to a method for sealing undesirable fraction in the evaporite stratum during lithological displacement. The defined parting interface may be horizontal or near-horizontal, but not necessarily. This method comprises the following steps:
(a) applying a hydraulic pressure greater than the overburden pressure at the interface to lithologically displace (lift) the evaporite mineral stratum and the overlying overburden, thereby forming a gap (main fracture) between the strata and exposing a main mineral free-surface, wherein said application of hydraulic pressure further induces formation of new undesirable transverse fractures and/or intersects pre-existing undesirable transverse fractures in the evaporite mineral stratum, thereby exposing minor mineral free-surfaces in said undesirable fractures;
(b) flowing a sealing agent into the gap and into the transverse fractures; and
(c) maintaining the sealing agent in said gap and in said undesirable transverse fractures to form a solidified matter inside the fractures and optionally in the gap.
Another aspect of the present invention 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 evaporite stratum and to dissolve mineral from the main mineral free-surface created at the strata interface into an aqueous 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.
Such sodium-based product may be 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.
Yet another 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 following may apply to any or all embodiments of such method, process, or product according of the present invention.
The evaporite stratum is preferably at a shallow depth of 2,500 feet or less.
The lifting hydraulic pressure during the lifting 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 interface. 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 interface. 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 interface. 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 strata interface.
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 formation of the solidified matter in step (c) in underground conditions preferably further results in sealing the undesirable fractures, at least partially or preferably completely. Step (c) may be carried out to seal or plug at least 50%, preferably at least 75%, more preferably at least 90% by volume of the transverse fractures.
The solidified matter may be formed in step (c) when a change in the physical and/or chemical state of the sealing agent or of at least one of its components occurs.
The solidified matter may be formed in step (c) by at least one mechanism selected from the group consisting of crystallization, precipitation, compaction, agglomeration, coagulation, cross-linking, wall-building, cementing, and combinations of two or more thereof.
The solidified matter may be formed in step (c) by at least crystallization or precipitation of the at least one sealing agent component.
In additional or alternate embodiments, the solidified matter may be formed during step (c) by at least binding or bonding of at least one component of the sealing agent with the mineral in the free mineral surfaces created during step (a) to form a wall-building solidified matter in the gap and fractures
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 evaporite mineral stratum preferably comprises a water-soluble mineral selected from the group consisting of trona, nahcolite, wegscheiderite, shortite, northupite, pirssonite, dawsonite, sylvite, carnalite, halite, and combinations thereof; more preferably comprises trona, nahcolite, wegscheiderite; most preferably comprises trona. In such instance, the underlying water-insoluble stratum of a different composition may include oil shale or any substantially water-insoluble sedimentary rock that has a weak bond interface with the target evaporite stratum.
The sealing agent is injected from the ground surface to the interface.
The sealing agent at the ground surface may comprise an aqueous phase which may or may not be at least 95% saturated, or at least 98% saturated, or at least 99% saturated, or saturated in at least one component of said mineral.
The sealing agent may comprise a solution/slurry/gel supersaturated in situ in at least one component of said mineral.
The sealing agent under surface conditions may be a slurry or a gel comprising an aqueous phase in which particles are suspended, wherein said aqueous phase is saturated in at least one component of said mineral, or said particles comprises at least one component of said mineral, or both.
The sealing agent may comprise a slurry with one or more water-insoluble materials of a suitable size suspended in water or an unsaturated aqueous solution.
The sealing agent may comprise an aqueous solution which is saturated in a sodium component selected from the group consisting of sodium sesquicarbonate, sodium carbonate, sodium bicarbonate, and any combinations thereof.
The sealing agent may comprise water-soluble particles. The water-soluble particles may comprise sodium carbonate, hydrates thereof, sodium sesquicarbonate, sodium bicarbonate, or combinations thereof.
The sealing agent may comprise water-insoluble particles. The water-insoluble particles may comprise water-insoluble calcium compounds (e.g., lime, limestone), fused or colloidal silica, sand, cement, water-insoluble solid matter recovered from a mechanically-mined mineral after its dissolution in water or aqueous medium, tailings recovered from a mineral surface refinery (such as tailings recovered from a soda ash surface refinery which uses mechanically-mined trona), 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 (insolubles) are separated from the sodium carbonate-containing liquor 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 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, 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 coaser particles of tailings (retained on the sieve) may be used as water-insoluble particles in the sealing agent. 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 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 succession in the sealing agent. For example, the particle size of tailings may increase in the sealing agent over time during the sealing agent injection, either in a continuous fashion or in a step-wise fashion. For example, the sealing agent comprising particles of a first average particle size is injected at the interface for a given period of time, and subsequently the sealing agent comprising particles of a second average particle size which is less than the first average particle size is injected at the interface. In this manner, 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 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. The sealing agent may comprise water-soluble particles and water-insoluble particles.
When the evaporite stratum comprises trona; and the underlying non-evaporite stratum comprises oil shale, in such instance, the sealing agent 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 sealing agent may comprise particles comprising at least one component of the oil shale.
The sealing agent may comprise a slurry or gel comprising particles in suspension in an aqueous solution which is saturated in a sodium component selected from the group consisting of sodium carbonate, sodium bicarbonate, and any combinations thereof. The particles in the slurry or gel may comprise water-soluble particles, water-insoluble particles, or combinations thereof, and at least a portion of the solidified matter obtained in step (c) may comprise these particles.
The water-soluble particles may contain the same sodium component as in the liquid phase in which they are suspended or a different sodium than the liquid phase in which they are suspended. Water-soluble particles in a slurry or gel used as sealing agent preferably comprise sodium carbonate, any of its hydrate forms, sodium sesquicarbonate, or sodium bicarbonate. Water-insoluble particles in a slurry or gel used as sealing agent may comprise colloidal or fused silica, sand, cement, insoluble fraction recovered from a mechanically-mined mineral stratum, biological and/or agricultural solid matter (such as hulls, shells), tailings of a mineral surface refinery, insoluble calcium inorganic salts (e.g., calcium hydroxide, calcium oxide), or any combinations thereof.
In preferred embodiments, the sealing agent may comprise trona particles (which may be calcined or uncalcined), particles of a water-insoluble calcium compound (such as calcium hydroxide), 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.
In some embodiments, the sealing agent may comprise a thixotropic gel containing particles in colloidal suspension in an aqueous solution. A component selected from the group consisting of sodium sesquicarbonate, sodium carbonate, sodium bicarbonate, sodium bentonite, calcium bentonite, and any combinations thereof may be included in the thixotropic gel particles, in the aqueous solution in which these particles are suspended, or both. A bentonite suspension for example would provide a good thixotropic sealing agent.
During step (c), the solidified matter may seal or plug at least 50%, preferably at least 75% of the transverse fractures, more preferably at least 90% of the transverse fractures.
During step (c), sealing or plugging the fractures may be effected at least in part by a wall-building mechanism in which the solidified matter may bind to or bond with the native mineral from the free faces in the gap and transverse fractures.
Sealing or plugging the fractures in step (c) may be effected by crystallization or precipitation or compaction of a sodium component to form at least a portion of the solidified matter. For example, sealing the fractures in step (c) may be effected at least in part by crystallization and/or precipitation of sodium carbonate in a hydrate form and/or of sodium bicarbonate and by compaction of particles of sodium sesquicarbonate and/or sodium carbonate.
Sealing or plugging the fractures in step (c) may be effected at least in part by compaction of the slurry/gel particles. In some embodiments, the sealing agent comprises water-insoluble particles of an appropriate size range suspended in an unsaturated or saturated aqueous solution. These particles would be carried with the aqueous solution and would fill and seal or plug the undesirable transverse fractures through the action of compaction of the particles, thereby closing the undesirable fractures to prevent further fluid to flow inside the fractures (thereby reducing the permeability in the fractures). The sealing agent may contain two or more populations of particles of different average sizes, preferably smaller than the width of the pre-existing and/or new transverse fractures to be sealed. It is desirable to have wide distribution of particles sizes in order to allow good compaction with a minimum of void space remaining in the fractures so as to effectively plug the fractures. 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.
In some embodiments, the sealing agent may be injected from the ground surface to the 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 solidified matter from said sealing agent in step (c) may be effected by a drop in the sealing agent's temperature as it naturally cools while being maintained in the fractures of the mineral stratum.
Alternatively, the sealing agent may be injected from the ground surface to the 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 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 sealing agent may be between about 25 and about 41° C. (about 77-106° F.).
The surface temperature of the sealing agent may be at least 20° C. higher than the in situ temperature of the mineral stratum.
The sealing agent may be preheated to a predetermined temperature higher than the in situ temperature of the mineral stratum.
The steps (a) and (b) may be performed at the same time by injecting the sealing agent into the target strata interface at the hydraulic pressure for its flowing to create said interface gap (main fracture) and intersect pre-existing transverse fractures and/or create new transverse fractures.
Alternatively, the steps (a) and (b) are performed sequentially, step (a) being carried out by injecting water or other suitable injection fluid as a lithological displacement fluid (also called ‘lifting fluid’) to apply the hydraulic pressure at the strata interface to form the interface gap (main fracture) and intersect and/or enlarge pre-existing transverse fractures and/or create new undesirable transverse fractures; and then, after evacuating the lithological displacement fluid used in step (a), step (b) is carried out by flowing the sealing agent in the gap and into the pre-existing and/or new undesirable transverse fractures.
The method may further comprise:
(d) releasing the hydraulic pressure for the overburden to compress the layer of solidified matter formed in the gap and/or to squeeze out any unsolidified sealing agent remaining in the gap; and/or
(e) injecting a flushing agent to remove at least a portion of a layer of solidified matter from the gap and/or to carry away any unsolidified sealing agent remaining in the gap; and/or
(f) after step (c) or an optional flushing step (e), injecting a propping fluid to maintain free fluid paths inside the gap.
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.
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:
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.
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 term “fracture” when used herein as a verb refers to the propagation of any pre-existing (natural) fracture or fractures 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.
As used herein, the term “sealing agent” is a substance which is used to plug or block off certain permeable zones (fractures) 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 (generally 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 ‘solvent-exposed’ or fluid-exposed′ in front of ‘trona’, ‘ore’, ‘mineral’, “surface” refers to any trona, ore, mineral, surface, which is in contact with a solvent or fluid.
The term ‘mined-out’ in front of ‘trona’, ‘ore’, or ‘cavity’ as used herein refers to any trona, ore, or cavity which has been previously mined.
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 Na2CO3 and 4 weight percent NaHCO3 would have a TA of 19.5 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 “supersaturated solution” as used herein refers to a composition which contains a solute in a liquid phase at a concentration greater than the solubility limit of such solute under the temperature and pressure of the composition; the “supersaturated solution” contains the solute in solid form and the liquid phase is saturated in dissolved solute.
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.
A ‘surface’ parameter is a parameter characterizing a fluid, solvent and/or liquor 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 liquor 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.
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.
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.
A first aspect of the present invention relates to a method of lithological displacement in a dense impervious underground formation, such as an evaporite mineral bed. This formation preferably contains a lithological mineral stratum which is soluble in a removal liquid, lying immediately above a lithological stratum of a different composition which is substantially insoluble in such removal liquid. The underground formation has a defined parting surface interface between the two strata.
This strata interface is preferably horizontal or near-horizontal with a dip of 5 degrees or less, but not necessarily. The evaporite stratum may be a horizontal bed (dip of 0 degree) or may be a gently dipping evaporite bed (dip>0 up to 5 degrees). A dipping evaporite bed with a dip greater than 5 degrees may also provide a strata interface with an underlying stratum which is suitable to apply the hydraulic pressure for lithological displacement.
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.
A hydraulic pressure which is slightly higher than the overburden pressure is preferably applied underground at the interface between the two strata thereby lifting the overlying evaporite stratum and at the same time the overburden (vertical displacement), creating a gap (main fracture) at the interface, and exposing a large free-surface of evaporite mineral upon which a suitable solvent can be introduced. This hydraulic pressure application is significantly different than the commercially-available hydraulic fracturing using very high pressures in deep 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.
Applicants thus refer to the present technique as “lithological displacement” in order to distinguish it, as a less invasive process, from the high pressure hydraulic fracturing used in the oil and gas field. Such “lithological displacement” method comprises applying a relatively low hydraulic pressure to make a separation between a horizontal or near-horizontal soluble evaporite stratum (e.g., trona) and an underlying or overlying dissimilar non-evaporite stratum (e.g., oil shale) in order to create a large free mineral surface with which a suitable solvent (water or aqueous solution) can contact for in situ solution mining.
The present “lithological displacement” technique can include drilling a fully cased and cemented well from the surface to at least the depth of a target injection zone which is at the interface between the target block of evaporite stratum (e.g., trona bed) and the underlying stratum (e.g., oil shale). The application of the low hydraulic pressure preferably comprises injecting a fluid at a hydraulic pressure greater than the overburden pressure at the interface in order to hydraulically lift the overburden at the injection depth, thus creating a “lithological displacement” of the overlying mineral stratum so that a gap (main fracture) is formed at the interface between the two strata.
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 20, a minimum target hydraulic pressure of 2,000 psi may be applied at interface 20 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 20 between the trona and the oil shale.
The lifting hydraulic pressure 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 interface. The hydraulic pressure during the lifting step may be at most 50% greater, or at most 40% greater, or at most 30% greater, or at most 20%, than the overburden pressure at the depth of the interface. The lifting hydraulic pressure may be from 0.01% to 50% greater, or from 0.1% to 50% greater, or even from 1% to 50% greater than the overburden pressure at the depth of the interface. The lifting hydraulic pressure should be sufficient to overcome the sum of the overburden pressure and the tensile strength of the interface.
The casing of the fully cased and cemented injection well should be perforated or otherwise open at the interface to expose the target in situ injection zone. If perforated, the perforations of the well casing may also be carried out solely on the lateral sides of the casing, so as to create perforations along one or more horizontal planes. This lateral perforating step may be carried out to allow passage of fluid in a preferential lateral way through the formed perforations.
The gap formed at the strata interface in this lithological displacement method would extend laterally in all directions away from the in situ injection zone 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 at the downhole end of the injection well. 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 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 during lithological displacement.
When the gap is formed exposing a large mineral free-surface, a solvent injected into the gap comes in contact with mineral ore and dissolves mineral ore from the exposed free-surface to form a brine which can be pumped or pushed to the surface for processing thereby enabling in situ solution mining.
For this “lithological displacement” method to be carried out on trona ore, the depth of the trona/shale interface 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 at this interface (hence sometimes called interface gap) between the trona stratum and the underlying oil shale stratum, although minor transverse fractures may be exposed (naturally existing) and/or may be newly created.
As this lithological displacement method progresses, 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 and which would preferentially seal at least a portion of these undesirable transverse fractures, whether being pre-existing and/or being hydraulically-generated.
The injected sealing agent may preferentially seal at least a portion of these undesirable transverse fractures by at least one of the following mechanisms:
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.
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 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′ method, 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 invention is to prevent liquid flow in the evaporite upper stratum's transverse fractures so as to prevent premature dissolution of mineral from the fractures faces, the lithological displacement 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)
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.
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 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.
The embodiment thereabove describes the simultaneuous use of two or more particles populations or fractions of different average particle sizes during the sealing agent injection.
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 increased 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 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, a liquid settable material may be utilized as the sealing agent.
In yet another embodiment, a liquid settable material may be utilized as carrying liquid along with a solid material.
In some embodiments, the method may further comprise: generating a gas during step (c). In such instances, the method may comprise: introducing a sealing agent to the interface; allowing the sealing agent to flow into the hydraulically-generated main fracture and pre-exiting and/or new transverse fractures; maintaining this sealing agent in these fractures for a time sufficient to generate a gas in the sealing agent in situ within the fractures, wherein the sealing agent expands to fill a cross-section of the fractures, thus blocking the flow of fluid through the fractures. The volume of the sealing agent may increase by from about 0.1% to about 80% by total volume of the sealing agent composition at a pressure of from about 2,000 psi to about 5,000 psi. The gas generating chemical system in the sealing agent may comprise one reactant which is a carbon dioxide generating material. Suitable carbon dioxide generating materials include ammonium, alkali metal, alkaline earth metal and transition metal salts of carbonate and bicarbonate or combinations thereof. The gas generating chemical system in the sealing agent may comprise a second reactant which is an activator. The second reactant may comprise one or more acids or acid generating materials. In general, any material capable of lowering the pH of an aqueous solution below 6 may be a suitable activator, including organic or inorganic material.
In one embodiment, at least one component of the sealing agent 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 sealing agent, and/or leave behind compacted or coagulated solid particles to form the solidified matter in the undesirable fractures that will inhibit the future passage of solvent fluid. This step preferably comprises injecting the sealing agent in these transverse fractures and gap, and maintaining such sealing agent in the gap and transverse fractures until a change in the physical and/or chemical state of said sealing agent 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 agent and/or to the mineral surfaces exposed to the sealing agent.
The change in the physical and/or chemical state may be depositing a compacted or coagulated material in the undesirable fractures 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 sealing agent. Swelling occurring in the undesirable fractures will significantly reduce the permeability inside the fractures 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 sealing agent component with sealing agent's particles, coagulation of particles (gel formation), water-swelling due to water adsorption and/or reaction with water of at least one sealing agent component, and/or wall building of at least one sealing agent component with mineral surfaces, to form in situ a solidified matter which covers the mineral free-surfaces which come in contact with the sealing agent and to seal the undesirable gap thereby preventing access to future solvent flow. As the sealing agent is maintained in the remaining open spaces in the undesirable fractures and gap, more change in the physical and/or chemical state may occur with more bonding or binding.
In some embodiments, the sealing agent may include or may consist of a slurry of particles in a water-based carrier liquid. These particles may be:
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.
In some embodiments, the step (c) is carried out to entirely cover the walls of the undesirable fractures with solidified matter (for example a layer of solidified matter is deposited onto, or binds to, the mineral free surface of the fractures' walls) thereby sealing the fractures' walls. Once the fracture walls are sealed, any production solvent which enters the sealed-wall fractures is prevented from contacting the mineral surface on the walls since it is covered by the solidified matter. In such embodiment, it is preferred that the solidified matter is insoluble or poorly soluble in the production solvent, or at the very least, the solidified matter should be less soluble in the production solvent than the mineral.
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. As a result, step (c) would significantly reduce the permeability of the material in the fractures. The goal would be for the permeability to be reduced to approach the permeability of the surrounding matrix (mineral). Once plugged, these transverse fractures would no longer be available to allow a production solvent, injected at the target interface, to deviate course through these undesirable fractures. Instead, the production solvent would be confined to flow through the near-horizontal target interface created in the gap between the new layer of solidified matter and the underlying 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 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” using such sealing agent. These conditions are as follows:
For sealing 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:
When the sealing agent is a solution, the solution would be injected so as to fill the undesirable fractures; and under the influence of in situ ore conditions, the solution goes through a change in temperature (decrease) and/or a change in pH, a solid substance may crystallize or precipitate out of the injected sealing agent to form a solidified matter (a plug) in the undesirable fractures.
When the sealing agent is a slurry or gel, the slurry or gel would be injected whereby due to particle size, component(s)' reactivity, flow rate, etc, the particles in the slurry may fill undesirable fractures by compaction and/or agglomeration; and/or a solid substance may crystallize or precipitate out of the liquid phase; and/or the particles in the slurry may form a cross-linked or cemented matter with one or more of the sealing agent's solutes, may swell by adsorption/reaction with the liquid carrier (such as water); and/or may form a wall-building matter with native mineral from the mineral free-surfaces, all of these mechanisms effecting the formation of a solidified matter (a plug) in these undesirable fractures during step (c).
The solidified matter plugging these undesirable fractures should be nearly impenetrable to fluid flow after sealing. 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 unwanted fractures in a block of trona, the properties of the most suitable materials for a ‘trona glue’ should be as follows:
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, trona, sodium carbonate, silica, bentonite, montmorillonite, or combinations thereof; more preferably the particles comprises 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.
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 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 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→2Na+-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 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.
In yet additional or alternate embodiments, the method may further comprise (d) 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 evaporite stratum inside the 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 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.
In order to maintain and/or enhance the flow-ability of the main hydraulically-created fracture in the mineral 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 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 mineral 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 mineral by the solvent will enlarge the fracture over time. As such, the proppant may be needed only at the beginning of exploitation, 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.
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:
lifting the overburden while injecting the sealing agent (steps a and b performed simultaneously) using a hydraulic pressure greater than the overburden pressure;
sealing transverse fractures and gap (main fracture) by solidified matter (step c);
optionally releasing hydraulic pressure to squeeze solidified matter out of gap or flushing solidified matter out of gap out by flushing agent (step d);
optionally, injecting a propping agent (step e); and
initiate dissolution of mineral from free face at hydrostatic pressure by injecting a solvent and removing a brine containing dissolved mineral to the surface.
The invention will now be described with reference to the following drawings:
Although
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.
The trona stratum 5 may contain up to 1 wt % sodium chloride, preferably up to 0.8 wt % NaCl, yet more preferably up to 0.2 wt % NaCl.
The defined parting interface 20 between the strata 5 and 10 is preferably horizontal or near-horizontal, but not necessarily. The interface 20 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 may have a dip greater than 5 degrees up to 45 degrees or more.
The trona/shale interface 20 may 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 interface 20 may at a depth of more than 800 ft (244 m).
In the Green River Basin, the trona/oil shale parting interface 20 may be at a shallow depth of from 800 to 2,500 feet (244-762 m).
In the Green River Basin, the trona stratum 5 may have a thickness of from 5 feet to 30 feet (1.5-9.1 m), or may be thinner with a thickness from 5 to 15 feet (1.5-4.6 m).
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, and which Applicants call ‘transverse fractures’. When the interface 20 is preferably horizontal or near-horizontal (with a dip of 5 degrees or less) as illustrated in
Referring back to
The well 30 is preferably fully cemented and cased, except that it comprises an in situ injection zone 40 which is in fluid communication with the strata interface 20. The in situ injection zone 40 should allow for a fluid to be injected into the well 30 and to be directed at the interface 20. The in situ injection zone 40 is preferably, albeit not necessarily, designed to laterally inject the fluid 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 trona/shale interface 20 by vertically displacing the stratum 5 to create the gap 42.
The in situ injection zone 40 may comprise one or more downhole casing openings. A downhole vertical section of the vertical well 30 may have a downhole end opening which is located at or near the parting interface 20. The vertical borehole section may have, alternatively or additionally, perforations which are at or near the interface 20. In some embodiments, these perforations are aligned with the interface (such as in a row). For example, using a downhole perforating tool, perforations may be cut through the casing and cement at a well circumference aligned with the interface 20 to form the in situ injection zone 40. However alignment of perforations with the interface 20 is not required to provide an adequate lifting of the stratum 5 at the interface 20.
In some embodiments, the in situ injection zone 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 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. Such conduit may be inserted inside the injection well 30 to facilitate injection of fluid. 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 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.
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 45a, 45b are illustrated in
For the first phase of lithological displacement, the production wells 45a, 45b are capped. The injection well 30 is also capped but will allow a fluid 50 to be injected therethrough.
The fluid 50 can flow through 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 in situ injection zone 40 which perforates the casing allows the fluid 50 to force a path at the trona/shale interface 20.
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 trona/shale interface 20 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 along the parting interface 20.
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.
Referring back to
The formation of gap 42 in this lithological displacement may extend laterally in all directions away from the injection zone 40 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. Because it is expected that the stresses are not equal in all directions, the lateral expansion will not be even in the horizontal plane. The height of the displacement (gap) however would be much less than 1 cm, generally about 0.5-1 cm near the injection zone up to 0.25 cm at the extreme edge of the lateral expanse. The height of the gap is highly dependent upon the flow rate of the fluid 50 during lithological displacement.
Although not illustrated in
Ideally, regardless of what type of well is used for fluid injection, the expanse of the gap 42 intercepts during lithological displacement the cased and cemented but perforated downhole ends of at least one of the production wells 45a, 45b. In this manner, a fluid communication is established between the injection well 30 and at least one production well 45a, 45b. In
For injection fluid 50, water may be used initially to create a main fracture (gap 42 illustrated in
In preferred embodiments, the sealing agent is used as the injection fluid 50 to apply the hydraulic pressure at the interface 20 to create the main fracture (interface gap 42) and create and/or enlarge transverse fractures (25) and at the same time its application in the interface gap 42 and fractures 25 permits sealing them at least partially. In this case, steps (a) and (b) of the present method are carried out simultaneously.
The fluid 50 (which may comprise or may be the 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 solidified matter may be formed when at least one component of the sealing agent undergoes a transformation under in situ conditions (different in situ pH or temperature than at the surface) and/or over time). This transformation may be a change in physical and/or chemical state which favors the creation of solidified matter. The creation of solidified matter may include crystallization or precipitation, solid compaction, coagulation, crosslinking, and/or cementation. Wall-building may also occur to form a solid crystal lattice with native trona present particularly on minor fracture mineral free faces but also in the main mineral free face of the gap 42. This change may be effected by a difference between the surface conditions and in situ conditions of the sealing agent. And/or this change may be effected by chemical reaction(s) over time with one sealing agent component, between two or more sealing agent components, and/or between at least one sealing agent component and native mineral on fracture faces. For example, when the initial (ground surface) temperature of the sealing agent is higher (preferably at least 20° C. higher) than the in situ trona bed temperature, the temperature of the sealing agent will decrease after being injected underground by natural cooling via heat transfer with the surrounding stratum. Such cooling is preferably used to favor crystallization/precipitation of at least one component of the liquid phase of the sealing agent. The surface temperature of the sealing agent may be selected to be between 15° C. (159° F.) and 90° C. (194° F.), preferably between 50° C. (122° F.) and 80° C. (176° F.), more preferably between 60° C. (140F) and 70° C. (158° F.), most preferably 65° C. (149° F.). The in situ trona bed temperature is estimated to be about 30-36° C. (86-96.8° F.), preferably 31-35° C. (87.8-95° F.).
In some embodiments, the injected sealing agent comprises an aqueous solution saturated in sodium carbonate. A decrease in temperature will cause the sodium carbonate present in the aqueous solution to precipitate in the form of a crystalline hydrate. If the sealing agent is a slurry or gel comprising particles in the aqueous solution saturated in sodium carbonate, the crystals formed under the in situ conditions may be capable of forming a crystal lattice between the slurry/gel particles and may be capable of forming a crystal lattice with the native trona which comes in contact with the injected agent.
As shown in
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 gap 42 at the bottom of the trona stratum 5, the solidified matter in the gap may be squeezed out of the gap.
A new interface 23 may be formed between the solidified matter in the (filled or partially-filled) gap 42 and the underlying shale stratum 10. To initiate solution mining, a fluid 60 will then be injected at the depth of the trona face 22 and/or at the new interface 23 to lift the overlying stratum. The fluid 60 may be effective in flushing at least a portion of the solidified matter present in the gap 42 (acting as a flushing agent) as shown in
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 50 when the trona stratum initially was lithologically displaced), 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 sealing step. Care should be taken here not to create new vertical fractures.
The fluid 60 may be initially a flushing agent (such as fluid 60b in
At first, the fluid 60 may dislodge and/or dissolve the layer of new solidified matter left in between the trona stratum 5 and the shale stratum 10 in the gap 42 which was created during hydraulic displacement (fluid 60 acting as flushing fluid 60b in
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).
The fluid 60 used for evaporite mineral 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 face 22, 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 liquor 65 which is removed to the surface has a surface temperature generally lower than the surface temperature of the fluid 60 at the time of injection. The surface temperature in the extracted liquor 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 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 liquor loses some heat as it flows through the mined cavity until the liquor 65 gets extracted via wells 45a, 45b.
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 well 30 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 liquor 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 injecting a compressed gas into the mining cavity 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 liquor 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, liquor aliquots may be analyzed for TA content and chloride content. Rising chloride contents in successive liquor 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 liquor 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 22 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 8% TA) or gets saturated with desired solute, at which point the resulting liquor 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, liquor 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.
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, liquor contamination from roof material may not be a major issue. Should this be the case, Applicants believe that the system can be operated much more aggressively in terms of solvent flow rates.
For any or all embodiments of the present invention, some underground gas may be released from the underlying 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 30 used for solvent injection. Alternatively, the purge of released gas may be effected by one or more secondary purge wells (not shown in figures). It is also conceived that much of the gas may dissolve in the solvent and in which case dissolved gas may leave the liquid freely under low pressure conditions at the surface.
A liquor collection zone may be created at the downhole ends of wells 45a, 45b to facilitate the recovery of the liquor 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 liquor can be pumped to the surface for recovery of the alkali values. Suitable pumping system can be installed at the downhole end of wells 45a, 45b 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 liquor return pipe may be placed into the downhole collection zone in fluid communication with a terranean pumping system to allow the liquor 65 to be pumped or pushed to the surface.
A conduit may be inserted inside the injection well 30 to facilitate injection. 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 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 a terranean solvent feeding system and with the in situ solvent injection zone 40.
The in situ solvent injection zone 40 is preferably, albeit not necessarily, designed to inject the solvent 60 (preferably laterally) in order to avoid injection of solvent in a vertical direction. Low to moderate working pressures may be utilized to limit the solvent ability to contact the roof of the ore bed, that is to say, the working pressure may be lower than the head of pressure residing at the location of the conduit injection zone. Low to moderate working pressures would also serve to prevent solvent backflow towards the surface inside the well 30.
The liquor 65 extracted at the surface may be saturated in sodium carbonate, but in most instances the liquor 65 is unsaturated in sodium carbonate. A portion 66 of such liquor 65 may be processed for recovery of the sodium values, while another portion 67 may be re-injected though well 30.
Such solution mining step may be carried out in a continuous mode in which the solvent 60 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 8% 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 shale floor and contaminants potentially falling from the upper areas of the trona stratum, keeping liquid from contamination by the overlying shale layer. The solvent thus may include tailings which then deposit on the bottom face 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 another 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 evaporite stratum and to dissolve mineral 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:
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 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.
A solution saturated in sodium bicarbonate was made by dissolving 425 g NaHCO3 in 2.5 liters of water. The solution was heated to 65° C. and decanted to remove excess sodium bicarbonate crystals. This saturated solution was used as a sealing agent in a sealing test performed on a solid 1.7-kg trona block from bed No. 17 in Green River, Wyo. One hole of ¼-inch in diameter and 1.5-inch in depth and a second hole of ⅛-inch in diameter and 1.125-inch in depth were drilled into the trona block. The block was submerged into the saturated solution at 65° C. The solution was allowed to cool at room temperature (19° C.) to precipitate sodium bicarbonate. Aliquots of the solution were taken out for a double endpoint titration measuring sodium carbonate and bicarbonate in the remaining solution were performed over time. At the same time, temperature of the remaining solution was measured. When the solution temperature dropped to about 36° C., crystals started to form and covered the trona block. It took about 3 hours for the temperature of the submerging solution to drop from 65° C. to 35° C. when left at room temperate of about 19° C.
The content in sodium carbonate and bicarbonate in weight percent (wt %), the ratio of NaHCO3 to Na2CO3, and the temperature of the remaining solution over time are shown in TABLE 2 below.
The composition for the crystals falling out of the solution taken after 5 days is shown in TABLE 3. The solid structures had fan corral-like shapes with long-needle type crystals.
At the end of the test, the trona block was cut by ½ inch to expose the holes at about half length. The holes were partially sealed by crystals formed during cooling of the saturated solution. The crystals deposited in the bottom half of the ⅛-inch hole, whereas crystals deposited near the walls of the ¼-inch hole leaving a cylindrical-shaped void of about ⅛-inch diameter at the center.
Six sealing tests were performed on another solid trona block from bed No. 17 in Green River, Wyo. Six holes of ⅛-inch in diameter and 2-inch in depth were drilled into the trona block.
A solution saturated in sodium carbonate and a supersaturated sodium carbonate slurry were made. Solid sodium carbonate was added to water heated at 65° C. in an amount exceeding the solubility limit of sodium carbonate at 65° C. The mixture was allowed to settle; the supernate provided the saturated solution of sodium carbonate while the settled solids with some of saturated solution provided the slurry of sodium carbonate. Similar saturated solutions and slurries were made for sodium sesquicarbonate and sodium bicarbonate.
An aliquot for each saturated solution/slurry was added to one of the six holes. The solutions/slurries were left to cool for 24 hours, and the openings of the holes were observed for presence of crystals formation.
All three holes which received slurries were dry and filled with crystalline deposit. The crystalline deposits from slurries of sodium sesquicarbonate and carbonate seemed harder while the crystalline deposit from the slurry of sodium bicarbonate appeared crumbly.
Two of three holes which received saturated solutions of sodium bicarbonate and sesquicarbonate still contained water and presence of some crystallization was visible but not extensive. The remaining hole which received a saturated solution of sodium carbonate die not have water but contained crystals on the walls of the hole.
After one week, the trona block was cut to expose the holes at about half length. The hole filled with solution of sodium sesquicarbonate (Ex. 2) was still wet and had small deposit of solid. The hole with slurry of sodium sesquicarbonate (Ex. 3) got sealed with solid very quickly and the deposit was the hardest of the three, although the bottom of this hole was still damp. The other four holes (Ex. 4-7) were sealed with solid.
A sample of each solid was taken out from each hole and titrated for analysis using an acid double end point titration; the results are shown in TABLE 4.
Several small (¼-inch diameter) holes were drilled in a block of trona, and trona insolubles (tailings) were injected into the holes. The insolubles used in this example were taken from a thickener underflow in a soda ash refinery, and had around 12% by Total Alkalinity as Na2CO3; about ⅓ of the volume are insoluble fines. This material set up much slower than previously tested materials and did not bond to the trona walls. The resulting plug was brittle.
The same trona insolubles as used in Example 8 were added to a slurry of trona particles (T200® Solvay Chemicals) at a weight ratio for about 50:50. This slurry was injected into a trona (¼-inch diameter) hole. Re-crystallization occurred and bonding with the trona was apparent at the surface of hole where the slurry was air dried. Inside the hole, the slurry remained wet as the hole sealed out the moisture loss to the air. When the sample was able to dry, the solidified matter bonded to the trona. After about a week, the bonding to trona and the solidified matter in the hole were quite hard.
Three slurries into water using calcium hydroxide at 10, 25 and 50 wt % were injected into trona holes. These slurries did not set inside the holes and did not recrystallize nor bonded to the trona walls.
Three slurries into water at 10, 25 and 50 wt % using 50:50 weight ratio of calcium hydroxide and trona particles (T200® Solvay Chemicals) were injected into a trona (¼ inch) hole. These slurries did not set inside the hole and did not recrystallize nor bonded to the trona walls. Slurries set up hard inside the hole and recrystallized. Bonding with trona walls was apparent. On one instance the slurry expanded in volume over time.
One slurry into water using 1/3:1/3:1/3 weight ratio of calcium hydroxide/trona particles T200®/lime were injected into a trona (¼ inch diameter) hole. The slurry solidified inside the hole and bonded to the trona walls.
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:
The present application claims priority benefit to U.S. provisional application No. 61/718,212 filed on Oct. 25, 2012, this application being herein incorporated by reference in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| 61718212 | Oct 2012 | US |
