WO2014189586A1 - Wellbore fluids comprising mineral particles and methods relating thereto - Google Patents

Wellbore fluids comprising mineral particles and methods relating thereto Download PDF

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Publication number
WO2014189586A1
WO2014189586A1 PCT/US2014/019867 US2014019867W WO2014189586A1 WO 2014189586 A1 WO2014189586 A1 WO 2014189586A1 US 2014019867 W US2014019867 W US 2014019867W WO 2014189586 A1 WO2014189586 A1 WO 2014189586A1
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WIPO (PCT)
Prior art keywords
wellbore
mineral particles
fluid
oxide
mineral
Prior art date
Application number
PCT/US2014/019867
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English (en)
French (fr)
Inventor
Dale E. Jamison
Charles Landis
Jay Deville
Cato Mcdaniel
Original Assignee
Halliburton Energy Services, Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
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Publication date
Priority claimed from US13/898,849 external-priority patent/US20140209390A1/en
Application filed by Halliburton Energy Services, Inc. filed Critical Halliburton Energy Services, Inc.
Priority to AU2014269067A priority Critical patent/AU2014269067B2/en
Priority to CA2907065A priority patent/CA2907065A1/en
Priority to GB1516453.6A priority patent/GB2536516A/en
Publication of WO2014189586A1 publication Critical patent/WO2014189586A1/en
Priority to NO20151371A priority patent/NO20151371A1/no

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Classifications

    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/02—Well-drilling compositions
    • C09K8/03—Specific additives for general use in well-drilling compositions
    • C09K8/032—Inorganic additives
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/06—Arrangements for treating drilling fluids outside the borehole
    • C—CHEMISTRY; METALLURGY
    • C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
    • C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
    • C04B20/00—Use of materials as fillers for mortars, concrete or artificial stone according to more than one of groups C04B14/00 - C04B18/00 and characterised by shape or grain distribution; Treatment of materials according to more than one of the groups C04B14/00 - C04B18/00 specially adapted to enhance their filling properties in mortars, concrete or artificial stone; Expanding or defibrillating materials
    • C04B20/10—Coating or impregnating
    • C—CHEMISTRY; METALLURGY
    • C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
    • C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
    • C04B28/00—Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements
    • C04B28/02—Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements containing hydraulic cements other than calcium sulfates
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/02—Well-drilling compositions
    • C09K8/03—Specific additives for general use in well-drilling compositions
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
    • C09K8/46—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement
    • C09K8/467—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement containing additives for specific purposes
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/01—Arrangements for handling drilling fluids or cuttings outside the borehole, e.g. mud boxes

Definitions

  • the present invention relates to mineral particles that provide for wellbore fluids with tailorable properties and capabilities, and methods relating thereto.
  • a variety of wellbore operations are performed, e.g., drilling operations, cementing operations, and stimulation operations.
  • One physical property of the wellbore fluids used in conjunction with these wellbore operations is density.
  • density For example during drilling operations, the density of a wellbore fluid must be carefully controlled so as to exert sufficient pressure to stabilize the walls of the wellbore, e.g. , to prevent blowouts, while simultaneously not exerting excess pressure that can cause damage to the surrounding subterranean formation.
  • the density of spacer fluids and cementing operations must be carefully balanced so as to minimize or prevent mixing of other wellbore fluids on either side of the spacer fluid (e.g., a drilling fluid and a cementing fluid).
  • weighting agents used in the exploration recovery of hydrocarbons.
  • barite particles
  • the complexity of wellbore fluids often increases.
  • Wellbore fluid complexity can lead to negative synergistic effects between wellbore additives, including barite.
  • the present invention relates to mineral particles that provide for wellbore fluids with tailorable properties and capabilities, and methods relating thereto.
  • One embodiment of the present invention provides for a wellbore drilling assembly that includes a pump in fluid communication with a wellbore via a feed pipe; and a wellbore fluid disposed in at least one selected from the group consisting of the pump, the feed pipe, the wellbore, and any combination thereof, wherein the wellbore fluid comprises a base fluid, a plurality of first mineral particles, and a plurality of second mineral particles such that the first mineral particles and the second mineral particles have a multiparticle specific gravity of about 3 to about 20.
  • a wellbore drilling assembly that includes a pump capable of introducing a fluid into a wellbore via a feed pipe; a fluid processing unit capable of receiving the fluid from a wellbore via an interconnecting flow line; and a wellbore fluid disposed in at least one selected from the group consisting of the pump, the feed pipe, the wellbore, the interconnecting flow line, the fluid processing unit, and any combination thereof, wherein the wellbore fluid comprises a base fluid, a plurality of first mineral particles, and a plurality of second mineral particles such that the first mineral particles and the second mineral particles have a multiparticle specific gravity of about 3 to about 20.
  • Yet another embodiment of the present invention provides for a wellbore drilling assembly that includes a pump capable of introducing a fluid into a wellbore via a feed pipe; a fluid processing unit capable of receiving the fluid from a wellbore via an interconnecting flow line; and a wellbore fluid disposed in at least one selected from the group consisting of the pump, the feed pipe, the wellbore, the interconnecting flow line, the fluid processing unit, and any combination thereof, wherein the wellbore fluid has a density of about 7 ppg to about 50 ppg and comprises a base fluid and a plurality of degradable mineral particles.
  • Figures 1A-B illustrate examples of theoretical multi-modal diameter distributions for particles.
  • Figure 2 illustrates exemplary recovery and recycling processes according to at least some embodiments described herein .
  • Figure 3 illustrates an exemplary wellbore drilling assembly for use in conjunction with the mineral particles, related fluids, and related methods described herein .
  • the present invention relates to mineral particles that provide for wellbore fluids with tailorable properties and capabilities, and methods relating thereto.
  • the present invention provides for, in some embodiments, mineral particles that can be used in subterranean applications as unique weighting agents.
  • the mineral particles described herein may advantageously have multiple properties that provide for desirable effects that other wellbore additives would traditionally provide for (e.g. , viscosifiers) .
  • the mineral particles described herein may advantageously serve as weighting agents and other wellbore additives select viscosifiers, cement particles, sag control additives, proppants, and the like), which may allow for the production of wellbore fluids with tailorable properties and capabilities using minimal types of wellbore additives.
  • the use of the mineral particles described herein in wellbore fluids for multiple purposes may reduce the complexity, and consequently the cost, of such wellbore fluids.
  • the mineral particles described herein may, in some embodiments, have additional advantages over traditional barite weighting agents.
  • the weighting agents produced can include up to about 21% sand, which can be abrasive to many wellbore tools.
  • the minerals described herein may advantageously be less abrasive, as described further herein, thereby prolonging the life of wellbore tools (e.g. , pumps, drill bits, drill string, and a casing) .
  • the mineral particles described herein may, in some embodiments, be degradable, which allows for unique opportunities for cleanup and cementing operations, as described further herein .
  • the mineral particles described herein may, in some embodiments, be recovered and recycled for use in other mineral applications (e.g. , smelting) .
  • the recycling of the mineral particles further reduces costs and environmental impact of the exploration and recovery of hydrocarbons.
  • wellbore additives and/or wellbore fluids may comprise the mineral particles described herein .
  • Such wellbore additives and/or wellbore fluids may be used in conjunction with a plurality of wellbore operations.
  • the terms “wellbore additive” and “wellbore fluid” refer to any additive or fluid, respectively, suitable for use in conjunction with a wellbore penetrating a subterranean formation and does not imply any particular action by the additive or fluid .
  • wellbore operation refers to any treatment or operation suitable for use in conjunction with a wellbore and/or subterranean formation, e.g. , drilling operations, lost circulation operations, fracturing operations, cementing operations, completion operations, and the like.
  • mineral particles encompasses single types of mineral particles and combinations of more than one type of mineral particle described herein . Distinctions between types of mineral particles may, in some embodiments, be defined by at least one of mineral composition, production method, average diameter, diameter distribution, shape, presence or absence of coating, coating composition, and the like, and any combination thereof.
  • the mineral particles described herein suitable for, inter alia, increasing the density of wellbore fluids described herein may have a specific gravity ranging from a lower limit of about 2.6, 3, 4, 4.5, 5, or 5.5 to an upper limit of about 20, 15, 10, 9, 8, or 7, and wherein the specific gravity may range from any lower limit to any upper limit and encompasses any subset therebetween.
  • the mineral particles described herein may comprise traditional minerals and/or non-traditional minerals useful for weighting a wellbore fluid, which may depend on, inter alia, the application, the desired wellbore fluid properties, the availability of the minerals, and the like, and any combination thereof.
  • Examples of traditional minerals useful for weighting a wellbore fluid include, but are not limited to, BaS0 4 , CaC0 3 , (Ca,Mg)C0 3 , FeC0 3 , Fe 2 0 3 , a- Fe 2 0 3 , a-FeO(OH), Fe 3 0 4 , FeTi0 3 , (Fe,Mg)Si0 4 , SrS0 4 , MnO, Mn0 2 , Mn 2 0 3 , Mn 3 0 4 , Mn 2 0 7 , MnO(OH), (Mn 2+ ,Mn 3+ ) 2 0 4 , and suitable combinations thereof.
  • Some embodiments described herein may involve grinding bulk mineral materials so as to yield the mineral particles described herein.
  • Additional examples of traditional minerals in their native form may include, but are not limited to, barite, calcium carbonate, dolomite, hematite, siderite, magnetite, manganese dioxide, manganese (IV) oxide, manganese oxide, manganese tetraoxide, manganese (II) oxide, manganese (III) oxide, and suitable combinations thereof.
  • non-traditional minerals useful for weighting a wellbore fluid include, but are not limited to, Agl, AgCI, AgBr, AgCuS, AgS, Ag 2 S, Ag 3 SbS 3 , AgSbS 2 , AgSbS 2 , Ag 5 SbS 4 , (AgFe 2 S 3 ), Ag 3 AsS 3 , Ag 3 AsS 3 , Cu(Ag,Cu) 6 Ag 9 As 2 Sii, [(Ag,Cu)6(Sb,As) 2 S 7 ][Ag 9 CuS 4 ], Ag 3 AuTe 2 , (Ag,Au)Te 2 , Ag 2 Te, Al 2 0 3 , AI 2 Si0 5 , AsSb, (Co,Ni,Fe)As 3 , PtAs 2 , AuTe 2 , BaC0 3 , BaO, BeO, Bi, BiOCI, (BiO) 2 C0 3 , Bi0 3 , Bi 2 S 3
  • non-traditional minerals in their native form may include, but are not limited to, acanthite, alamandite,lastite, altaite, aluminum oxide, andalusite, anglesite, antimony sulfide, antimony tin oxide, antimony trioxide, argentite, arsenopyrite, awaruite, barium carbonate, barium oxide, bastnaesite, beryllium oxide, birnessite, bismite, bismuth, bismuth oxycarbonates, bismuth oxychloride, bismuth sulfide, bismuth sulfide, bismuth trioxide, bismuth (III) oxide, bixbyite, bornite, boulangerite, bournonite, brannerite, braunite, bravoite, bromyrite, cadimum sulfide, cadimum telluride, calaverite, calcium oxide, calomel, carrollite, cassiterite,
  • the mineral particles described herein may be produced by grinding methods, precipitation methods, melt form plasma methods, etching bulk minerals, or any combination thereof, each where applicable based on, inter alia, the composition of the mineral particle.
  • grinding refers to mechanically breaking down the material into smaller pieces and encompasses milling, Raymond milling, roller milling, ball milling, and grinding, machine grinding, crushing, and the like.
  • the terms “median diameter” and “diameter distribution” refers to a weight median diameter and a weight diameter distribution, respectively, wherein the diameter is based on the largest dimension of the particles. For example, rod-like particles would have diameter distributions and the like based on the length of the rod-like particles. As used herein, the term “median diameter” refers to a diameter distribution wherein 50% of the particles are smaller than a given value.
  • the mineral particles described herein produced by grinding methods may have a median diameter ranging from a lower limit of about 100 nm, 250 nm, 500 nm, 1 micron, or 5 microns to an upper limit of about 5000 microns, 2500 microns, 1000 microns, 500 microns, 100 microns, 75 microns, 50 microns, 25 microns, or 10 microns, and wherein the median diameter may range from any lower limit to any upper limit and encompasses any subset therebetween.
  • larger particle sizes may be appropriate in some instances, e.g. , mineral particles used in lost circulation or proppant compositions and methods.
  • the median diameter of the mineral particles may range from a lower limit of about 350 microns, 500 microns, or 1 mm to an upper limit of about 15 mm, 10 mm, or 5 mm, and wherein the median diameter may range from any lower limit to any upper limit and encompasses any subset therebetween.
  • Some embodiments of the present invention may involve precipitating particles from two or more salts in aqueous solutions so as to yield the mineral particles described herein (or precursors to mineral particles described herein, e.g. , particles that can be further calcined to yield mineral particles described herein).
  • some embodiments of the present invention may involve precipitating manganese carbonate from manganese (II) salts in aqueous solutions with alkali metal carbonates so as to yield the mineral particles described herein that comprise manganese carbonate.
  • Examples of other salts that may be used in producing precipitated mineral particles may include salts ⁇ e.g., fluorides, chlorides, bromides, iodides, acetates, formates, citrates, sulfates, carbonates, hydroxides, phosphates, silicates, molybdates, tungstates, vanadates, titanates, chromates, and the like) of barium, bismuth, chromium, cobalt, copper, gold, iron, lead, nickel, strontium, tin, zinc, manganese, tungsten, aluminum, silver, cerium, magnesium, zirconium, titanium, calcium, antimony, lead, and the like, and any combination thereof.
  • salts ⁇ e.g., fluorides, chlorides, bromides, iodides, acetates, formates, citrates, sulfates, carbonates, hydroxides, phosphates, silicates, molybdates, tungstates
  • Some precipitation embodiments described herein may further involve adjusting the pH of the aqueous solution, adjusting the temperature of the aqueous solution, adding morphology modifiers to the aqueous solution, adding aqueous-miscible organic liquids (e.g. , an alcohol or acetone) to the aqueous solution, using capping agents (e.g., compounds with moieties that interact with the crystal being formed so as to stop, slow, and/or direct growth of the crystal), and any combination thereof.
  • capping agents e.g., compounds with moieties that interact with the crystal being formed so as to stop, slow, and/or direct growth of the crystal
  • the foregoing may be useful in regulating the average diameter, diameter distribution, and shape of the mineral particles described herein. For example, increasing the pH and/or temperature may increase the average diameter of the mineral particles described herein.
  • additional polyelectrolytes may be used to synthesize mineral particles having a desired non-spherical shape.
  • the particles produced by precipitation may be calcined to yield mineral particles described herein. Calcining may, inter alia, increase the mechanical properties (e.g., crush strength) of the mineral particles, yield a corresponding oxide (e.g. , manganese carbonate to manganese oxide, calcium carbonate to calcium oxide, bismuth carbonate to bismuth oxycarbonate or bismuth oxide, zirconium hydroxide to zirconium oxide, or magnesium hydroxide to magnesium oxide), or any combination thereof.
  • a corresponding oxide e.g. , manganese carbonate to manganese oxide, calcium carbonate to calcium oxide, bismuth carbonate to bismuth oxycarbonate or bismuth oxide, zirconium hydroxide to zirconium oxide, or magnesium hydroxide to magnesium oxide
  • Examples of mineral particles that can be produced with precipitation methods may include, but are not limited to, Agl, AgCI, AgBr, AgCuS, AgS, Ag 2 S, Al 2 0 3 , AsSb, AuTe 2 , BaC0 3 , BaS0 4 , BaCr0 4 , BaO, BeO, BiOCI, (BiO) 2 C0 3 , Bi0 3 , Bi 2 S 3 , Bi 2 0 3 , CaO, CaF 2 , CaW0 4 , CaC0 3 , (Ca,Mg)C0 3 , CdS, CdTe, Ce 2 0 3 , CoAsS, Cr 2 0 3 , CuO, Cu 2 0, CuS, Cu 2 S, CuS 2 , CugS 5 , CuFeS 2 , Cu 5 FeS 4 , CuS ⁇ Co 2 S 3 , Fe 2+ Al 2 0 4 , Fe 2 Si0 4
  • combination of more than one salt may be used to form precipitated particles with two or more of the foregoing precipitates in substantially homogeneous domain.
  • strontium and barium salts may be utilized in forming precipitated particles that comprise (Ba,Sr)S0 4 or (Ba,Sr)C0 3 .
  • barium salts may be used in forming precipitated particles that comprise Ba(S0 4 ,Cr0 4 ).
  • Examples of other substantially homogeneous domains may include, but are not limited to, suitable mixtures of barium, strontium, calcium, zinc, iron, cobalt, manganese, lead, tin, and the like, and any combination thereof in the form of sulfates, carbonates, hydroxide, oxides, sulfides, chromates and the like, and any combination thereof.
  • Some embodiments may involve forming precipitated mineral particles with discrete domains that comprise at least one of the foregoing precipitates.
  • a calcium carbonate particle may be formed by precipitation and then barium salts added so as to precipitate barium carbonate on at least a portion of the surface of the calcium carbonate precipitated particle.
  • a higher specific gravity composition like those comprising bismuth may be precipitated and then a different composition precipitated thereon.
  • Precipitating a second composition on a first composition may allow for the first composition to be formed with a desired shape and the second composition to increase the specific gravity of the particle, which may allow for a desired higher specific gravity particle with a desired shape that may be difficult to achieve otherwise.
  • the higher specific gravity particle may be the first composition and the second composition precipitated thereon may enable linking of the particles or reduce the abrasiveness of the particles (described further herein).
  • the mineral particles produced by precipitation may be calcined to yield precipitated particles described herein. Calcining may, inter alia, increase the mechanical properties (e.g. , crush strength) of the precipitated particles, yield a corresponding oxide (e.g. , manganese carbonate to manganese oxide, calcium carbonate to calcium oxide, bismuth carbonate to bismuth oxycarbonate or bismuth oxide, zirconium hydroxide to zirconium oxide, or magnesium hydroxide to magnesium oxide), or any combination thereof.
  • a corresponding oxide e.g. , manganese carbonate to manganese oxide, calcium carbonate to calcium oxide, bismuth carbonate to bismuth oxycarbonate or bismuth oxide, zirconium hydroxide to zirconium oxide, or magnesium hydroxide to magnesium oxide
  • the precipitated mineral particles described herein may be shaped as spherical, ovular, substantially spherical, substantially ovular, discus, platelet, flake, toroidal (such as donut-shaped), dendritic, acicular, spiked with a substantially spherical or ovular shape (such as a sea urchin), spiked with a discus or platelet shape, rod-like, fibrous (such as high-aspect ratio shapes), polygonal (such as cubic or pyramidal), faceted (such as the shape of crystals), star or floral shaped (such as a tripod or tetrapod where rods or the like extend from a central point), or any hybrid thereof (e.g.
  • dumbbell-shape spherical, ovular, substantially spherical, and substantially ovular-shaped precipitated mineral particles may be useful in producing wellbore fluids that are less abrasive to wellbore tools and/or decrease viscosity as compared to ground mineral particles.
  • platelet, flake, acicular, spiked with a discus or platelet shape, rod-like, and fibrous- shaped precipitated mineral particles may be useful in producing wellbore fluids with less sag and/or greater viscosity as compared to ground mineral particles.
  • the precipitated mineral particles described herein may have a median diameter ranging from a lower limit of about 5 nm, 10 nm, 20 nm, 50 nm, 100 nm, 250 nm, 500 nm, or 1 micron to an upper limit of about 100 microns, 50 microns, 25 microns, 10 microns, 5 microns, 1 micron, or 750 nm, and wherein the median diameter may range from any lower limit to any upper limit and encompasses any subset therebetween .
  • precipitation methods may be used to yield larger sizes of mineral particles that are millimeters or larger in size. For example, precipitated mineral particles having a median diameter of about 1- 10 mm may be used as proppants or lost circulation materials.
  • the precipitated particles may be ground to achieve a desired size and/or shape.
  • Methods that involve precipitation and then grinding may advantageously allow for production of higher purity precipitated particles as compared to particles produced by grinding bulk minerals. Further, such methods may allow for reduced cost while maintaining high purity as compared to some precipitation methods with steps to control particle size.
  • larger precipitated particles may be directly added to a mined mineral and undergo the same grinding process such that the ground product may have a higher purity than the mineral alone.
  • large particles of barium sulfate may formed by precipitation and added to mined barite with high levels of contaminants (e.g. , greater than 15% sand) such that the ground product is higher purity, which yields a less abrasive, higher specific gravity weighting agent that is of greater value in the industry.
  • the conditions under which the precipitated particles are formed may be manipulated so as to assist in controlling or directing the characteristics of the precipitated particles (e.g., shape, median diameter, diameter distribution, narrow diameter distribution, density, hardness, and the like) .
  • characteristics of the precipitated particles e.g., shape, median diameter, diameter distribution, narrow diameter distribution, density, hardness, and the like
  • conditions that can be manipulated may include, but are not limited to, pH, temperature, chemical composition of morphology modifiers, concentration of morphology modifiers, concentration of the salts used in the production of the precipitated particles, and the like, and any combination thereof.
  • increasing the pH and/or temperature may increase the median diameter of the precipitated particles.
  • the term "morphology modifiers" refers to chemicals that are used during the formation of precipitated particles that effect the characteristics of the precipitated particles.
  • morphology modifiers may include, but are not limited to, polymers, surfactants, electrolytes, hydrogen peroxide, silicates and other similar inorganic materials, aqueous-miscible organic liquids, and the like, and any combination thereof.
  • the wellbore additives and/or the wellbore fluids may comprise the mineral particles described herein having a multimodal diameter distribution (e.g. , bimodal, trimodal, and so on) .
  • the wellbore additives and/or the wellbore fluids may comprise the mineral particles described herein having a multimodal diameter distribution such that at least one mode has an average diameter (or peak diameter) ranging from a lower limit of about 5 nm, 10 nm, 20 nm, 50 nm, 100 nm, 250 nm, 500 nm, or 1 micron to an upper limit of about 50 microns, 10 microns, 5 microns, 1 micron, or 500 nm and at least one mode has an average diameter ranging from a lower limit of about 10 microns, 25 microns, 50 microns, or 100 microns to an upper limit of about 5000 microns, 2500 microns, 1000 microns, 500 microns, 100 micron
  • Figures 1A- B illustrate appropriate multimodal diameter distributions for use in wellbore fluids.
  • Figure 1A illustrates a bimodal diameter distribution with a first mode average diameter of about 1 micron and a second mode average diameter of about 25 microns.
  • Figure I B illustrates a trimodal diameter distribution with a first mode average diameter of about 5 microns, a second mode average diameter of about 50 microns, and a third mode average diameter of about 90 microns.
  • the mode(s) of a diameter distribution may independently be considered to have a narrow diameter distribution . That is, at least one mode of a diameter distribution (including monomodal) may have a standard deviation of about 2% or less of the peak diameter for the given mode (e.g. , about 0.1% to about 2% or any subset therebetween) .
  • precipitation methods may be advantageously employed to achieve narrow diameter distributions of mineral particles described herein .
  • the mineral particles described herein may have a coating on at least a portion of the surface of the mineral particles.
  • the term "coating,” and the like does not imply any particular degree of coating on the particle. In particular, the terms “coat” or “coating” do not imply 100% coverage by the coating on the particle. Further, a coating may, in some embodiments, be covalently and/or noncovalently associate with the mineral particles described herein.
  • a coating suitable for use in conjunction with the mineral particles described herein may include, but are not limited to, polymers, surfactants, and any combination thereof. Coatings may, in some embodiments, assist in the suspension of the mineral particles and/or the compatibility of the mineral particles with a wellbore fluid and/or wellbore operation.
  • a coating like an alkyl amine may, in some embodiments, associate with the surface of the mineral particles so as to render the mineral particle more hydrophobic, which may enhance the suspendability of the mineral particles in oil-based fluids.
  • a coating may be applied during production of the mineral particles described herein.
  • grinding production methods may, in some embodiments, be conducted in the presence of polymers, surfactants, or the like suitable for use as a coating .
  • precipitation production methods may be conducted in the presence of polymers, surfactants, or the like suitable for use as a coating .
  • polymers, surfactants, or the like in a production method of the mineral particles described herein should be chosen so as not to significantly impact the production in a negative manner.
  • Polymers suitable for use in conjunction with the coated mineral particles described herein may, in some embodiments, have a molecular weight ranging from a lower limit of about 10,000 g/mol, 25,000 g/mol, 100,000 g/mol, or 250,000 g/mol to an upper limit of about 2,000,000 g/mol, 1,000,000 g/mol, 500,000 g/mol, or 250,000 g/mol, and wherein the molecular weight may range from any lower limit to any upper limit and encompasses any subset therebetween.
  • polymers suitable for use in conjunction with the coated mineral particles described herein may, in some embodiments, include, but are not limited to, homopolymers or copolymers of monomers selected from the group comprising : acrylic acid, itaconic acid, maleic acid or anhydride, hydroxypropyl acrylate vinylsulphonic acid, acrylamido 2-propane sulphonic acid, acrylamide, methacrylamide, hydrolyzed acrylamide, styrene sulphonic acid, acrylic phosphate esters, methyl vinyl ether, vinyl acetate, stearyl methacrylate, butylacrylate, vinyl pyrrolidone, glycols (ethylene glycol, propylene glycol, and butylene glycol), and the like, salts thereof where appropriate, any derivative thereof, and any combination thereof.
  • monomers selected from the group comprising : acrylic acid, itaconic acid, maleic acid or anhydride, hydroxypropyl acrylate vinylsulphonic acid, acrylamido
  • Examples of commercially available polymers may include Pluronic® surfactants (polyethylene oxide-polypropylene oxide-polyethylene oxide triblock polymers, available from BASF), Tetronic® surfactants (tetra-functional block copolymers based on ethylene oxide and propylene oxide, available from BASF), and the like, and any combination thereof.
  • Pluronic® surfactants polyethylene oxide-polypropylene oxide-polyethylene oxide triblock polymers, available from BASF
  • Tetronic® surfactants tetra-functional block copolymers based on ethylene oxide and propylene oxide, available from BASF
  • surfactants suitable for use in conjunction with the coated mineral particles described herein may, in some embodiments, include, but are not limited to, oleic acid, monobasic fatty acids, polybasic fatty acids, alkylbenzene sulfonic acids, alkane sulfonic acids, linear alpha-olefin sulfonic acid, phospholipids, betaines, and the like, salts thereof where appropriate, any derivative thereof, and any combination thereof.
  • surfactants examples include Brij® surfactants (ethoxylated fatty alcohols, available from Sigma-Aldrich), Triton® surfactants (ethoxylated fatty alkylphenols, available from Sigma-Aldrich), and the like, and any combination thereof.
  • Brij® surfactants ethoxylated fatty alcohols, available from Sigma-Aldrich
  • Triton® surfactants ethoxylated fatty alkylphenols, available from Sigma-Aldrich
  • coatings may comprise consolidating agents that generally comprise any compound that is capable of minimizing particulate migration, which may be suitable for methods and compositions relating to proppant packs, gravel packs, and the like.
  • Suitable consolidating agents may include, but are not limited to, non-aqueous tackifying agents, aqueous tackifying agents, emulsified tackifying agents, silyl-modified polyamide compounds, resins, crosslinkable aqueous polymer compositions, polymerizable organic monomer compositions, consolidating agent emulsions, zeta-potential modifying aggregating compositions, silicon-based resins, and binders. Combinations and/or derivatives of these also may be suitable.
  • Nonlimiting examples of suitable non-aqueous tackifying agents may be found in U.S. Patent Nos. 7,392,847, 7,350,579, 5,853,048; 5,839,510; and 5,833,000, the entire disclosures of which are herein incorporated by reference.
  • suitable aqueous tackifying agents may be found in U.S. Patent Nos. 8,076,271, 7,131,491, 5,249,627 and 4,670,501, the entire disclosures of which are herein incorporated by reference.
  • Nonlimiting examples of suitable crosslinkable aqueous polymer compositions may be found in U .S. Patent Application Publication No. 2010/0160187 and U .S. Patent No.
  • Nonlimiting examples of suitable silyl-modified polyamide compounds may be found in U.S. Patent No. 6,439,309 entitled the entire disclosure of which is herein incorporated by reference.
  • suitable resins may be found in U .S. Patent Nos. 7,673,686; 7, 153,575; 6,677,426; 6,582,819; 6,311,773; and 4,585,064 as well as U.S. Patent Application Publication No. 2008/0006405 and U.S. Patent No. 8,261,833, the entire disclosures of which are herein incorporated by reference.
  • Nonlimiting examples of suitable polymerizable organic monomer compositions may be found in U.S.
  • Patent No. 7,819,192 the entire disclosure of which is herein incorporated by reference.
  • suitable consolidating agent emulsions may be found in U .S. Patent Application Publication No. 2007/0289781 the entire disclosure of which is herein incorporated by reference.
  • suitable zeta-potential modifying aggregating compositions may be found in U .S. Patent Nos. 7,956,017 and 7,392,847, the entire disclosures of which are herein incorporated by reference.
  • suitable silicon-based resins may be found in Application Publication Nos. 2011/0098394, 2010/0179281, and U.S. Patent Nos.
  • the wellbore fluids described herein may comprise a base fluid and the mineral particles described herein.
  • the mineral particles described herein may be useful as weighting agents so as to adjust the density of a wellbore fluid described herein.
  • the mineral particles may serve other functions as described further herein.
  • weighting agents have consisted essentially of a single mineral, most commonly barite (sometimes with up to 21% sand contamination), with a monomodal diameter distribution.
  • barite sometimes with up to 21% sand contamination
  • the mineral particles described herein may, in some embodiments, be included in the wellbore additives and/or the wellbore fluids as a barite substitute weighting agent or a barite augmenting weighting agent.
  • the wellbore additives and/or the wellbore fluids may comprise the mineral particles described herein so as to achieve a desired density of the wellbore fluid.
  • the wellbore fluids described herein may have a density between a lower limit of about 7 pounds per gallon ("ppg"), 9 ppg, 12 ppg, 15 ppg, or 22 ppg to an upper limit of about 50 ppg, 40 ppg, 30 ppg, 22 ppg, 20 ppg, or 17 ppg, and wherein the density of the wellbore fluid may range from any lower limit to any upper limit and encompasses any subset therebetween.
  • ppg pounds per gallon
  • the ability to achieve a desired density of the wellbore fluid while maintaining a fluid that can be pumped may depend on, inter alia, the composition and specific gravity of the mineral particles, the shape of the mineral particles, the concentration of the mineral particles, and the like, and any combination thereof.
  • wellbore fluids having a density of about 25 ppg or higher may be achieved with mineral particles having a specific gravity of about 7 or greater and having a shape of spherical, substantially spherical, ovular, substantially ovular, or a hybrid thereof so as to allow for the fluid to be pumpable.
  • wellbore fluids having a density of about 30 ppg or less may be achieved with precipitated particles having a specific gravity of about 7 or greater and having a larger variety of shapes, including discus.
  • the plurality of mineral particles described herein may be useful in modifying the density of a wellbore fluid
  • achieving a desired density may utilize the mineral particles described herein that comprise at least one of rhodochrosite, tenorite, awaruite, albandite, bismuth oxychloride, fluorite, manganese carbonate, manganese (II) oxide, manganese (II, III) oxide, manganese (III) oxide, manganese (IV) oxide, manganese (VII) oxide, spalerite, strontianite, tenorite, zinc carbonate, zinc oxide, and any combination thereof.
  • a mixture of two or more types of mineral particles described herein having a multiparticle specific gravity useful for achieving a desired density As used herein, the term “multiparticle specific gravity” refers to the calculated specific gravity from Formula I.
  • the wellbore additives and/or the wellbore fluids may comprise a mixture of mineral particles described herein having a multiparticle specific gravity ranging from a lower limit of about 3, 4, 4.5, 5, or 5.5 to an upper limit of about 20, 15, 10, 9, 8, or 7, and wherein the multiparticle specific gravity may range from any lower limit to any upper limit and encompasses any subset therebetween .
  • specific gravity refers to the multiparticle specific gravity.
  • the size and shape of each of the precipitated particles may be tailored so as to minimize separation of the precipitated particles, which may lead to a wellbore fluid with a striated density profile.
  • a first precipitated particle with a discus or platelet shape may impede the settling of a second precipitated particle that has a high settling or migration rate (e.g., a higher specific gravity, spherical particle) .
  • the properties of the mineral particles described herein may be tailored to mitigate the abrasion of wellbore tools (e.g. , pumps, drill bits, drill string, and a casing) as compared to comparable API grade barite (i. e. , a comparable wellbore fluid having the same density and/or sag as the wellbore fluid comprising the mineral particles), which may prolong the life of the wellbore tools.
  • wellbore tools encompasses tools suitable for use in conjunction with wellbore operations, including tools that are used outside of the wellbore, e.g. , pumps, shakers, and the like.
  • Abrasion can be measured by the ASTM G75-07 and is reported as a Miller Number or a SAR Number.
  • Suitable mineral particles can be those with properties tailored to mitigate abrasion, which may include, but are not limited to, hardness (e.g. , a Mohs hardness of less than about 5), size (e.g. , median diameter less than about 400 nm or mode of a multimodal distribution having an peak diameter less than about 400 nm), shape (e.g. , particle shapes with higher sphericity like spherical, substantially spherical, ovular, substantially ovular, and the like), coatings (e.g. , thicker and/or elastic coatings that minimize physical interactions between the mineral portion of the particle and the wellbore tool), and the like, and any combination thereof.
  • wellbore additives and/or the wellbore fluids may comprise substantially spherical awaruite particles with a median diameter less than about 400 nm and manganese carbonate particles, which have a Mohs hardness less than about 5.
  • wellbore additives and/or the wellbore fluids may comprise at least one of the foregoing suitable mineral particles that mitigate abrasion of wellbore tools in combination with at least one mineral particle described herein that may not mitigate abrasion of wellbore tools.
  • wellbore additives and/or the wellbore fluids that are less abrasive than the comparable wellbore fluid may comprise manganese carbonate particles with a median diameter less than about 400 nm and awaruite particles with a median diameter greater than about 500 nm .
  • Examples of mineral particles with a Mohs hardness of less than about 5 may include BaS0 4 , CaC0 3 , (Ca,Mg)C0 3 , FeC0 3 , FeTi0 3 , (Fe,Mg)Si0 4 , SrS0 4 , MnO(OH), barite, calcium carbonate, dolomite, siderite, manganese dioxide, Agl, AgCI, Ag Br, AgS, Ag 2 S, Ag 3 SbS 3 , AgSbS 2 , AgSbS 2 , Ag 5 SbS 4 , (Ag Fe 2 S 3 ), Ag 3 AsS 3 , Ag 3 AsS 3 , Cu(Ag,Cu) 6 Ag 9 As 2 Sii,
  • Particles (e.g. , weighting agents, proppants, and cement particles) in wellbore fluids can settle from the wellbore fluid therein, which is a condition known as "sag .”
  • the term “sag” refers to an inhomogeneity in density of a fluid in a wellbore, e.g., along the length of a wellbore and/or the diameter of a deviated wellbores. In some instances, sag can cause to portions of the wellbore fluid to be at an insufficient density to stabilize the wellbore and other portions of the wellbore fluid to have increased density.
  • Unstabilized portions of the wellbore can lead to wellbore collapse and/or pressure buildups that cause blowouts. Increased density can cause wellbore damage (e.g., undesired fracturing of the wellbore), which may show up as pressure increases or decreases when changing from static to flow conditions of the fluid which can cause higher than desired pressures downhole.
  • wellbore damage e.g., undesired fracturing of the wellbore
  • the mineral particles described herein may be sized, shaped, or otherwise treated (e.g., coated) so as to mitigate sag in wellbore fluids.
  • the size may, inter alia, provide for the formation of a stable suspension that exhibit low viscosity under shear.
  • the specific gravity of the mineral particles may further allow for such mineral particles to provide for a desired density of the wellbore fluid while mitigating sag of these mineral particles or other particles therein.
  • Sag control can be measured by analyzing density changes in an undisturbed sample of wellbore fluid over time at a typical wellbore temperature (e.g. , about 300°F) and an elevated pressure (e.g. , about 5,000 psi to about 10,000 psi).
  • a typical wellbore temperature e.g. , about 300°F
  • an elevated pressure e.g. , about 5,000 psi to about 10,000 psi.
  • the mineral particles described herein that provide effective sag control may, in some embodiments, yield wellbore fluids having a change in density of less than about 1 ppg (e.g. , about 0.5 ppg change or less including no change in density) when comparing a fluid's original density to the fluid's density at the bottom of a sample having been undisturbed for a given amount of time.
  • the mineral particles described herein may provide sag control (i.e. , a density change of less than about 1 ppg) over a time ranging from a lower limit of about 10 hours, 24 hours, 36 hours, or 48 hours to an upper limit of about 120 hours, 96 hours, 72 hours, or 48 hours, and wherein the sag control timeframe of the wellbore fluid may range from any lower limit to any upper limit and encompasses any subset therebetween .
  • sag control i.e. , a density change of less than about 1 ppg
  • the properties of the mineral particles described herein may be tailored to achieve sag control.
  • Properties of the mineral particles that can be tailored to achieve sag control may include, but are not limited to, size (e.g. , median diameter of about 2 microns or less or at least one mode of a multimodal distribution having such a peak diameter of about 2 microns or less), shape (e.g., particle shapes with lower sphericity like discus, platelet, flake, ligamental, acicular, spiked with a substantially spherical or ovular shape, spiked with a discus or platelet shape, fibrous, toroidal, and the like), coatings, linking (described further herein), and the like, and any combination thereof.
  • sag control may utilize the mineral particles described herein that comprise at least one of rhodochrosite, tenorite, awaruite, albandite, bismuth oxychloride, fluorite, manganese carbonate, manganese (II) oxide, manganese (II, III) oxide, manganese (III) oxide, manganese (IV) oxide, manganese (VII) oxide, spalerite, strontianite, tenorite, zinc carbonate, zinc oxide, and any combination thereof.
  • the size and shape of each of the mineral particles may be tailored so as to minimize separation of the mineral particles, which may lead to a wellbore fluid with a striated density profile.
  • a first mineral particle with a discus or platelet shape may impede the settling of a second mineral particle that has a high settling or migration rate (e.g. , a higher specific gravity, spherical particle).
  • At least some of the mineral particles described herein may, in some embodiments, be capable of being linked by linking agents. Linking of mineral particles may allow for increasing the viscosity of the wellbore fluid or forming a solid mass described further herein.
  • the composition of the mineral particles described herein may determine if the mineral particles are suitable for being linked and to what degree they can be linked.
  • linking agents suitable for use in conjunction with the wellbore additives and/or the wellbore fluids may, in some embodiments, include, but are not limited to, eugenol, guaiacol, methyl guaiacol, salicyladehyde, salicyladimine, salicylic acid, sodium salicylate, acetyl salicylic acid, methyl salicylic acid, methyl acetylsalicylic acid, anthranilic acid, acetyl anthranilic acid, vanillin, derivatized 1,2-dihydroxybenzene (catechol), derivatized or unsubstituted phthalic acid, ortho-phenylenediamine, ortho- aminophenol, ortho-hydroxyphenylacetic acid, alkylsilanes, esters, ethers, and the like, and any combination thereof.
  • polymers of the foregoing examples, or suitable derivatives thereof may be used as linking agents.
  • vinyl derivatives of the foregoing examples may be used in synthesizing a polymer or copolymer suitable for use as a linking agents.
  • carboxylated derivates of the foregoing examples may be used in derivatizing a polyamine to yield suitable linking agents.
  • Additional examples may include, but are not limited to, compounds (including polymers and lower molecular weight molecules) having at least two silane moieties, ester moieties, ether moieties, sulfide moieties, amine moieties, and the like, and any combination thereof.
  • Viscosity increases from linking with linking agents may, in some embodiments, yield wellbore fluids that remain pumpable, wellbore fluids that are non-pumpable, or hardened masses.
  • One skilled in the art with the benefit of this disclosure should understand that the extent of the viscosity increase may depend on, inter alia, the composition of the mineral particles described herein, the composition of the linking agents, the relative concentration of the mineral particles and the linking agents, intended use, additional components in the wellbore fluid, and any combination thereof.
  • the increase in viscosity may yield a hardened mass.
  • a hardened mass is used to indicate a composition that has transitioned from a liquid-state to a substantially solid- state, but does not imply a size or function of the hardened mass.
  • a hardened mass may be a plug that spans cross-sectional area of the wellbore or a composition that has filled a crack in an existing hardened mass (e.g. , a cement sheath) and solidified .
  • a hardened mass may be rigid or relatively pliable.
  • such a hardened mass may be permeable (e.g. , 1 Da to about 100 mDa) or substantially non-permeable (e.g. , about 100 mDa or less).
  • the wellbore additives and/or the wellbore fluids may comprise linking agents at an amount ranging from a lower limit of about 0.1%, 0.5%, or 1% by weight of the mineral particles to an upper limit of about 10%, 5%, or 1% by weight of the mineral particles.
  • linking methods and compositions may utilize the mineral particles described herein that comprise at least one of Al 2 0 3 , AI 2 Si0 5 , BaC0 3 , BaO, BeO, (BiO) 2 C0 3 , Bi0 3 , Bi 2 0 3 , CaO, CaC0 3 , (Ca,Mg)C0 3 , CdS, CdTe, Ce 2 0 3 , (Fe,Mg)Cr 2 0 4 , Cr 2 0 3 , CuO, Cu 2 0, Cu 2 (As0 4 )(OH), CuSi0 3 ⁇ H 2 0, Fe 3 AI 2 (Si0 4 ) 3 , Fe 2+ Al 2 0 4 , Fe 2 Si0 4 , FeC0 3 , Fe 2 0 3 , a- Fe 2 0 3 , a-FeO(OH), Fe 3 0 4 , FeTi
  • Mineral particles not suitable for linking may include, but are not limited to, Ca F 2 , CuS, CuFeS 2 , FeS, FeS 2 , HgS, Hg 2 CI 2 , NiAs, NiAsS, PbS, and (Zn, Fe)S.
  • the mineral particles described herein may advantageously have a higher unconfined compressive strength (e.g. , about 1200 psi or greater) that allow for load-bearing applications (e.g., proppant applications).
  • the mineral particles described herein may advantageously have a moderate to high unconfined compressive strength (e.g. , about 500 psi or greater) that allow for implementation in applications like cements, wellbore strengthening additives, and gravel packs.
  • the unconfined compressive strength of a mineral particle may depend on, inter alia, the composition of the mineral particle, the shape of the mineral particle, additional processing steps in producing the mineral particle (e.g., calcining after precipitation), and the like, and any combination thereof.
  • such mineral particles may comprise at least one of CaC0 3 , (Ca,Mg)C0 3 , FeC0 3 , Fe 2 0 3 , a-Fe 2 0 3 , a-FeO(OH), Fe 3 0 4 , FeTi0 3 , (Fe,Mg)Si0 4 , MnO, Mn0 2 , Mn 2 0 3 , Mn 3 0 4 , Mn 2 0 7 , MnO(OH), (Mn 2+ ,Mn 3+ ) 2 0 4 , calcium carbonate, hematite, siderite, magnetite, manganese dioxide, manganese (IV) oxide, manganese oxide, manganese tetraoxide, manganese (II) oxide, manganese (III) oxide, Al 2 0 3 , AI 2 Si0 5 , CaF 2
  • At least some of the mineral particles described herein may, in some embodiments, be at least partially degradable.
  • the term “degradable” refers to a material being capable of reduced in size by heterogeneous degradation (or bulk erosion) and homogeneous degradation (or surface erosion), and any stage of degradation in between these two. This degradation can be a result of, inter alia, a chemical or thermal reaction, for example, dissolution by an acidic fluid.
  • the composition of the mineral particles described herein may determine if the mineral particles are degradable and to what extent they are degradable.
  • degradable mineral particles may comprise at least one of BaC0 3 , (BiO) 2 C0 3 , CaW0 4 , CaC0 3 , CuO, FeC0 3 , (Ce,La)C0 3 F, (Y,Ce)C0 3 F, PbC0 3 , (PbCI) 2 C0 3 , SrC0 3 , ZnC0 3 , aragonite, bastnaesite, barium carbonate, bismuth oxycarbonate, calcium carbonate, cerussite, copper oxide, manganese carbonate, phosgenite, rhodochrosite, scheelite, siderite, smithsonite, strontianite, witherite, zinc carbonate, and suitable combinations thereof.
  • Examples of mineral particles described herein that may not be degradable may, in some embodiments, include, but are not limited to, mineral particles that comprise aluminum oxide, antimony sulfide, antimony tin oxide, antimony trioxide, bismuth (III) oxide, cadmium sulfide, cadmium telluride, copper, copper sulfide, ferrous sulfide, magnesium oxide, magnetite, manganese dioxide, pyrite, strontium oxide, zirconium silicate, zinc oxide, and any combination thereof.
  • Degradation of the minerals described herein may advantageously be used in a plurality of wellbore operations, e.g., cleanup operations (e.g. , in removing a filter cake or plug from a lost circulation operation) and cementing operations (e.g. , in enhancing the permeability of a cement plug to allow for fluid to flow therethrough while still providing structural strength). Additionally, degradation may be advantageous in reducing the viscosity of a fluid by degrading mineral particles that contribute to the viscosity (e.g. , by shape and/or by linking). [0075] Examples of degradation agents that may be useful in at least partially degrading mineral particles described herein may, in some embodiments, include, but are not limited to, acid sources (e.g.
  • inorganic acids inorganic acids, organic acid, and polymers that degrade into acids like polylactic acid
  • alkaline sources e.g. , bases
  • oxidizers e.g. , peroxide compounds, permanganate compounds, and hexavalent chromium compounds.
  • the mineral particles described herein may be chosen so as to degrade over a desired amount of time, which may be dependent on, inter alia, particle size, particle shape, wellbore temperature, and mineral particle composition.
  • calcium carbonate rather than lead carbonate may be utilized, in some embodiments, when for faster degradation.
  • manganese carbonate may, in some embodiments, be chosen for slower degradation in colder wellbore environments and faster degradation in hotter wellbore environments.
  • the mineral particles described herein may be recovered from the wellbore fluids and/or wellbore additives and recycled for another use.
  • the term “recovery” relative to mineral particles described herein encompasses collection of the mineral particles from the wellbore fluids and the physical or chemical portions thereof (e.g. , collecting mineral particles that have been partially degraded or collecting the chemicals resultant from degradation like salt or ions).
  • the term “recycle” refers encompasses both using the mineral particles again without significant physical or chemical modification (e.g. , adding to another wellbore fluid after cleaning or applying a coating) and significantly changing the physical or chemical nature of the mineral particles (e.g. , melting, grinding to change the diameter distribution, dissolving and precipitating new mineral particles, and the like).
  • some embodiments may involve recovering the mineral particles described herein so as to yield a recovered mineral product (e.g. , the mineral particles, the mineral particles partially degraded, and/or the degradation products of the mineral particles), optionally grading the recovered mineral product, and recycling the recovered mineral product.
  • Recovery of mineral particles described herein may, in some embodiments, involve at least one of: filtering, magnetically extracting, centrifuging, sludging, chelating, linking, dissolving, chemically degrading, supercritical fluid extraction, and the like, and any combination thereof.
  • some of the mineral particles described herein e.g. , magnetite, awaruite, chromite, ilmenite, and siderite
  • the recovered mineral product may be used in another wellbore fluid and/or wellbore additive.
  • recovery of the mineral particles described herein may involve degrading the mineral particles while they resided the wellbore and collecting the resultant fluid (i.e. , the recovered mineral product), which may, in some embodiments, be processed so as to concentrate of the chemicals resultant from the degradation.
  • the resultant fluid i.e. , the recovered mineral product
  • an acid may be used to degrade rhodochrosite that resides in the wellbore so as to yield a fluid that comprises manganese ions.
  • Such a fluid depending on the additional components of the fluid, may then be concentrated, neutralized, and then used for precipitation of manganese carbonate mineral particles for use in additional wellbore operations.
  • the recovered mineral product (e.g. , the mineral particles, the mineral particles partially degraded, and/or the degradation products of the mineral particles) may, in some embodiments, be in the solid form (e.g., a plurality of particles or a hardened mass), liquid form (e.g., a sludge, a slurry, or a low viscosity fluid), or the like.
  • solid form e.g., a plurality of particles or a hardened mass
  • liquid form e.g., a sludge, a slurry, or a low viscosity fluid
  • the recovery methods and resultant recovered mineral product for each mineral particle described herein may, in some embodiments, depend on, inter alia, the composition of the mineral particles, the composition of the wellbore fluid and/or wellbore additive (e.g., the additional components therein), the viscosity of the wellbore fluid, and the like, and any combination thereof.
  • Recycling of the recovered mineral product described herein may, in some embodiments, involve using the recovered mineral product as-is (e.g. , producing a wellbore fluid described herein with the recovered mineral product), processing the recovered mineral product so as to yield mineral particles described herein for use of wellbore applications (e.g., grinding or precipitating to form mineral particles described herein), or using the recovered mineral product and methods and processes that produce other materials (e.g. , smelting to form steel, processing to extract precious metals, and the like) .
  • Recycling of a recovered mineral product described herein may, in some embodiments, be on-site or off-site.
  • some embodiments may involve magnetically extracting mineral particles (e.g. , awaruite) on-site so as to yield a recovered mineral product and recycling recovered mineral product comprising the mineral particles into another wellbore fluid .
  • some embodiments may involve degrading mineral particles (e.g., rhodochrosite or tenorite) into a recovered mineral product comprises the corresponding dissolved salts and recycling the recovered mineral product to yield precipitated mineral particles described herein, which may, in some embodiments, be performed on-site or at a suitable processing facility.
  • Recycling the mineral particles described herein may, in some embodiments, involve grading of the recovered mineral product.
  • grading refers to assessing the quality of the recovered mineral product relative to the desired recycling method . Grading may, in some embodiments, be achieved by gravimetry, atomic spectroscopy, mass spectroscopy, Auger electron spectroscopy, X-ray photoelectron spectroscopy, and the like.
  • the recycling of the mineral particles described herein may involve methods that concentrates of the mineral particles (or components thereof) in the recovered mineral product, cleans the mineral particles (or components thereof) (e.g. , washing or burning away organic matter), and the like, each of which may be used to enhance the grading value of the recovered mineral product.
  • the recovered mineral product may be burned to remove organic material, which may increase the grading value and, consequently, the intrinsic value of the recovered mineral product.
  • Some of the mineral particles described herein may have other characteristics that may impart properties and/or capabilities to a wellbore fluid and/or wellbore additive described herein . These characteristics may advantageously be utilized to further reduce or eliminate additional components in wellbore fluids and/or wellbore additives without reducing or eliminating the properties and/or capabilities thereof.
  • the antimicrobial properties of tenorite, copper oxide, and the like may advantageously allow for the weighting agent to also serve as, inter alia, an antimicrobial additive.
  • Antimicrobial agents may be useful in maintaining a clean wellbore and mitigating microbial growth during transportation of a wellbore additive.
  • the wellbore additives and/or the wellbore fluids may comprise mineral particles described herein having a median diameter of about 2 microns or less, a Mohs hardness of about 5 or less, and a specific gravity of about 2.6 or greater, including combination of any subset of the foregoing ranges (e.g. , mineral particles having a median diameter between about 250 nm and about 1 micron, a Mohs hardness of about 2 to about 4, and a specific gravity of about 5 to about 20) so as to provide for a wellbore fluid with a desired density, sag control, and abrasion mitigation.
  • mineral particles described herein having a median diameter of about 2 microns or less, a Mohs hardness of about 5 or less, and a specific gravity of about 2.6 or greater, including combination of any subset of the foregoing ranges (e.g. , mineral particles having a median diameter between about 250 nm and about 1 micron, a Mohs hardness of about 2 to about 4, and
  • wellbore additives and/or wellbore fluids may be produced on-site, on-the-fly, or off-site. For example, if a well site is near a mine or facility that produced mineral particles described herein, the wellbore additives and/or wellbore fluids may be produced on-site.
  • the wellbore fluid tailorability that the mineral particles described herein may further provide for on-the-fly modification of wellbore fluids so as to respond to the conditions of the wellbore and/or events that occur in the wellbore.
  • the mineral particles described herein may be present in the wellbore fluid in an amount sufficient for a particular application.
  • the mineral particles described herein may be present in a wellbore fluid in an amount up to about 70% by volume of the wellbore fluid (v %) (e.g., about 5%, about 15%, about 20%, about 25%, about 30%, about 35%, about 40%, about 45%, about 50%, about 55%, about 60%, about 65%, etc.) -
  • the mineral particles described herein may be present in the wellbore fluid in an amount of 10 v % to about 40 v % .
  • the wellbore additives may comprise the mineral particles described herein and optionally further comprise other particles and/or additional components suitable for use in a specific wellbore operation (e.g. , proppants and cement particles as described further herein) .
  • Wellbore additives may, in some embodiments, be dry powder or gravel, a liquid with a high concentration of the mineral particles described herein (e.g. , a slurry), and the like.
  • Distinctions between types of mineral particles may, in some embodiments, be defined by at least one of mineral composition, production method, average diameter, diameter distribution, presence or absence of coating, coating composition, and the like, and any combination thereof.
  • achieving homogeneous mixtures of dry wellbore additives may be aided by inclusion of a dry lubricant to facilitate homogeneous mixing and flowability.
  • dry lubricant may, in some embodiments, include, but are not limited to, molybdenum disulfide, graphite, boron nitride, tungsten disulfide, polytetrafluoroethylene particles, bismuth sulfide, bismuth oxychloride, and the like, and any combination thereof.
  • a dry lubricant may advantageously have a specific gravity greater than about 2.6 (e.g. , molybdenum disulfide, tungsten disulfide, bismuth sulfide, and bismuth oxychloride) so as contribute to the density of the resultant wellbore fluid .
  • Examples of base fluids suitable for use in conjunction with the wellbore fluids may, in some embodiments, include, but are not limited to, oil- based fluids, aqueous-based fluids, aqueous-miscible fluids, water-in-oil emulsions, or oil-in-water emulsions.
  • Suitable oil-based fluids may include alkanes, olefins, aromatic organic compounds, cyclic alkanes, paraffins, diesel fluids, mineral oils, desulfurized hydrogenated kerosenes, and any combination thereof.
  • Suitable aqueous-based fluids may include fresh water, saltwater (e.g.
  • Suitable aqueous-miscible fluids may include, but not be limited to, alcohols, e.g., methanol, ethanol, n-propanol, isopropanol, n-butanol, sec-butanol, isobutanol, and t-butanol; glycerins; glycols, e.g. , polyglycols, propylene glycol, and ethylene glycol; polyglycol amines; polyols; any derivative thereof; any in combination with salts, e.g.
  • Suitable water-in-oil emulsions also known as invert emulsions, may have an oil-to-water ratio from a lower limit of greater than about 30 : 70, 40 : 60, 50 : 50, 55 :45, 60 :40, 65 : 35, 70 : 30, 75 : 25, or 80 : 20 to an upper limit of less than about 100 :0, 95 : 5, 90 : 10, 85 : 15, 80 : 20, 75 : 25, 70 : 30, or 65 : 35 by volume in the base fluid, where the amount may range from any lower limit to any upper limit and encompass any subset therebetween.
  • suitable invert emulsions include those disclosed in U .S.
  • the wellbore fluids described herein may be foamed.
  • the term "foam” refers to a two-phase composition having a continuous liquid phase and a discontinuous gas phase.
  • the wellbore fluids may comprise a base fluid, the mineral particles described herein, a gas, and a foaming agent.
  • gases may include, but are not limited to, nitrogen, carbon dioxide, air, methane, helium, argon, and any combination thereof.
  • carbon dioxide foams may have deeper well capability than nitrogen foams because carbon dioxide emulsions have greater density than nitrogen gas foams so that the surface pumping pressure required to reach a corresponding depth is lower with carbon dioxide than with nitrogen .
  • the higher density may impart greater particle transport capability, up to about 12 lb of particles per gal of wellbore fluid .
  • the quality of a wellbore fluid that is foamed may range from a lower limit of about 5%, 10%, 25%, 40%, 50%, 60%, or 70% gas volume to an upper limit of about 95%, 90%, 80%, 75%, 60%, or 50% gas volume, and wherein the quality may range from any lower limit to any upper limit and encompasses any subset therebetween .
  • the wellbore fluid that is foamed may have a foam quality from about 85% to about 95%, or about 90% to about 95%.
  • foaming agents may include, but are not limited to, cationic foaming agents, anionic foaming agents, amphoteric foaming agents, nonionic foaming agents, or any combination thereof.
  • suitable foaming agents may, in some embodiments, include, but are not limited to, surfactants like betaines, sulfated or sulfonated alkoxylates, alkyl quarternary amines, alkoxylated linear alcohols, alkyl sulfonates, alkyl aryl sulfonates, Cio- C 2 o alkyldiphenyl ether sulfonates, polyethylene glycols, ethers of alkylated phenol, sodium dodecylsulfate, alpha olefin sulfonates such as sodium dodecane sulfonate, trimethyl hexadecyl ammonium bromide, and the like, any derivative thereof, or any combination thereof.
  • Foaming agents may include, but are not
  • the wellbore additives and/or the wellbore fluids described herein may optionally further comprise additional components, e.g., filler particles, salts, inert solids, fluid loss control agents, emulsifiers, dispersion aids, corrosion inhibitors, emulsion thinners, emulsion thickeners, viscosifying agents, gelling agents, crosslinking agents, surfactants, cement particulates, proppants, gravel particulates, lost circulation materials, pH control additives, breakers, defoaming agents, biocides, stabilizers, scale inhibitors, gas hydrate inhibitors, oxidizers, reducers, friction reducers, clay stabilizing agents, set accelerators, set retarders, and combinations thereof.
  • additional components e.g., filler particles, salts, inert solids, fluid loss control agents, emulsifiers, dispersion aids, corrosion inhibitors, emulsion thinners, emulsion thickeners, viscosifying agents, gelling agents, cross
  • the wellbore additives and/or the wellbore fluids described herein may be used in a plurality of wellbore operations.
  • Examples wellbore operations may, in some embodiments, include, but are not limited to, drilling operations, managed-pressure drilling operations, dual-gradient drilling, tripping operations, logging operations, lost circulation operations, stimulation operations, sand control operations, completion operations, acidizing operations, scale inhibiting operations, water-blocking operations, clay stabilizer operations, fracturing operations, gravel packing operations, wellbore strengthening operations, and sag control operations.
  • the wellbore additives and/or the wellbore fluids described herein may, in some embodiments, be used in full-scale operations or pills.
  • a "pill" is a type of relatively small volume of specially prepared wellbore fluid placed or circulated in the wellbore.
  • the mineral particles described herein may be useful in a variety of wellbore fluids and/or wellbore additives.
  • the wellbore fluid tailorability that the mineral particles described herein may, in some embodiments, be particularly advantageous in some wellbore operations, e.g., fracturing operations, cementing operations, and the like.
  • the wellbore fluid tailorability may provide for on-the-fly modification of wellbore fluids so as to respond to the conditions of the wellbore and/or events that occur in the wellbore. Such conditions may be determined prior to introduction of the wellbore fluid into the wellbore (e.g.
  • An on-the-fly modification to at least one of the wellbore fluid properties or capabilities can be made to optimize a wellbore operation (e.g., encountering an unknown lost circulation or thief zone).
  • Examples of wellbore operations that can employ the mineral particles and wellbore fluids described herein may, in some embodiments, include, but are not limited to, drilling operations, lost circulation operations, stimulation operations, sand control operations, completion operations, acidizing operations, scale inhibiting operations, water-blocking operations, clay stabilizer operations, fracturing operations, frac-packing operations, gravel packing operations, wellbore strengthening operations, and sag control operations.
  • Some embodiments of the present invention may further include producing hydrocarbons from at least a portion of a subterranean formation, wherein the subterranean formation has been treated with a wellbore fluid described herein .
  • hydrocarbons may be produced from the portion of the subterranean formation having been treated with a wellbore fluid described herein (e.g., a fracturing fluid) or from a second portion of the subterranean formation having not been treated with the wellbore fluid (e.g., as described herein relative to a fluid flow control operation) .
  • linkable mineral particle As used herein terms like “linkable mineral particle,” “degradable mineral particle,” and the like are used in examples to indicated at least one property of the mineral particle and do not necessarily preclude mineral particles with other properties, e.g. , a “linkable mineral particle” may also be degradable and recyclable or a “sag control mineral particle” may also be linkable and degradable.
  • cementing operations refers to operations where a composition is placed in a wellbore and/or a subterranean formation and sets therein to form a hardened mass, which encompasses hydraulic cements, construction cements, linked mineral particles described herein, and some polymeric compositions that set (e.g., polymers like epoxies and latexes).
  • cementing operations may, in some embodiments, include, but are not limited to, primary cementing operations (e.g., forming cement sheaths in a wellbore annulus or forming wellbore plugs for zonal isolation or fluid diversion) and remedial cementing operations (e.g. , squeeze operations, repairing and/or sealing microannuli and/or cracks in a hardened mass, or forming plugs) .
  • primary cementing operations e.g., forming cement sheaths in a wellbore annulus or forming wellbore plugs for zonal isolation or fluid diversion
  • remedial cementing operations e.g. , squeeze operations, repairing and/or sealing microannuli and/or cracks in a hardened mass, or forming plugs
  • cementing fluids sometimes referred to as settable compositions
  • spacer fluids spacer fluids
  • displacement fluids e.g., a plurality of fluids are often utilized including, but not limited to, cementing fluids (sometimes
  • a cementing operation may utilize, in order, ( 1) a first spacer fluid, (2) a cementing fluid, optionally (3) a second spacer fluid, and (4) a displacement fluid, each of which may independently be a wellbore fluid comprising mineral particles described herein .
  • cementing operations may utilize a plurality of fluids in order such that each subsequent fluid has a higher density than the previous fluid .
  • Achieving the desired density for a wellbore fluid in a cementing operation may, in some embodiments, involve the use of mineral particles described herein . Further, as described herein, the mineral particles utilized in such wellbore fluids may be chosen to achieve other properties and/or capabilities in the wellbore fluids.
  • each wellbore fluid may be independently designed with mineral particles described herein and do not necessarily require the use of the same mineral particle in each of the wellbore fluids or the use of a mineral particle described herein in all of the wellbore fluids.
  • the first spacer fluid may include fluorite
  • the cementing fluid may include manganese oxide
  • the second spacer may include tenorite.
  • cementing fluids, spacer fluids, and/or displacement fluids may comprise mineral particles described herein so as to achieve a desired density, a desired level of sag control, and/or a desired viscosity.
  • linkable mineral particles may be included in the cementing fluids and utilized so as to yield hardened masses that comprise linked mineral particles.
  • degradable mineral particles may be included in the cementing fluids and utilized so as to yield hardened masses that that can be at least partially degraded .
  • mineral particles comprising rhodochrosite may be useful in cementing fluids to achieve a desired density and a desired level of sag control, to link in forming the hardened mass, and to degrade for increasing the permeability of the hardened mass.
  • cementing operations may involve forming hardened masses that comprise at least one of: linked mineral particles described herein, cement particles, and any combination thereof.
  • hardened mass refers to a composition that has transitioned from a liquid-state to a substantially solid-state and does not imply a size or function of the hardened mass.
  • a hardened mass may be a plug that spans cross-sectional area of the wellbore or a composition that has filled a crack in an existing hardened mass (e.g. , a cement sheath) and solidified .
  • wellbore fluids suitable for use in conjunction with cementing operations may comprise a base fluid and linkable mineral particles and optionally further comprise cement particles.
  • the linking agents may be introduced into the wellbore in a preceding wellbore fluid, the same wellbore fluid, and/or a subsequent wellbore fluid as the settable composition .
  • a first wellbore fluid that comprises linkable mineral particles described herein may be introduced into a wellbore and subsequently a second wellbore fluid that comprises the appropriate linking agents may be introduced into the wellbore so as to contact at least some of the linkable mineral particles in the first wellbore fluid .
  • the linking agent should then link the mineral particles therein, thus forming a hardened mass comprising linked mineral particles.
  • some embodiments may involve introducing a wellbore fluid that comprises a base fluid, suitable linkable mineral particles described herein, and suitable linking agents into a wellbore penetrating a subterranean formation and allowing the linking agents to link the linkable mineral particles so as to yield a hardened mass that comprises linked mineral particles.
  • the amount of linkable mineral particles described herein included in wellbore fluids may depend on, inter alia, the composition and amount of the optional cement particles, the composition and amount of the optional additional components (e.g., fillers described further herein), the composition of the mineral particles, the average diameter of the mineral particles, the diameter distribution of the mineral particles, the dimensions and volume of the set cement, and the like, and any combination thereof.
  • the degradable mineral particles described herein may be included in wellbore fluids (e.g. , settable compositions) suitable for use in conjunction with cementing operations described herein so as to allow for changing the permeability of the hardened mass produced therefrom .
  • degradation and/or dissolution of the mineral particles in a hardened mass may be achieved by exposing the hardened mass to an acidic treatment fluid, a treatment fluid comprising an acid source, a basic treatment fluid, an oxidizing treatment fluid, and the like.
  • Change of the permeability of a hardened mass may be useful, in some embodiments, for converting a substantially impermeable hardened mass (e.g., having a permeability less than about 10 "2 milliDarcy) that substantially blocks fluid flow to a permeable hardened mass that allow fluid to flow therethrough, for example, when alleviating zonal isolation from plugs and/or wellbore/subterranean formation separation from sheaths.
  • the ability to convert a hardened mass from substantially impermeable to permeable may, in some embodiments, advantageously eliminate the need to drill out plugs or perforate sheaths in order to restore a desired level of permeability.
  • wellbore fluids (e.g., settable compositions) suitable for use in conjunction with cementing operations may comprise a base fluid, mineral particles described herein capable of linking, and mineral particles capable of degradation .
  • wellbore fluids (e.g. , settable compositions) suitable for use in conjunction with cementing operations may comprise a base fluid, cement particles, and degradable mineral particles and optionally further comprise linkable mineral particles.
  • the degradable mineral particles may also be linkable.
  • the hardened mass after degradation and/or dissolution of the degradable mineral particles therein may have a permeability ranging from a lower limit of about 10 "1 milliDarcy ("m Da"), 1 m Da, or 10 m Da to an upper limit of about 1000 m Da, 100 m Da, or 10 m Da, and wherein the permeability may range from any lower limit to any upper limit and encompasses any subset therebetween .
  • m Da milliDarcy
  • the amount of degradable mineral particles described herein included in wellbore fluids (e.g. , settable compositions) suitable for use in conjunction with cementing operations so as to achieve hardened masses capable of changing permeability may depend on, inter alia, the composition and amount of the cement particles, the composition and amount of the optional additional components (e.g. , fillers described further herein), the composition of the degradable mineral particles, the average diameter of the degradable mineral particles, the diameter distribution of the degradable mineral particles, the dimensions of the set cement, and the like, and any combination thereof.
  • the cementing operations described herein may involve the recovery and recycling the mineral particles described herein .
  • the resultant fluid may be recovered and recycled according to any suitable recovery and recycling method described herein suitable for use in conjunction with the mineral particles utilized .
  • a spacer fluid or displacement fluid utilizing mineral particles described herein may be recovered and recycled according to any suitable recovery and recycling method described herein suitable for use in conjunction with the mineral particles utilized .
  • Base fluids suitable for use in conjunction with wellbore fluids suitable for use in conjunction with cementing operations may, in some embodiments, include any of the base fluids described herein in relation to wellbore fluids in general .
  • the base fluid may preferably comprise water.
  • wellbore fluids suitable for use in conjunction with cementing operations may be foamed as described herein in relation to wellbore fluids in general .
  • the base fluid may be present in the wellbore fluids suitable for use in conjunction with cementing operations in an amount sufficient to form a pumpable slurry.
  • the wellbore fluids suitable for use in conjunction with cementing operations may include base fluids in an amount ranging from a lower limit of about 30% by weight of cement ("bwoc"), 50% bwoc, or 100% bwoc to an upper limit of about 200% bwoc, 150% bwoc, or 100% bwoc, and wherein the amount may range from any lower limit to any upper limit and encompasses any subset therebetween .
  • the term "by weight of cement” refers to by weight of the cement and/or linkable mineral particles.
  • cement particles suitable for use in conjunction with the wellbore fluids and/or wellbore additives described herein may, in some embodiments, include, but are not limited to, hydraulic cements, Portland cement, gypsum cements, calcium phosphate cements, high alumina content cements, silica cements, high alkalinity cements, shale cements, acid/base cements, magnesia cements (e.g. , Sorel cements), fly ash cements, zeolite cement systems, cement kiln dust, slag cements, micro-fine cements, epoxies, bentonites, latexes, and the like, any derivative thereof, and any combination thereof.
  • hydraulic cements Portland cement, gypsum cements, calcium phosphate cements, high alumina content cements, silica cements, high alkalinity cements, shale cements, acid/base cements, magnesia cements (e.g. , Sorel cements),
  • the wellbore fluids and/or wellbore additives described herein suitable for use in conjunction with cementing operations may optionally further comprise additional components described herein in relation to wellbore fluids in general .
  • additional components may, in some embodiments, include, but are not limited to, filler particles, salts, weighting agents, inert solids, fluid loss control agents, emulsifiers, dispersion aids, corrosion inhibitors, emulsion thinners, emulsion thickeners, viscosifying agents, gelling agents, crosslinking agents, surfactants, cement particulates, proppants, gravel particulates, lost circulation materials, pH control additives, breakers, defoaming agents, biocides, stabilizers, scale inhibitors, gas hydrate inhibitors, oxidizers, reducers, friction reducers, clay stabilizing agents, set accelerators, set retarders, and combinations thereof.
  • the hardened masses, the wellbore fluids are hardened masses, the wellbore fluids
  • Filler particles may, in some embodiments, be useful in tailoring the mechanical properties of the final set cement, e.g. , some polymers and rubbers may allow for hardened masses that are more pliable than hardened masses without such polymers and rubbers.
  • filler particles suitable for use in conjunction with the wellbore fluids and/or wellbore additives described herein may, in some embodiments, include, but are not limited to, fly ash, fume silica, hydrated lime, pozzolanic materials, sand, barite, calcium carbonate, ground marble, iron oxide, manganese oxide, glass bead, crushed glass, crushed drill cutting, ground vehicle tire, crushed rock, ground asphalt, crushed concrete, crushed cement, ilmenite, hematite, silica flour, fume silica, fly ash, elastomers, polymers, diatomaceous earth, a highly swellable clay mineral, nitrogen, air, fibers, natural rubber, acrylate butadiene rubber, polyacrylate rubber, isoprene rubber, chloroprene rubber, butyl rubber, brominated butyl rubber, chlorinated butyl rubber, chlorinated polyethylene, neoprene rubber, styrene butadiene copolymer rubber
  • the wellbore fluids and/or wellbore additives described herein suitable for use in conjunction with cementing operations may include filler particles in an amount ranging from a lower limit of about 5% bwoc, 10% bwoc, 25% bwoc, or 50% bwoc to an upper limit of about 150% bwoc, 100% bwoc, or 50% bwoc, and wherein the amount may range from any lower limit to any upper limit and encompasses any subset therebetween .
  • the wellbore additives and/or the wellbore fluids described herein may be used in fracturing operations. Fracturing operations, in some embodiments, may involve introducing a first wellbore fluid (e.g. , pad fluid) into a subterranean formation at a pressures sufficient to create or extend at least one fracture in the subterranean formation and introducing a second wellbore fluid (e.g., a proppant slurry) into the subterranean formation so as to create a proppant pack in the at least one fracture.
  • a "proppant pack" refers to a collection of proppant particles in a fracture.
  • proppant mineral particles described herein may, in some embodiments, allow for tailoring a proppant slurry to have a desired density with proppant mineral particles also being useful as proppant particles, thereby reducing the need for additional weighting agent and/or traditional proppant particles (and associated costs) to achieve substantially the same result.
  • the proppant mineral particles described herein may optionally be used in fracturing operations in combination with traditional proppant particles.
  • Examples of traditional proppant particles that may be suitable for use in conjunction with the mineral particles described herein may, in some embodiments, include, but are not limited to, sand, glass materials, polymer materials, polytetrafluoroethylene materials, nut shell pieces, cured resinous particulates comprising nut shell pieces, seed shell pieces, cured resinous particulates comprising seed shell pieces, fruit pit pieces, cured resinous particulates comprising fruit pit pieces, wood, composite particulates (e.g.
  • particulates that may comprise a binder and a filler material wherein suitable filler materials include silica, fumed carbon, carbon black, graphite, mica, titanium dioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash, hollow glass microspheres, solid glass, and any combination thereof), and the like, and any combination thereof.
  • the proppant mineral particles described herein and/or traditional proppant particles used in conjunction with fracturing operations generally may have a median diameter ranging from a lower limit of about 350 microns, 500 microns, or 1 mm to an upper limit of about 15 mm, 10 mm, or 5 mm, and wherein the median diameter may range from any lower limit to any upper limit and encompasses any subset therebetween . It should be understood that fibrous materials, that may or may not be used to bear the pressure of a closed fracture, may be included in certain embodiments of the present invention .
  • the proppant mineral particles optionally in combination with the traditional proppant particles may be included in the proppant slurries in an amount in the range of from about 0.5 pounds per gallon ("ppg") to about 30 ppg of total proppant content by volume of the fracturing fluid, and encompass any subset therebetween .
  • the proppant mineral particles described herein may further be useful for imparting the properties and/or capabilities described herein in relation to wellbore fluids in general (e.g. , density, viscosity, sag control, degradation, and the like) to the wellbore fluids suitable for use in conjunction with fracturing operations.
  • Some embodiments may involve exploiting the degradability of some of the proppant mineral particles described herein to change the permeability of a proppant pack. For example, some embodiments may involve introducing a first wellbore fluid into at least a portion of a subterranean formation at a pressure sufficient to create or extend at least one fracture in the subterranean formation; introducing a second wellbore fluid that comprises a base fluid, a degradable mineral particles described herein suitable for use as a proppant, and proppant particles (e.g.
  • the mineral particles described herein may be less suitable for use as proppant particles and may be utilized in conjunction with fracturing operations so as to achieve any combination of the properties and/or capabilities described herein in relation to wellbore fluids in general (e.g. , density, viscosity, sag control, degradation, and the like) .
  • mineral particles comprising bismuth oxychloride may be useful in achieving a desired density and sag control for wellbore fluids suitable for use in conjunction with fracturing operations.
  • a proppant slurry may, in some embodiments, comprise a base fluid, traditional proppant particles, and mineral particles that have a suitable diameter distribution to mitigate sag of the traditional proppant particles (e.g. , a median diameter of about 2 microns or less) at a concentration to achieve a desired density of the wellbore fluid .
  • such mineral particles may, depending on the composition, also be degradable (e.g., manganese carbonate or tenorite), applicable as proppants (e.g. , manganese carbonate or awaruite), linkable (e.g. , manganese carbonate or tenorite), or any combination thereof, thereby allowing for other characteristics of the proppant slurry to be tailored for the conditions encountered in the wellbore and/or subterranean formation.
  • the fracturing operations described herein may involve the recovery and recycling the mineral particles described herein.
  • the resultant fluid may be recovered and recycled according to any suitable recovery and recycling method described herein suitable for use in conjunction with the mineral particles utilized.
  • Base fluids suitable for use in conjunction with wellbore fluids described herein suitable for use in conjunction with fracturing operations may, in some embodiments, include any of the base fluids described above in relation to wellbore fluids in general. Further, in some embodiments, wellbore fluids described herein suitable for use in conjunction with fracturing operations may be foamed as described above in relation to wellbore fluids in general .
  • the wellbore fluids and/or wellbore additives described herein suitable for use in conjunction with fracturing operations may optionally further comprise additional components described herein in relation to wellbore fluids in general .
  • additional components may, in some embodiments, include, but are not limited to, filler particles, salts, weighting agents, inert solids, fluid loss control agents, emulsifiers, dispersion aids, corrosion inhibitors, emulsion thinners, emulsion thickeners, viscosifying agents, gelling agents, crosslinking agents, surfactants, cement particulates, proppants, gravel particulates, lost circulation materials, pH control additives, breakers, defoaming agents, biocides, stabilizers, scale inhibitors, gas hydrate inhibitors, oxidizers, reducers, friction reducers, clay stabilizing agents, set accelerators, set retarders, and combinations thereof.
  • the mineral particles described herein may be useful in fluid flow control between a wellbore and the surrounding subterranean formation. Controlling the flow of fluids between the wellbore and the subterranean formation can be especially important for, inter alia, maintaining the proper wellbore pressure (e.g. , to mitigate blowouts), minimize loss of wellbore fluids (often expensive wellbore fluids) into the subterranean formation, ensure proper placement of a wellbore fluids (e.g., fluids comprising proppants), and the like.
  • a wellbore fluids e.g., fluids comprising proppants
  • fluid flow control may be achieved by at least one of the following mechanisms: bridging a fracture, reducing or blocking formation permeability, providing fluid loss control, sealing a rock surface, sealing a thief zone, enabling fluid diversion, plugging a void, controlling water production, and any combination thereof within the subterranean formation.
  • pores, voids, high-permeability porosity, and the like may be found in a subterranean formation, e.g.
  • Fluid loss may be problematic in any number of subterranean operations, including drilling operations, fracturing operations, acidizing operations, gravel-packing operations, wellbore clean-out operations, produced water reduction or elimination, and the like.
  • fracturing operations for example, fluid loss into the formation may result in a reduction in fluid efficiency, such that the fracturing fluid cannot propagate fracture formation as desired .
  • the wellbore fluids described herein may, in some embodiments, lower the volume of a filtrate that passes through a filter medium. That is, the wellbore fluids described herein (e.g.
  • the mineral particles, the mineral particles in combination with additional fluid components, and/or linked mineral particles may block the pore throats and spaces that would otherwise allow a fluid to leak out of a desired zone and into an undesired zone.
  • the wellbore fluids described herein e.g. , the mineral particles, the mineral particles in combination with additional fluid components, and/or linked mineral particles
  • Fluid diversion is a similar approach to fluid loss control but strives for a somewhat different approach where a portion of the subterranean formation is sealed off or rendered less permeable.
  • a volume of a wellbore fluid may be pumped into the high permeability portion of the formation to partially or completely seal off that portion from subsequent fluid penetration .
  • a wellbore fluid When being placed, a wellbore fluid will flow most readily into the portion of the formation having the largest pores, fissures, or vugs and, in some embodiments, deposit the mineral particles therein, until that portion is bridged and sealed, thus diverting the remaining and/or subsequent fluid to the next most permeable portion of the formation .
  • Some embodiments may involve introducing a first wellbore fluid comprising the mineral particles described herein into a subterranean formation; allowing the first wellbore fluid to penetrate into a portion of the subterranean formation in a sufficient amount so as to provide fluid flow control (e.g., sealing, bridging, plugging, diversion, and the like) within a first portion of the subterranean formation; and introducing a second wellbore fluid (e.g. , a pad fluid, a proppant slurry, a cementing fluid, or the like) into the subterranean formation such that the first wellbore fluid at least substantially blocks the second wellbore fluid from entering the first portion of the subterranean formation (e.g. , an area of fluid flow control that comprises the mineral particles).
  • fluid flow control e.g., sealing, bridging, plugging, diversion, and the like
  • Providing fluid flow control may, in some embodiments, be achieved with high density fluids (e.g. , the first wellbore fluid having a higher density than the second wellbore fluid), viscosifying fluids optionally through the mineral particle linking (e.g., the first wellbore fluid having a higher viscosity than the second wellbore fluid), forming hardened masses (e.g. , with the first wellbore fluid), and any combination thereof.
  • high density fluids e.g. , the first wellbore fluid having a higher density than the second wellbore fluid
  • viscosifying fluids optionally through the mineral particle linking e.g., the first wellbore fluid having a higher viscosity than the second wellbore fluid
  • forming hardened masses e.g. , with the first wellbore fluid
  • the mineral particles described herein may be utilized in the first and/or the second wellbore fluids so as to achieve conditions that allow for fluid flow control operations.
  • the first wellbore fluid may comprise first mineral particles (e.g. , comprising awaruite and/or tenorite) in a sufficient amount to yield the desired density that is higher than the second wellbore fluid .
  • the second wellbore fluid may be useful in other operations like fracturing operations or cementing operations.
  • the mineral particles described herein may be utilized for achieving a desired viscosity so as to allow for fluid flow control operations.
  • the mineral particles described herein suitable for use in conjunction with fluid flow control operations may be linked before, after, and/or during placement in the portion of the subterranean formation where fluid flow control is desired .
  • some embodiments may involve a wellbore fluid comprising the mineral particles described herein may be introduced into a subterranean formation so as to penetrate a portion of the subterranean formation; and contacting the wellbore fluid with a linking agent so as to increase the viscosity of the wellbore fluid .
  • contacting the wellbore fluid with a linking agent may yield a hardened mass as described further herein .
  • the location providing fluid flow control may be treated so as to increase fluid flow therethrough .
  • some embodiments may involve treating an area of fluid flow control within a subterranean formation with a wellbore fluid comprising a degradation agent so as to degrade and/or dissolve at least a portion of the mineral particles described herein in the area of fluid flow control .
  • some embodiments may involve introducing a first wellbore fluid comprising the mineral particles described herein capable of linking and linking agents into a wellbore so as to incorporate the first wellbore fluid into a gravel pack within the wellbore; introducing a second wellbore fluid into the wellbore such that the first wellbore fluid at least substantially blocks the second wellbore fluid from passing through the gravel pack; and contacting the first wellbore fluid with a third wellbore fluid comprising a degradation agent so as to at least partially degrade the mineral particles, thereby increasing the permeability of the gravel pack.
  • the fluid flow control operations described herein may involve the recovery and recycling the mineral particles described herein .
  • the resultant fluid may be recovered and recycled according to any suitable recovery and recycling method described herein suitable for use in conjunction with the mineral particles utilized .
  • Base fluids suitable for use in conjunction with wellbore fluids suitable for use in conjunction with fluid flow control operations may, in some embodiments, include any of the base fluids described herein in relation to wellbore fluids in general .
  • wellbore fluids suitable for use in conjunction with fluid flow control operations may be foamed as described herein in relation to wellbore fluids in general .
  • the wellbore fluids and/or wellbore additives described herein suitable for use in conjunction with fluid flow control operations may optionally further comprise additional components described herein in relation to wellbore fluids in general .
  • additional components may, in some embodiments, include, but are not limited to, filler particles, salts, weighting agents, inert solids, fluid loss control agents, emulsifiers, dispersion aids, corrosion inhibitors, emulsion thinners, emulsion thickeners, viscosifying agents, gelling agents, crosslinking agents, surfactants, cement particulates, proppants, gravel particulates, lost circulation materials, pH control additives, breakers, defoaming agents, biocides, stabilizers, scale inhibitors, gas hydrate inhibitors, oxidizers, reducers, friction reducers, clay stabilizing agents, set accelerators, set retarders, and combinations thereof. Ill.d. Drilling
  • the mineral particles described herein may be useful in drilling operations. Some embodiments may involve drilling a wellbore penetrating a subterranean formation with a wellbore fluid that comprises mineral particles described herein . In some embodiments, the mineral particles described herein may be useful in at least one of: suspending wellbore cuttings (e.g., by contributing to the fluid viscosity and/or sag control), maintaining wellbore pressure (e.g. , by contributing to sag control), incorporating into filter cakes that provide fluid loss control, and the like. Further, mineral particles described herein may be chosen to mitigate abrasion of wellbore tools utilized during drilling .
  • Some embodiments may involve forming a filter cake that comprises mineral particles described herein (optionally linked) in a wellbore so as to provide fluid loss control . Some embodiments may involve cleaning up the filter cake by contacting the filter cake with a degradation agent so as to dissolve degradable mineral particles incorporated therein . [0155] In some embodiments, the fluid flow control operations described herein may involve the recovery and recycling the mineral particles described herein . For example, after degradation of an area of fluid loss control, the resultant fluid may be recovered and recycled according to any suitable recovery and recycling method described herein suitable for use in conjunction with the mineral particles utilized .
  • Base fluids suitable for use in conjunction with wellbore fluids suitable for use in conjunction with drilling operations may, in some embodiments, include any of the base fluids described herein in relation to wellbore fluids in general .
  • wellbore fluids suitable for use in conjunction with drilling operations may be foamed as described herein in relation to wellbore fluids in general .
  • the wellbore fluids and/or wellbore additives described herein suitable for use in conjunction with drilling operations may optionally further comprise additional components described herein in relation to wellbore fluids in general .
  • additional components may, in some embodiments, include, but are not limited to, filler particles, salts, weighting agents, inert solids, fluid loss control agents, emulsifiers, dispersion aids, corrosion inhibitors, emulsion thinners, emulsion thickeners, viscosifying agents, gelling agents, crosslinking agents, surfactants, cement particulates, proppants, gravel particulates, lost circulation materials, pH control additives, breakers, defoaming agents, biocides, stabilizers, scale inhibitors, gas hydrate inhibitors, oxidizers, reducers, friction reducers, clay stabilizing agents, set accelerators, set retarders, and combinations thereof. Ill.e. On-The-Fly
  • the mineral particles described herein may allow for on-the-fly modifications of wellbore fluid properties and capabilities.
  • the conditions encountered in the wellbore and/or subterranean formation may necessitate changing the properties and/or characteristics of the wellbore fluid on-the-fly (e.g. , density, viscosity, level of sag, and the like) .
  • On-the-fly modifications may, in some embodiments, include, but are not limited to, changing the concentration of the mineral particles in the wellbore fluid, changing the type of mineral particles in the wellbore fluid (e.g.
  • a wellbore fluid utilizing two mineral particles with different specific gravities may increase the relative concentration of the higher specific gravity particle to achieve a higher density fluid .
  • Adjusting the density of the wellbore fluid may, in some embodiments, be useful when drilling a wellbore so as to maintain the bottom hole pressure at a level that mitigates damage to the subterranean formation (e.g. , minimizes fracturing and leak-off) while maintaining a high enough pressure to minimize subterranean fluids from entering the wellbore.
  • the density of the wellbore fluid can be reduced on-the-fly with the addition of a degradation agent to degrade a mineral particle (e.g. , tenorite, awaruite, rhodochrosite, or the like) . Similar to above such a change may be used to mitigate wellbore damage while drilling .
  • a degradation agent e.g. , tenorite, awaruite, rhodochrosite, or the like. Similar to above such a change may be used to mitigate wellbore damage while drilling .
  • the viscosity of a wellbore fluid utilizing a linkable mineral particle may be changed on-the-fly with the addition of linking agents for an increase or the addition of a degradation agent for a decrease.
  • the viscosity of the wellbore fluid may, at least in part, assist in suspending cuttings and bringing them to the surface.
  • the on-the-fly modification of the viscosity may assist in enhancing the efficacy while minimizing the energy use and cost associated with drilling .
  • One embodiment disclosed herein includes a method that comprises circulating a wellbore fluid with a first density of about 7 ppg to about 50 ppg in a wellbore penetrating a subterranean formation, the wellbore fluid comprising a base fluid, a plurality of first mineral particles, and a plurality of second mineral particles such that the first mineral particles and the second mineral particles are present in a first relative ratio, and the first mineral particles and the second mineral particles have a multiparticle specific gravity of about 3 to about 20; and changing the first relative ratio to a second relative ratio on-the-fly so as to yield the wellbore fluid with a second density.
  • Some embodiments may further include at least one element of: Element 1 : wherein the first mineral particles in combination with the second mineral particles have a multi-modal diameter distribution; Element 2 : wherein the first mineral particles in combination with the second mineral particles have a diameter distribution that has at least one mode with a standard deviation of about 2% or less of a peak diameter of the mode; Element 3 : wherein the first mineral particles and/or the second mineral particles have a shape selected from the group consisting of spherical, ovular, substantially spherical, substantially ovular, discus, platelet, flake, ligamental, acicular, spiked with a substantially spherical or ovular shape, spiked with a discus or platelet shape, fibrous, rod-like, polygonal, faceted, and any hybrid thereof; Element 4: wherein the first density is less than the second density; Element 5 : wherein the first mineral particles and/or the second mineral particles have a coating; Element 6: wherein the first mineral
  • Exemplary combinations may include, but are not limited to : Element 1 in combination with Element 2 and optionally in further combination with at least one of Elements 3-6; Element 1 in combination with at least one of Elements 3-6; Element 2 in combination with at least one of Elements 3-6; at least one of Elements 7-10 in combination with any of the foregoing; and so on.
  • One embodiment disclosed herein includes a method that comprises circulating a wellbore fluid with a density of about 7 ppg to about 50 ppg in a wellbore penetrating a subterranean formation, the wellbore fluid comprising a base fluid and a plurality of linkable mineral particles, and the wellbore fluid having first viscosity; and introducing a linking agent into the wellbore fluid on-the-fly in response to a condition encountered in the wellbore during circulating so as to yield a second viscosity that is greater than the first viscosity of the wellbore fluid .
  • Some embodiments may further include at least one element of: Element 1 : wherein the linkable mineral particles are formed by precipitation; Element 2 : wherein the linkable mineral particles have a diameter distribution that has at least one mode with a standard deviation of about 2% or less of a peak diameter of the mode; Element 3 : wherein the linkable mineral particles have a shape selected from the group consisting of spherical, ovular, substantially spherical, substantially ovular, discus, platelet, flake, ligamental, acicular, spiked with a substantially spherical or ovular shape, spiked with a discus or platelet shape, fibrous, rod-like, polygonal, faceted, and any hybrid thereof; Element 4: wherein the linkable mineral particles have a coating; Element 5 : the method further comprising drilling a wellbore with the wellbore fluid; Element 6: the method further comprising producing hydrocarbons from the subterranean formation; Element 7 : the method further
  • Exemplary combinations may include, but are not limited to : Element 1 in combination with Element 2 and optionally in further combination with at least one of Elements 3-4; Element 1 in combination with at least one of Elements 3-4; Element 2 in combination with at least one of Elements 3-4; at least one of Elements 5-8 in combination with any of the foregoing; and so on.
  • One embodiment disclosed herein includes a method that comprises circulating a wellbore fluid with a density of about 7 ppg to about 50 ppg in a wellbore penetrating a subterranean formation, the wellbore fluid comprising a base fluid and a plurality of mineral particles, and the wellbore fluid having first viscosity; and introducing a degradation agent into the wellbore fluid on-the-fly in response to a condition encountered in the wellbore during circulating so as to yield a second viscosity that is less than the first viscosity of the wellbore fluid.
  • Some embodiments may further include at least one element of: Element 1 : wherein the mineral particles are formed by precipitation; Element 2 : wherein the mineral particles have a diameter distribution that has at least one mode with a standard deviation of about 2% or less of a peak diameter of the mode; Element 3 : wherein the mineral particles have a shape selected from the group consisting of spherical, ovular, substantially spherical, substantially ovular, discus, platelet, flake, ligamental, acicular, spiked with a substantially spherical or ovular shape, spiked with a discus or platelet shape, fibrous, rod-like, polygonal, faceted, and any hybrid thereof; Element 4 : wherein the mineral particles have a coating; Element 5 : wherein the mineral particle comprises at least one selected from the group consisting of AI203, AI2Si05, BaC03, BaO, BeO, (BiO)2C03, Bi03, ⁇ 203, CaO, Ca
  • Exemplary combinations may include, but are not limited to : Element 1 in combination with Element 2 and optionally in further combination with at least one of Elements 3-5; Element 1 in combination with at least one of Elements 3- 5; Element 2 in combination with at least one of Elements 3-5; at least one of Elements 6-9 in combination with any of the foregoing ; and so on .
  • the exemplary mineral particles and related fluids disclosed herein may directly or indirectly affect one or more components or pieces of equipment associated with the preparation, delivery, recapture, recycling, reuse, and/or disposal of the disclosed mineral particles and related fluids.
  • the disclosed mineral particles and related fluids may directly or indirectly affect one or more components or pieces of equipment associated with an exemplary wellbore drilling assembly 300, according to one or more embodiments.
  • Figure 3 generally depicts a land-based drilling assembly, those skilled in the art will readily recognize that the principles described herein are equally applicable to subsea drilling operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure.
  • the drilling assembly 300 may include a drilling platform 302 that supports a derrick 304 having a traveling block 306 for raising and lowering a drill string 308.
  • the drill string 308 may include, but is not limited to, drill pipe and coiled tubing, as generally known to those skilled in the art.
  • a kelly 310 supports the drill string 308 as it is lowered through a rotary table 312.
  • a drill bit 314 is attached to the distal end of the drill string 308 and is driven either by a downhole motor and/or via rotation of the drill string 308 from the well surface. As the bit 314 rotates, it creates a wellbore 316 that penetrates various subterranean formations 318.
  • a pump 320 (e.g. , a mud pump) circulates drilling fluid 322 (e.g. , a drilling fluid comprising the mineral particles described herein) through a feed pipe 324 and to the kelly 310, which conveys the drilling fluid 322 downhole through the interior of the drill string 308 and through one or more orifices in the drill bit 314.
  • the drilling fluid 322 is then circulated back to the surface via an annulus 326 defined between the drill string 308 and the walls of the wellbore 316.
  • the recirculated or spent drilling fluid 322 exits the annulus 326 and may be conveyed to one or more fluid processing unit(s) 328 via an interconnecting flow line 330.
  • a "cleaned" drilling fluid 322 is deposited into a nearby retention pit 332 (i. e. , a mud pit) . While illustrated as being arranged at the outlet of the wellbore 316 via the annulus 326, those skilled in the art will readily appreciate that the fluid processing unit(s) 328 may be arranged at any other location in the drilling assembly 300 to facilitate its proper function, without departing from the scope of the disclosure.
  • One or more of the disclosed mineral particles may be added to the drilling fluid 322 via a mixing hopper 334 communicably coupled to or otherwise in fluid communication with the retention pit 332.
  • the mixing hopper 334 may include, but is not limited to, mixers and related mixing equipment known to those skilled in the art.
  • the disclosed mineral particles may be added to the drilling fluid 322 at any other location in the drilling assembly 300.
  • the retention put 332 may be representative of one or more fluid storage facilities and/or units where the disclosed mineral particles may be stored, reconditioned, and/or regulated until added to the drilling fluid 322.
  • the disclosed mineral particles and related fluids may directly or indirectly affect the components and equipment of the drilling assembly 300.
  • the disclosed mineral particles and related fluids may directly or indirectly affect the fluid processing unit(s) 328 which may include, but is not limited to, one or more of a shaker (e.g. , shale shaker), a centrifuge, a hydrocyclone, a separator (including magnetic and electrical separators), a desilter, a desander, a separator, a filter (e.g. , diatomaceous earth filters), a heat exchanger, any fluid reclamation equipment.
  • the fluid processing unit(s) 328 may further include one or more sensors, gauges, pumps, compressors, and the like used to store, monitor, regulate, and/or recondition the exemplary mineral particles and related fluids.
  • the disclosed mineral particles and related fluids may directly or indirectly affect the pump 320, which representatively includes any conduits, pipelines, trucks, tubulars, and/or pipes used to fluidically convey the mineral particles and related fluids downhole, with pumps, compressors, or motors (e.g. , topside or downhole) used to drive the mineral particles and related fluids into motion, any valves or related joints used to regulate the pressure or flow rate of the mineral particles and related fluids, and any sensors (i.e. , pressure, temperature, flow rate, etc.), gauges, and/or combinations thereof, and the like.
  • the disclosed mineral particles and related fluids may also directly or indirectly affect the mixing hopper 334 and the retention pit 332 and their assorted va nations.
  • the disclosed mineral particles and related fluids may also directly or indirectly affect the various downhole equipment and tools that may come into contact with the mineral particles and related fluids such as, but not limited to, the drill string 308, any floats, drill collars, mud motors, downhole motors and/or pumps associated with the drill string 308, and any MWD/LWD tools and related telemetry equipment, sensors or distributed sensors associated with the drill string 308.
  • the disclosed mineral particles and related fluids may also directly or indirectly affect any downhole heat exchangers, valves and corresponding actuation devices, tool seals, packers and other wellbore isolation devices or components, and the like associated with the wellbore 316.
  • the disclosed mineral particles and related fluids may also directly or indirectly affect the drill bit 314, which may include, but is not limited to, roller cone bits, PDC bits, natural diamond bits, any hole openers, reamers, coring bits, etc.
  • the disclosed mineral particles and related fluids may also directly or indirectly affect any transport or delivery equipment used to convey the mineral particles and related fluids to the drilling assembly 300 such as, for example, any transport vessels, conduits, pipelines, trucks, tubulars, and/or pipes used to fluidically move the mineral particles and related fluids from one location to another, any pumps, compressors, or motors used to drive the mineral particles and related fluids into motion, any valves or related joints used to regulate the pressure or flow rate of the mineral particles and related fluids, and any sensors (i. e. , pressure and temperature), gauges, and/or combinations thereof, and the like.
  • any transport or delivery equipment used to convey the mineral particles and related fluids to the drilling assembly 300 such as, for example, any transport vessels, conduits, pipelines, trucks, tubulars, and/or pipes used to fluidically move the mineral particles and related fluids from one location to another, any pumps, compressors, or motors used to drive the mineral particles and related fluids into motion, any valves or related joints used to regulate the pressure or flow rate of
  • drilling assembly 300 While not specifically illustrated herein, one of ordinary skill in the art should recognize the modifications to drilling assembly 300 to allow for performing other operations described herein including, but not limited to, cementing operations, fracturing operations, and fluid flow control operations.
  • a wellbore drilling assembly may comprise a pump in fluid communication with a wellbore via a feed pipe; and a wellbore fluid described herein disposed in at least one selected from the group consisting of the pump, the feed pipe, the wellbore, and any combination thereof.
  • a wellbore drilling assembly may comprise a pump in fluid communication with a wellbore via a feed pipe; a drill string with drill bit attached to the distal end of the drill string; and a wellbore fluid described herein in contact with the drill bit.
  • a wellbore drilling assembly may comprise a pump capable of introducing a fluid into a wellbore via a feed pipe; a fluid processing unit capable of receiving the fluid from a wellbore via an interconnecting flow line; and a wellbore fluid described herein disposed in at least one selected from the group consisting of the pump, the feed pipe, the wellbore, the interconnecting flow line, the fluid processing unit, and any combination thereof.
  • a wellbore drilling assembly may comprise a pump capable of introducing a fluid into a wellbore via a feed pipe; a mixing hopper upstream of the pump; and a wellbore fluid described herein disposed in at least one selected from the group consisting of the pump, the feed pipe, the wellbore, and any combination thereof.
  • the mixing hopper may be useful, in some embodiments, for implementing on-the-fly changes to the wellbore fluids described herein .
  • suitable wellbore fluids described herein may include, but are not limited to,
  • a wellbore fluid comprising a base fluid, a plurality of first mineral particles, and a plurality of second mineral particles such that and the first mineral particles and the second mineral particles have a multiparticle specific gravity of about 3 to about 20;
  • any of the wellbore fluids described in Embodiments A-C optionally including at least one of Elements 1-14 relating to the wellbore fluid.
  • compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit to an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values.

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GB1516453.6A GB2536516A (en) 2013-05-21 2014-03-03 Wellbore fluids comprising mineral particles and methods relating thereto
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US20100059224A1 (en) * 2005-03-01 2010-03-11 Carbo Ceramics Inc. Methods for producing sintered particles from a slurry of an alumina-containing raw material
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