WO2014102388A2

WO2014102388A2 - Shale hydration inhibitor complex for aqueous wellbore fluids

Info

Publication number: WO2014102388A2
Application number: PCT/EP2013/078165
Authority: WO
Inventors: Stephen Cliffe; Catriona SELLICK
Original assignee: M-I Drilling Fluids Uk Limited
Priority date: 2012-12-31
Filing date: 2013-12-31
Publication date: 2014-07-03
Also published as: GB2523938A; GB201511219D0; WO2014102388A3

Abstract

Wellbore fluids containing stabilizing complexes capable of controlling hydration in swellable formations such as shale- and clay-containing formations and methods of using same are provided. In one aspect, embodiments disclosed herein relate to wellbore fluids that include an aqueous base fluid; and a stabilizing complex, wherein the stabilizing complex is prepared from the reaction of an alkali metal aluminate salt and one or more selected from a group that includes phosphoric acid, a phosphate salt, and an amine -phosphoric acid mixture. In another aspect the stabilizing complex may be formed from the reaction of a metal oxide and one or more selected from a group that includes phosphoric acid, phosphate salts, and amine-phosphoric acid mixtures.

Description

SHALE HYDRATION INHIBITOR COMPLEX FOR AQUEOUS

WELLBORE FLUIDS

CROSS -REFERENCE TO RELATED APPLICATIONS

[0001] This application claims the priority under 35 U.S.C. § 1 19(e) to U.S.

Provisional Application Serial No. 61/747,763 filed December 31 , 2012, which is herein incorporated by reference in its entirety.

BACKGROUND

[0002] To facilitate the drilling of a well, fluid is circulated through the drill string, out the bit and upward in an annular area between the drill string and the wall of the borehole. Common uses for well fluids include: lubrication and cooling of drill bit cutting surfaces while drilling generally or drilling-in (i.e., drilling in a targeted petroliferous formation), transportation of "cuttings" (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation fluid pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, fracturing the formation in the vicinity of the well, displacing the fluid within the well with another fluid, cleaning the well, testing the well, transmitting hydraulic horsepower to the drill bit, fluid used for emplacing a packer, abandoning the well or preparing the well for abandonment, and otherwise treating the well or the formation.

[0003] Drilling fluids may be classified according to their base material. The selection of the type of drilling fluid to be used in a drilling application involves a careful balance of both the good and bad characteristics of the drilling fluids in the particular application and the type of well to be drilled. In oil-based fluids, solid particles are suspended in oil (the continuous phase), and water or brine may be emulsified with the oil. In water-based fluids, solid particles are suspended in water or brine (continuous phase) including solid particles such as 1) clays and organic colloids added to provide necessary viscosity and filtration properties; 2) heavy minerals whose function is to increase the drilling fluid's density; and 3) formation solids that become dispersed in the drilling fluid during the drilling operation. Historically, water based drilling fluids have been used to drill a majority of wells. Their lower cost and better environment acceptance as compared to oil based drilling fluids continue to make them the first option in drilling operations. However, as mentioned above, the selection of a fluid frequently may depend on the type of formation through which the well is being drilled. Where the formation solids are clay minerals that swell, the presence of either type of formation solids in the drilling fluid can greatly increase drilling time and costs.

[0004] The types of subterranean formations, intersected by a well, which may be at least partly composed of clays, including shales, mudstones, siltstones, and claystones. In penetrating through such formations, many problems may be encountered including bit balling, swelling or sloughing of the wellbore, stuck pipe, and dispersion of drill cuttings. This may be particularly true when drilling with a water-based fluid due to the high reactivity of clay in an aqueous environment.

[0005] Clay minerals are generally crystalline in nature. The structure of a clay's crystals determines its properties. Clays may have a flaky, mica-type structure. Clay flakes are made up of a number of crystal platelets stacked face-to-face. Each platelet is called a unit layer, and the surfaces of the unit layer are called basal surfaces. Each unit layer is composed of multiple sheets, which may include octahedral sheets and tetrahedral sheets. Octahedral sheets are composed of either aluminum or magnesium atoms octahedrally coordinated with the oxygen atoms of hydro xyls, whereas tetrahedral sheets consist of silicon atoms tetrahedrally coordinated with oxygen atoms.

[0006] Sheets within a unit layer link together by sharing oxygen atoms. When this linking occurs between one octahedral and one tetrahedral sheet, one basal surface consists of exposed oxygen atoms while the other basal surface has exposed hydro xyls. It is also quite common for two tetrahedral sheets to bond with one octahedral sheet by sharing oxygen atoms. The resulting structure, known as the Hoffman structure, has an octahedral sheet that is sandwiched between the two tetrahedral sheets. As a result, both basal surfaces in a Hoffman structure are composed of exposed oxygen atoms. The unit layers stack together face-to-face and are held in place by weak attractive forces. The distance between corresponding planes in adjacent unit layers is called the d-spacing. A clay crystal structure with a unit layer consisting of three sheets often has a d-spacing of about 9.5x10^"7 mm.

[0007] In clay mineral crystals, atoms having different valences commonly will be positioned within the sheets of the structure to create a negative potential at the crystal surface, which causes cations to be adsorbed thereto. These adsorbed cations are called exchangeable cations because they may chemically trade places with other cations when the clay crystal is suspended in water. In addition, ions may also be adsorbed on the clay crystal edges and exchange with other ions in the water.

[0008] The type of substitutions occurring within the clay crystal structure and the exchangeable cations adsorbed on the crystal surface greatly affect clay swelling, a property of primary importance in the drilling fluid industry. Clay swelling is a phenomenon in which water molecules surround a clay crystal structure and position themselves to increase the structure's d-spacing thus resulting in an increase in volume. Two types of swelling may occur: surface hydration and osmotic swelling.

[0009] Surface hydration is one type of swelling in which water molecules are adsorbed on crystal surfaces. Hydrogen bonding holds a layer of water molecules to the oxygen atoms exposed on the crystal surfaces. Subsequent layers of water molecules align to form a quasi-crystalline structure between unit layers, which results in an increased d-spacing. Virtually all types of clays swell in this manner.

[0010] Osmotic swelling is a second type of swelling. Where the concentration of cations between unit layers in a clay mineral is higher than the cation concentration in the surrounding water, water is osmotically drawn between the unit layers and the d-spacing is increased. Osmotic swelling results in larger overall volume increases than surface hydration. However, only certain clays, like sodium montmorillonite, swell in this manner.

[0011] Exchangeable cations found in clay minerals are reported to have an impact on the amount of swelling that takes place. The exchangeable cations compete with water molecules for the available reactive sites in the clay structure. Generally cations with high valences are more strongly adsorbed than ones with low valences. Thus, clays with low valence exchangeable cations will swell more than clays whose exchangeable cations have high valences.

[0012] Clay swelling during the drilling of a subterranean well can have a tremendous adverse impact on drilling operations. The overall increase in bulk volume accompanying clay swelling impedes removal of cuttings from beneath the drill bit, increases friction between the drill string and the sides of the borehole, and inhibits formation of the thin filter cake that seals formations. Clay swelling can also create other drilling problems such as loss of circulation or stuck pipe that slow drilling and increase drilling costs. Thus, given the frequency in which gumbo shale is encountered in drilling subterranean wells, the development of a substance and method for reducing clay swelling remains a continuing challenge in the oil and gas exploration industry.

[0013] One method to reduce clay swelling is to use salts in drilling fluids. Salts generally reduce the swelling of clays; however, salts can flocculate the clays resulting in both high fluid losses and an almost complete loss of thixotropy. Further, increasing salinity often decreases the functional characteristics of drilling fluid additives.

[0014] Another method for controlling clay swelling is to use organic shale inhibitor molecules in drilling fluids. It is believed that the organic shale inhibitor molecules are absorbed on the surfaces of clays with the added organic shale inhibitor completing with water molecules for clay reactive sites and thus serve to reduce clay swelling. Organic shale inhibitors can be cationic, anionic, or nonionic. Cationic organic shale inhibitors dissociate into organic cations and inorganic anions, while anionic organic shale inhibitors dissociate into inorganic cationic and organic anions. Nonionic shale inhibitor molecules do not dissociate.

SUMMARY

[0015] In one aspect, embodiments disclosed herein relate to wellbore fluids that include an aqueous base fluid; and a stabilizing complex, wherein the stabilizing complex is prepared from the reaction of an alkali metal aluminate salt and one or more selected from a group that includes phosphoric acid, a phosphate salt, and an amine-phosphoric acid mixture.

[0016] In another aspect, embodiments disclosed herein relate to methods of preparing wellbore fluids, the method including: providing an aqueous base fluid; adding an aluminate salt; adding one or more selected from a group that includes of phosphoric acid and a monobasic phosphate salt; adjusting the pH to be within the range of 7 to 13.

[0017] In another aspect, embodiments disclosed herein relate to drilling methods that include: circulating a wellbore fluid into a wellbore, the wellbore fluid including: an aqueous base fluid; and a stabilizing complex, wherein the stabilizing complex is prepared from the reaction of an alkali metal aluminate salt and one or more selected from a group that includes a phosphoric acid and a monobasic phosphate salt.

[0018] In yet another aspect, embodiments disclosed herein relate to drilling methods that include: circulating a wellbore fluid into a wellbore, the wellbore fluid including: an aqueous base fluid; and an amine, wherein the amine has the general formula:

where R¹, R², and R³ are each the same or different and are selected from a group that includes hydrogen, alkyl, haloalkyl, alkenyl, alkoxy, and alkoxy ether.

[0019] In yet another aspect, embodiments disclosed herein relate to drilling methods that include: an aqueous base fluid; an alkali metal silicate; and an amine, wherein the amine has the general formula:

1 2 3

where R , R , and R are each the same or different and are selected from a group consisting of hydrogen, alkyl, haloalkyl, alkenyl, alkoxy, and alkoxy ether.

[0020] In one aspect, embodiments disclosed herein relate to wellbore fluids that include an aqueous base fluid; and a stabilizing complex, wherein the stabilizing complex prepared from the reaction of a metal oxide and one or more selected from a group consisting of a phosphoric acid, a phosphate salt, and an amine -phosphoric acid mixture.

[0021] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

[0022]

BRIEF DESCRIPTION OF DRAWINGS

[0023] Figure 1 shows the change in percent hydration of Oxford shales as a function of added phosphate salt according to embodiments disclosed herein.

[0024] Figure 2 shows the percent recovery of wellbore fluid from a shale formation as a function of added aluminate for various wellbore fluid formulations according to embodiments disclosed herein.

[0025] Figure 3 shows the change in percent hydration of an Arne shale formation as a function of added aluminate according to embodiments disclosed herein.

DETAILED DESCRIPTION

[0026] In one aspect, embodiments disclosed herein relate to a water-based wellbore fluid for use in drilling wells through a formation containing shale that swells in the presence of water. The wellbore fluids of the present disclosure may be formulated to include an aqueous continuous phase, a stabilizing agent, and, in some embodiments, an amine. In other embodiments, the shale hydration inhibiting wellbore fluid may contain an aqueous base fluid and an amine.

[0027] While most of the terms used herein will be recognizable to those of skill in the art, the following definitions are nevertheless put forth to aid in the understanding of the present disclosure. It should be understood, however, that when not explicitly defined, terms should be interpreted as adopting a meaning presently accepted by those of skill in the art.

[0028] The term "alkyl" as used herein, unless otherwise specified, refers to a saturated straight chain, branched or cyclic hydrocarbon group of 1 to 24 or 1-12 carbon atoms in particular embodiments. The hydrocarbon group may be selected from, for example, methyl, ethyl, n-propyl, isopropyl, n-butyl, isobutyl, sec-butyl, t-butyl, pentyl, cyclopentyl, isopentyl, neopentyl, hexyl, isohexyl, cyclohexyl, 3-methylpentyl, 2,2- dimethylbutyl, and 2,3-dimethylbutyl. The term "lower alkyl" intends an alkyl group of one to six carbon atoms, and includes, for example, methyl, ethyl, n-propyl, isopropyl, n- butyl, isobutyl, t-butyl, pentyl, cyclopentyl, isopentyl, neopentyl, hexyl, isohexyl, cyclohexyl, 3-methylpentyl, 2,2-dimethylbutyl, and 2,3-dimethylbutyl. The term "cycloalkyl" refers to cyclic alkyl groups such as cyclopropyl, cyclobutyl, cyclopentyl, cyclohexyl, cycloheptyl and cyclooctyl.

[0029] Moreover, the term "alkyl" includes "modified alkyl", which references an alkyl group having from one to twenty-four carbon atoms, and further having additional groups, such as one or more linkages selected from ether-, thio-, amino-, phospho-, oxo-, ester-, and amido-, and/or being substituted with one or more additional groups including lower alkyl, aryl, alkoxy, thioalkyl, hydroxyl, amino, sulfonyl, thio, mercapto, imino, halo, cyano, nitro, nitroso, azide, carboxy, sulfide, sulfone, sulfoxy, phosphoryl, silyl, silyloxy, and boronyl. Similarly, the term "lower alkyl" includes "modified lower alkyl", which references a group having from one to eight carbon atoms and further having additional groups, such as one or more linkages selected from ether-, thio-, amino-, phospho-, keto-, ester-, and amido-, and/or being substituted with one or more groups including lower alkyl; aryl, alkoxy, thioalkyl, hydroxyl, amino, sulfonyl, thio, mercapto, imino, halo, cyano, nitro, nitroso, azide, carboxy, sulfide, sulfone, sulfoxy, phosphoryl, silyl, silyloxy, and boronyl. The term "alkoxy" as used herein refers to a substituent -O- R wherein R is alkyl as defined above. The term "lower alkoxy" refers to such a group wherein R is lower alkyl. The term "thioalkyl" as used herein refers to a substituent -S- R wherein R is alkyl as defined above. The term "alkoxy ether" as used herein, refers to a substituent -0-(Ri-0)_x-R₂, wherein Ri and R₂ are independently alkyl groups as defined above, and where X may be any integer between 1 and 10.

[0030] The term "alkylene" as used herein, unless otherwise specified, refers to a bivalent saturated alkyl chain (such as ethylene) regarded as derived from an alkene by opening of the double bond or from an alkane by removal of two hydrogen atoms from different carbon atoms.

[0031] The term "alkenyl" as used herein, unless otherwise specified, refers to a branched, unbranched or cyclic (e.g. in the case of C5 and C6) hydrocarbon group of 2 to 30, or 2 to 12 in some embodiments, carbon atoms containing at least one double bond, such as ethenyl, vinyl, allyl, octenyl, decenyl, dodecenyl, and the like. The term "lower alkenyl" intends an alkenyl group of two to eight carbon atoms, and specifically includes vinyl and allyl. The term "cycloalkenyl" refers to cyclic alkenyl groups.

[0032] The term "alkynyl" as used herein, unless otherwise specified, refers to a branched or unbranched hydrocarbon group of 2 to 24, or 2 to 12 in some embodiments, carbon atoms containing at least one triple bond, such as acetylenyl, ethynyl, n-propynyl, isopropynyl, n-butynyl, isobutynyl, t-butynyl, octynyl, decynyl and the like. The term "lower alkynyl" intends an alkynyl group of two to eight carbon atoms, and includes, for example, acetylenyl and propynyl, and the term "cycloalkynyl" refers to cyclic alkynyl groups.

[0033] Stabilizing Complex

[0034] In one or more embodiments, wellbore fluids of the present disclosure may contain a stabilizing complex formed from the reaction of an aluminate and a phosphate, and in particular embodiments the stabilizing complex is formed from an acidic phosphate salt and an aluminate salt. [0035] Aluminates in accordance with one or more embodiments of the instant disclosure are compounds containing aluminum and oxygen. In aqueous solutions aluminate may be present as a mononuclear tetrahedral complex Al(OH)⁴ , or a number of ionic forms that include A10₂ ^", A10₃ ³ Al(H₂0)₅OH²⁺, Al(OH₃), and [Al(OH)₄]^1_, for example. In addition, depending on a number of factors that include pH, ionic strength, and the presence of other ions or molecules in solution, aluminates may also form higher order complexes that encompass gibbsite or alumina-type structures such as [Al₃(OH)n]^2" , Al₆(OH) i5³⁺, Al[(OH)₅Al₂]n³⁺ⁿ⁺, Ali₃0₄(OH)₂₄ ⁷⁺ _, or Ali₄(OH)₃₄ ⁸⁺. The degree to which aluminates polymerize may depend on process parameters like temperature, stirring rate, order or reagent addition, etc. Polymerization of aluminates gradually proceeds to higher molecular weight structures, and may eventually lead to the formation of aggregates that may become large enough to precipitate from solution.

[0036] Aluminates in solution may interact with a number of other ionic and non- ionic species that may include organic materials, chelants, and counter ions such as phosphate, borate, silicate, alkali metal cations, and alkaline earth metal cations. When reacted with alkali metals or salts thereof, aluminates may form salts with available counter ions such as sodium aluminate ( a₂Al₂0₄) and potassium aluminate (K₂A1₂0₄). Alkali metal salts may include, for example, alkali metal chlorides, hydroxides, or carboxylates, for example, where the metals are selected from group 1 alkali metal selected from Li, Na, K, Cs, or group 2 alkaline earth metals selected from Mg, Ca, and Ba.

[0037] In particular, aluminum has a high affinity for phosphate counter ions generated from the dissolution of phosphoric acid or mono-, di- or tri-basic phosphate salts, for example. In some embodiments, a stabilizing complex may be formed by reacting the above described aluminates with a phosphate counter ion prior to addition to a wellbore fluid or may be reacted in situ depending on fluid conditions such as pH or ionic strength. Phosphate counter ions may be generated, for example, from the dissolution of an alkali metal phosphate such as that formed from the reaction of phosphoric acid and any of the basic alkali metal salts described above. In other embodiments, the phosphate may be selected, for example, trisodium phosphate, tetrasodium pyrophosphate, sodium acid pyrophosphate, sodium tripolyphosphate hexahydrate, sodium monobasic phosphate, sodium dibasic phosphate, sodium hexametaphosphate, potassium monobasic phosphate, potassium dibasic phosphate, potassium hexametaphosphate, potassium polyphosphates, and mixtures thereof. In yet other embodiments, the phosphate may be selected the neutralization products, in part or in whole, from the reaction of a suitable amine and phosphoric acid of polyphosphoric acid.

[0038] In embodiments, the stabilizing complex may possess a ratio of aluminate to phosphate within a range of 0.25:1 to 10:1 by weight of solid material. In other embodiments, the stabilizing complex may possess a ratio of aluminate to phosphate within a range of 1 :1 to 2:1 by weight of solid material. In some embodiments, the stabilizing complex may be an alkali metal aluminate such as sodium or potassium aluminate and the phosphate may be an alkali metal phosphate, phosphoric acid, polypolyphoric acid or a mixture of phosphoric or polyphosphoric acid and an amine.

[0039] The pH of the wellbore fluid may also affect the speed of the reaction between aluminate and phosphate. Other factors may include the solubility of the phosphate salt, affinity of the phosphate for other cations present in solution, and the overall pH of the solution. For example, a monobasic phosphate salt may be used in some embodiments to alter the pH of an aluminate solution, increasing the rate of formation of the stabilizing complex.

[0040] In one or more embodiments, the wellbore fluid or stock fluid containing the stabilizing complex may have a pH that ranges from a lower limit equal to or greater than 5, 6, 7, and 8, to an upper limit of 8, 9, 10, 11 , 12, and 13, where the pH may range from any lower limit to any upper limit. In other embodiments, the wellbore fluid or stock fluid containing the stabilizing complex may have a pH that ranges from pH 10 to pH 12.5. In yet other embodiments, the wellbore fluid or stock fluid containing the stabilizing complex may have a pH that ranges from pH 7 to pH 13. [0041] In one or more embodiments, the stabilizing complex is present in the wellbore fluid at a concentration that ranges from 0.1 ppb to 50 ppb, and from 1 ppb to 50 ppb in other embodiments.

[0042] In other embodiments, stabilizing complexes useful for application as shale inhibitors in accordance with the present disclosure may include phosphate geopolymers formed from the reaction of a metal oxide with phosphoric acid or any of the alkali metal phosphates described above. In one or more embodiments, the metal oxide may be calcium oxide, calcium hydroxide, magnesium oxide, magnesium hydroxide, zinc oxide, zinc hydroxide or combinations thereof.

[0043] Embodiments of the present disclosure directed to the use of phosphate geopolymers may provide effective shale hydration inhibition at elevated temperatures without the addition of extraneous temperature stabilizers. In particular embodiments, stabilizing complexes may effectively inhibit shale hydration and retain stably rheology at temperatures up to 150°F (66°C) or from 150°F up to 300°F (149°C) in other embodiments.

[0044] The particle size of the components of the phosphate geopolymer may be varied to increase or decrease the reaction or set time of the stabilizing complexes. For example, the metal oxide component may have a reduced particle size in order to increase surface area, which may lead to increased reaction rates. In one or more embodiments, metal oxides in accordance with this disclosure may have an average particle size of less than 50 microns.

[0045] In some embodiments, the reaction rate for the formation of the phosphate geopolymer may be controlled by tuning the rate of dissolution for the metal oxide component. The rate of dissolution is, in part, a function of the crystalline structure of the metal oxide. Depending on the method of production, metal oxides may be prepared having crystalline structure with a greater or lesser degree of crystal defects. In one example, metal oxides may be produced through calcination of carbonates to remove associated water molecules and carbon dioxide. High temperature calcination results in a much more ordered crystalline product than low temperature calcination. With lower temperature calcination (less than 750°C for example), the resulting product is often disordered and less crystalline with a higher degree of unsaturated coordinate sites. The presence of unsaturated coordinate sites results in faster hydration of the metal oxide and increased production of metal cations that react to form the phosphate geopolymer.

[0046] In one or more embodiments, the concentration of the inorganic complex is present in the wellbore fluid at a concentration that ranges from 0.1 ppb to 50 ppb. In embodiments directed to stabilizing agents that include phosphate geopolymers, the stoichiometric ratio of metal oxide to phosphate salt may be range from about 2:1 to 1 :2 I some embodiments, and about 1 :1 in other embodiments.

[0047] Amine Additives

[0048] In one or more embodiments, an amine additive may be present in a wellbore fluid to decrease or eliminate water uptake by reactive shales, thereby preventing fluid loss to clay-rich formations. Any type of amine may be used, including those described in, for example, U.S. Patent Nos. 5,558,171 , 6,609,578, 6,857,485, 7,618,925, 7,939,473, and 7,521 ,398.

[0049] However, in particular embodiments, the amine additives in accordance with the present disclosure may be amine shale hydration inhibition agents such as naturally occurring amines having an oleophilic backbone component, and naturally occurring polyamines in more particular embodiments. In various embodiments, the shale inhibitors may include from 1 to 7 amine groups, but may include more in other embodiments. The oleophilic backbone of the amine may be a linear, branched alkyl group, cyclic alkyl, or heterocyclic aromatic groups, and in particular embodiments, may be at least a C3 group. Amine additives in some embodiments may be selected from commercial shale inhibitors such as ULTRAHIB™ and KLAHIB™, available from M-I L.L.C. (Houston, TX). In other embodiments, amine additives may be selected from aminophosphates such as 1 -hydro xyethylidene- 1 , 1 -di-phosphonic acid, bis (hexamethylene) triamine pentabis (methylene phosphonic acid) and amine phosphonic acid. [0050] While not bound by theory, the inventors of the present disclosure theorize that the shale inhibition occurs by the interaction of the nitrogen atoms from the amine(s) with the active groups on the clay surface in combination with the carbon backbone of the oleophilic portion of the amine repelling water from the clay surface. Thus, the amine should be present in sufficient concentration to reduce either or both the surface hydration based swelling and/or the osmotic based swelling of the shale clay. When drilling through a formation having water-swellable clays therein, a wellbore fluid having the additives of the present disclosure may be circulated therein to reduce the swelling of clays or shale hydration.

[0051] In some embodiments, the amine may be selected from alkylxanthine derivatives, pyrimidine derivatives, polyether amines, and polyalkylene amines. For example, in a particular embodiment the amine may have general formula:

1 2 3

where R , R , and R are each the same or different and are selected from a group consisting of hydrogen, alkyl, haloalkyl, alkenyl, alkoxy, and alkoxy ether, as defined above.

[0052] Using amines of the present disclosure that are also non-ionic, shale hydration inhibition may be achieved without increasing the electrical conductivity of the wellbore fluid. Thus, such fluids may be classified as low electrical conductivity fluids. As used herein, a "low electrical conductivity fluid" refers to a fluid having an electrical conductivity of no more than 10,000 μ8/αη. However, in accordance with particular embodiments of the present disclosure, fluids having electrical conductivities of less than about 3000 μ8/αη may be achieved, and less than about 2000 μδ/αη in more particular embodiments. [0053] The amines of the present disclosure may be added to a wellbore fluid in concentrations sufficient to meet the requirements for a particular formation in a given geographic region. In embodiments, concentrations between about 0.5 pounds per barrel (ppb) and 10 ppb are contemplated and are considered to be functionally effective to reduce swelling of clays which swell in the presence of water. In other embodiments, the amine is present in the wellbore fluid at a concentration that ranges from 0.5 ppb to 40 ppb. In yet other embodiments, the amine is present in the wellbore fluid at concentrations that range from 1 ppb to 35 ppb.

[0054] Wellbore Fluids

[0055] The aqueous based continuous phase may generally be any water-based fluid phase that is compatible with the formulation of a drilling fluid and is compatible with the shale hydration inhibition agents disclosed herein. In a particular embodiment, the aqueous based continuous phase may include fresh water. However, in other embodiments, the fluid may include at least one of fresh water, mixtures of water and water soluble organic compounds and mixtures thereof.

[0056] In a particular embodiment, the aqueous fluid may be selected to be within the electrical conductivity limits described above. One skilled in the art would appreciate that conductivity requirements of a fluid may depend on the regulatory requirements for disposal of fluids/cuttings in a particular jurisdiction, and thus, for jurisdictions having relatively higher conductivity limits, inclusion of some salt in the fluid may be provided. In such instances, for example, the aqueous fluid may be formulated with mixtures of desired salts in fresh water. Such salts may include, but are not limited to alkali metal chlorides, hydroxides, or carboxylates, for example.

[0057] In various embodiments of the drilling fluid disclosed herein, the brine may include seawater, aqueous solutions wherein the salt concentration is less than that of sea water, or aqueous solutions wherein the salt concentration is greater than that of sea water. Salts that may be found in seawater include, but are not limited to, sodium, calcium, aluminum, magnesium, potassium, strontium, lithium, and salts of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, sulfates, phosphates, silicates and fluorides. Salts that may be incorporated in a given brine include any one or more of those present in natural seawater or any other organic or inorganic dissolved salts. Additionally, brines that may be used in the drilling fluids disclosed herein may be natural or synthetic, with synthetic brines tending to be much simpler in constitution. One of ordinary skill would appreciate that the above salts may be present in the base fluid, or alternatively, may be added according to the method disclosed herein. Further, the amount of the aqueous based continuous phase should be sufficient to form a water based drilling fluid. This amount may range from nearly 100% of the wellbore fluid to less than 30% of the wellbore fluid by volume. In some embodiments, the aqueous based continuous phase may constitute from about 95 to about 30% by volume or from about 90 to about 40% by volume of the wellbore fluid.

[0058] Temperature Stability Agents

[0059] Wellbore fluids of the present disclosure may also contain at least one temperature stabilizing agent that works to increase the stability of compositions at elevated temperatures such as from 150°F to 300°F (66°C to 150°C). Temperature stability agents in some embodiments may include amino-phosphates, fulvates, humates, polycarboxylates, polyols, or alkoxyamines.

[0060] In one or more embodiments, the temperature-stabilizing agent may be an amino -phosphate that may include l-hydroxyethylidene-l ,l-di-phosphonic acid, bis (hexamethylene) triamine pentabis (methylene phosphonic acid), and amine phosphonic acid. Examples polyol alkoxy-amine stabilizing agents useful a temperature stabilizers in accordance with the present disclosure may include triethanolamine, glycerol, mannitol, glucose, maltodextrin, cyclodextrin, pentaerythritol, 2-methyl-2,4-pentanediol, 1 ,1 ,1- tris(hydroxymethyl) propane, bis(hydroxymethyl) propionic acid, bis(hydroxymethyl) butyric acid, l ,3-bis[tris(hydroxymethyl)methylamino] propane, 2,2-bis(hydroxymethyl) -2,2 ',2 "-nitrilotriethanol, 1 ,1 ,1 -tris(hydroxymethyl)propane, 2,2-bis(hydroxymethyl), butyric acid, and the like.

[0061] Rheological Additives [0062] The wellbore fluids may also include a viscosifying agent in order to alter or maintain the rheological properties of the fluid. The primary purpose for such viscosifying agents is to control the viscosity and potential changes in viscosity of the drilling fluid. Viscosity control may be needed because often a subterranean formation may have temperatures higher than the surface temperature. Thus a wellbore fluid may undergo temperature extremes of nearly freezing temperatures to nearly the boiling temperature of water or higher during the course of its transit from the surface to the drill bit and back. One of skill in the art should know and understand that such changes in temperature may result in changes in the rheological properties of fluids. Thus in order to control and/or moderate the rheology changes, viscosity agents and rheology control agents may be included in the formulation of the wellbore fluid.

[0063] Viscosifying agents suitable for use in the formulation of the fluids of the present disclosure may be generally selected from any type of natural biopolymer suitable for use in aqueous based drilling fluids. Biopolymers may include starches, celluloses, and various gums, such as xanthan gum, gellan gum, welan gum, and schleroglucan gum. Such starches may include potato starch, com starch, tapioca starch, wheat starch and rice starch, etc. In accordance with various embodiments of the present disclosure, the biopolymer viscosifying agents may be unmodified (i.e., without derivitization). Polymeric viscosifiers may include, for example, POLYP AC^® UL polyanionic cellulose (PAC), DUOVIS^®, and BIOVIS^®, each available from M-I L.L.C. (Houston, TX).

[0064] Depending on the application, the polymeric viscosifier may be a synthetic polymer that resists degradation over time, and in some instances, under high temperature/high pressure conditions (HTHP). Thermal and pressure stable polymeric viscosifiers polymers may include for example polymers, copolymers, block copolymers, and higher order copolymers (i.e., a terpolymer or quaternary polymer, etc.) composed of monomers that may include 2-acrylamido-2-methylpropanesulfonate, acrylamide, methacrylamide, N,N dimethyl acrylamide, N,N dimethyl methacrylamide, tetrafluoro ethylene, dimethylaminopropyl methacrylamide, N-vinyl-2-pyrrolidone, N- vinyl-3-methyl-2-pyrrolidone, N-vinyl-4,4-diethyl-2-pyrrolidone, 5-isobutyl-2- pyrrolidone, N-vinyl-3-methyl-2-pyrrolidone, alkyl oxazoline, poly(2-ethyl-2- oxazoline), C2-C12 olefins, ethylene, propylene, butene, butadiene, vinyl aromatics, styrene, alkylstyrene, acrylic acid, methacrylic acid, vinyl alcohol, partially hydrolyzed acrylamide or methacrylamide, and derivatives or mixtures thereof. In yet other embodiments, polymeric viscosifiers may include polyalkylene amines and polyethers such as polyethylene oxide and polypropylene oxide.

[0065] In some embodiments, the polymeric viscosifiers may include, for example, thermally stable polymeric viscosifiers such as DUROTHERM™, DURALON™, available from MI, L.L.C. (Houston, TX), KEMSEAL™, available from Baker Hughes, Inc. (Houston, TX), DRISCAL^®-D, available from Phillips Petroleum Co. (Bartlesville, OK), CYPA ™ available from National Oilwell Varco (Houston, TX), and ALCOMER™ 242, available from Allied Colloids Ltd (United Kingdom). In other embodiments the viscosifying agent may be IDCAP™ D, commercially available from MI L.L.C. (Houston, TX).

[0066] Wellbore fluids in accordance with embodiments disclosed herein may contain viscosifying agents in an amount ranging from 0.5 to 5 pounds per barrel (1.43 to 14.27 kg/m ); however, more or less may be used depending on the particular wellbore diameter, annular velocity, cutting carrying capacity, quiescent time expected or desired.

[0067] Moreover, the wellbore fluids of the present disclosure may include a weight material or weighting agent in order to increase the density of the fluid. The primary purpose for such weighting materials is to increase the density of the fluid so as to prevent kick-backs and blow-outs. Thus the weighting agent may be added to the drilling fluid in a functionally effective amount largely dependent on the nature of the formation being drilled. Weighting agents or density materials suitable for use the fluids disclosed herein include galena, hematite, magnetite, iron oxides, illmenite, barite, siderite, celestite, dolomite, calcite, and the like, mixtures and combinations of these compounds and similar such weight materials that may be used in the formulation of wellbore fluids. The quantity of such material added, if any, may depend upon the desired density of the final composition. In some instances, weighting agent is added to result in a drilling fluid density of up to about 24 pounds per gallon. The weighting agent may be added up to 21 pounds per gallon in one embodiment, and up to 19.5 pounds per gallon in another embodiment.

[0068] In addition to the other components previously noted, materials generically referred to as thinners and fluid loss control agents may also optionally added to water- based wellbore fluid formulations. Of these additional materials, each may be added to the formulation in a concentration as Theologically and functionally required by drilling conditions.

[0069] In certain embodiments, the methods of the present disclosure comprise providing a wellbore fluid (e.g., a drilling fluid, reservoir drill-in fluid, fracturing fluid, etc.) of the present disclosure that comprises an aqueous base fluid, a stabilizing complex formed from an aluminate and a phosphate, and placing the wellbore fluid in a subterranean formation. The stabilizing complex and selected additives may be mixed into the wellbore fluid individually or as a mulit-component additive that comprises the stabilizing complex, and/or amine additive, viscosifier, or other optional components. The stabilizing complex may be added to the wellbore fluid prior to, during, or subsequent to placing the wellbore fluid in the subterranean formation.

[0070] A wellbore fluid according to the disclosure may be used in a method for drilling a well into a subterranean formation in a manner similar to those wherein conventional wellbore fluids are used. In the process of drilling the well, a wellbore fluid is circulated through the drill pipe, through the bit, and up the annular space between the pipe and the formation or steel casing to the surface. The wellbore fluid performs several different functions, such as cooling the bit, removing drilled cuttings from the bottom of the hole, suspending the cuttings and weighting the material when the circulation is interrupted.

[0071] The stabilizing complex may be added to the base fluid on location at the well-site where it is to be used, or it can be carried out at another location than the well- site. If the well-site location is selected for carrying out this step, then the stabilizing complex and/or the amine may immediately be dispersed in an aqueous fluid, and the resulting wellbore fluid may immediately be emplaced in the well using techniques known in the art.

[0072] In one or more embodiments of the present disclosure, components of the wellbore fluids may be added to the wellbore simultaneously or sequentially, depending on the demands of the downhole environment. In a particular embodiment, amine additives may be provided in a second wellbore fluid as at least one of a preflush or an overflush when used in conjunction with first wellbore fluid containing a stabilizing complex.

[0073] Another embodiment of the present method includes a method of reducing the swelling of shale in a well whereby a water-base fluid formulated in accordance with the teachings of this disclosure is circulated in a well. The methods and fluids of the present disclosure may be utilized in a variety of subterranean operations that involve subterranean drilling, drilling-in (without displacement of the fluid for completion operations) and fracturing. Examples of suitable subterranean drilling operations include, but are not limited to, water well drilling, oil/gas well drilling, utilities drilling, tunneling, construction/installation of subterranean pipelines and service lines, and the like. These subterranean drilling operations may be utilized, inter alia, to drill a well bore in a subterranean formation, or to stimulate the production of fluids from a subterranean formation, as well as or for a number of other purposes. In certain embodiments, the present disclosure provides methods of drilling at least a portion of a well bore to penetrate a subterranean formation.

[0074] EXAMPLES

[0075] Example 1

[0076] In the following example, a series of experiments was conducted to illustrate inhibition of hydration in samples of Oxford clay using wellbore fluids in accordance with the instant disclosure. Samples wellbore fluids were formulated as shown in Table 1 , where ULTRAHIB™ is a liquid polyamine shale inhibitor and IDCAP™ D is an anionic polymeric fluid floss additive; both commercially available from M-I L.L.C. (Houston, TX). Fluid formulations were then added to shale cuttings and aged 16 hours at 150°F (66°C). Shale recovery and hydration data are shown below in Table 1.

Table 1 Shale Recovery and Hydration data for wellbore fluid formulations in

Example 1.

In order to quantitatively measure the affinity for the sample fluids for binding and coating clay surfaces, adhesive force data was obtained for a number of samples. Results are shown below in Table 2. The test procedure involves compacting cuttings recovered from fluids in Example 1 with an applied compression load. In separate test sequences the compaction force is increased from 10, 30 and 50 kg and the tensional load required to separate a steel probe from the surface of the compressed cuttings bed is measured. A texture analyzer is used to apply the pre-set compaction load and to measure the tensional force required to separate the contacting steel disc from the surface of the compacted cuttings sample. The test cell is composed of a steel cylinder and a perforated base plate to allow some fluid to drain from the test cell during the compaction step. The average tensional force taken from repeat tests is expressed as the adhesive force and taken as a measure of the stickiness of clay cuttings after exposure to the fluids in Example 1. Results are shown in Table 2. Table 2 Adhesive force data for wellbore fluid formulations in Example 1.

[0078] Example 2

[0079] An additional experiment was conducted to illustrate the synergistic effect of the stabilizing complex formed between an aluminate and a phosphate salt. With particular regard to Figure 1 , the percent hydration of a sample of Oxford shale exposed to sample wellbore fluid formulations was assayed as a function of added potassium phosphate salt. Samples were formulated with and without 17.5 ppb potassium aluminate. Results indicate that the percent hydration for the shale sample exposed to a wellbore fluid containing the stabilizing complex formed by the aluminate and phosphate salt is lower that the percent hydration for either of the respective components alone.

[0080] Example 3

[0081] In another example, an experiment was conducted to illustrate the effect of the further addition of an amine to the stabilizing complex formed between an aluminate and a phosphate salt. With particular regard to Figure 2, the percent hydration of a wellbore fluid following aging of a wellbore fluid with Oxford shale cuttings was determined as a function of added potassium aluminate for samples containing various mixtures of phosphate and amine. As shown in Figure 2, wellbore fluid samples containing amine and the stabilizing complex of aluminate and phosphate show nearly complete recovery of the wellbore fluid at lower relative concentrations than wellbore fluids containing only the amine or a mixture of the amine and aluminate, respectively. [0082] Example 4

[0083] In the following example, a series of experiments was conducted to illustrate inhibition of hydration in samples of Arne clay using wellbore fluids in accordance with the instant disclosure. Samples wellbore fluids were formulated as shown in Table 3, where ULTRAHIB™ and KLA-HIB™ are amine -based shale inhibitors, EMI-727 is a poly(oxyethylene) diamine, IDCAP™ D is an anionic polymer fluid loss additive, EMI- 1988 is a cationic polymer fluid loss additive, and EMI- 1994 is a nonionic polymer fluid loss additive; and all are commercially available from M-I L.L.C. (Houston, TX) and PA- 1 is a polymeric non-ionic amine. Fluid formulations were then added to shale cuttings and aged 16 hours at 150°F (66°C). Shale recovery and hydration data as shown below in Table 3.

Table 3 Wellbore fluid formulations and shale inhibition data for Example 4.

. pp In order to quantitatively measure the affinity for the sample fluids for binding and coating clay surfaces, adhesive force data was obtained for a number of samples. Results are shown below in Table 4. The test procedure involves compacting cuttings recovered from fluids in Example 4 with an applied compression load. In separate test sequences the compaction force is increased from 10, 30 and 50Kg and the tensional load required to separate a steel probe from the surface of the compressed cuttings bed is measured. A texture analyzer is used to apply the pre-set compaction load and to measure the tensional force required to separate the contacting steel disc from the surface of the compacted cuttings sample. The test cell is composed of a steel cylinder and a perforated base plate to allow some fluid to drain from the test cell during the compaction step. The average tensional force taken from repeat tests is expressed as the adhesive force and taken as a measure of the stickiness of clay cuttings after exposure to the fluids in Example 4. Arne clay is a high kaolinite fraction clay and becomes particularly sticky when contacted with water based fluids. Results are shown in Table 4.

Table 4 Adhesive force data for wellbore fluid formulations in Example 4.

[0085] Example 5

[0086] In another example, an experiment was conducted to illustrate the effect of the further addition of an amine to the stabilizing complex formed between an aluminate and a phosphate salt. With particular regard to Figure 3, the percent hydration of a wellbore fluid following aging of a wellbore fluid with Arne shale cutting was determined as a function of added potassium aluminate for samples containing various mixtures of phosphate and amine. As shown in Figure 3, wellbore fluid samples containing 8 ppb amine and the stabilizing complex of aluminate and phosphate show decreased percent hydration of Arne shale than wellbore fluids containing only the amine or a mixture of the amine and aluminate, respectively.

[0087] Example 6

[0088] In the following example, a stabilizing complex composition is provided based on the partial neutralization of phosphoric acid with an amine, PA-2. The phosphoric acid/PA-2 mixture is mixed into the fluid and the alumino -phosphate complex salt is formed with the addition of a soluble alkali metal aluminate, such as a potassium aluminate. The amine and phosphoric are both 50% w/w, with the resultant material having a 50% w/w active content and a pour point of -17°C.

[0089] The phosphoric acid/PA-2 mixture is a liquid with a low pour point (-17°C) which will speed up the rate of product addition, reduce occupational health issues in handling phosphoric acid (corrosive) and improve handling in cold environments and may simplify logistics if the water-based fluid provided contains both an amine and mixed aluminate-phosphate complex salt components.

090] Tables 5 and 6 illustrate shale recovery and hydration data for selected fluid formulations added to shale cuttings and aged 16 hours at 150°F (66°C).

Table 5 Wellbore fluid formulations and Oxford clay inhibition data for Example 6.

Table 6 Wellbore fluid formulations and Arne clay inhibition data for Example 6

[0091] Table 7 illustrates adhesive force data obtained for selected inhibitor compositions for both Oxford and Arne clays. Testing methods were conducted according to the methods outlined in Example 1.

Table 7 Adhesive force data for wellbore fluid formulations in Example 6.

[0092] Embodiments of the present disclosure may provide at least one of the following advantages. Advantageously, reacting aluminates with phosphoric acid or phosphates prior to emplacement of the wellbore fluid may prevent aluminates from forming large insoluble aggregates and aid in dispersion of the aluminate/phosphate stabilizing complex throughout the fluid. Moreover, the reaction of the aluminate prior to emplacement the wellbore fluid may select for preferential ionic specie(s) that are more effective in inhibiting the hydration of shales downhole.

[0093] Further, amine additives of the present disclosure may be effective as shale hydration inhibitors during drilling and, when combined with the aluminate-based stabilizing complexes described above, may also exhibit a synergistic effect whereby the observed shale hydration inhibition is greater than either respective component alone. In addition, amine additives may not contribute to an increase in the electrical conductivity of the fluid, allowing for broader applicability for land disposal due to environmental concerns for disposal of high conductivity fluids/cuttings.

[0094] Wellbore fluids described herein may be used to inhibit shale hydration at a lower intrinsic pH, which may improve compatibility with polymer and lubricant drilling fluid components. Shale hydration inhibitors in accordance with embodiments disclosed herein also may be effective at preventing the hydration of high kaolinite/high illite fraction shales and may reduce the potential for wellbore instability due to balling, agglomeration, and accretion of drill cuttings.

[0095] While the disclosure includes a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments may be devised which do not depart from the scope of the present disclosure. Accordingly, the scope should be limited only by the attached claims. Moreover, embodiments described herein may be practiced in the absence of any element that is not specifically disclosed herein.

[0096] In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words 'means for' together with an associated function.

Claims

CLAIMS What is claimed:

1. A wellbore fluid, comprising:

an aqueous base fluid; and

a stabilizing complex, wherein the stabilizing complex is prepared from the reaction of an alkali metal aluminate salt and one or more selected from a group consisting of a phosphoric acid, a phosphate salt, and an amine -phosphoric acid mixture.

2. The wellbore fluid of claim 1 , wherein the stabilizing complex comprises an alkali metal phosphate formed from the reaction of an acid and a basic alkali metal phosphate salt.

3. The wellbore fluid of claim 1 , wherein the phosphate salt is described by the general formula:

M_xH_yP0₄ where M is at least one selected from Group I alkali metals and Group II alkaline earth metals; x is less than 2; and y ranges from 1 to 3.

4. The wellbore fluid of claim 1 , wherein the stabilizing complex comprises potassium aluminate and potassium dihydrogen phosphate.

5. The wellbore fluid of claim 4, wherein the ratio of potassium aluminate to potassium dihydrogen phosphate is within a range of 1 :1 to 2: 1 by weight of solid material.

6. The wellbore fluid of claim 1 , wherein the wellbore fluid comprises an amine, and wherein the amine is one or more selected from a group consisting of an alkylxanthine derivative, a pyrimidine derivative, a polyether amine, and a polyalkylene amine.

The wellbore fluid of claim 1 , wherein the wellbore fluid comprises an amine general formula:

1 2 3

8. The wellbore fluid of claim 8, wherein R 1 is hydrogen or methyl, R 2 is hydrogen or methyl, and R³ is hydrogen or methyl.

9. The wellbore fluid of claim 6, wherein the amine is present in the wellbore fluid at a concentration that ranges from 1 ppb to 35 ppb.

10. The wellbore fluid of claim 1 , wherein the pH of the wellbore fluid is within a range of pH 7 to pH 13.

11. The wellbore fluid of claim 1 , wherein the stabilizing complex is present in the wellbore fluid at a concentration that ranges from 1 ppb to 50 ppb.

12. The wellbore fluid of claim 1 , further comprising one or more temperature stabilizing agents selected from a group consisting of amino-phosphates, fulvates, humates, polycarboxylates, polyols, and alkoxyamines.

13. A method of preparing a drilling fluid, the method comprising:

providing an aqueous base fluid;

adding an aluminate salt;

adding one or more selected from a group consisting of phosphoric acid and a monobasic phosphate salt;

adjusting the pH to be within the range of 7 to 13.

14. The method of claim 13, wherein the one or more selected from a group consisting of phosphoric acid and a monobasic phosphate salt is added prior to the aluminate salt.

15. The method of claim 13, wherein the one or more selected from a group consisting of phosphoric acid and a monobasic phosphate salt is added subsequent to the aluminate salt.

16. The method of claim 13, further comprising adding one or more temperature stabilizing agents selected from a group consisting of amino-phosphates, fulvates, humates, polycarboxylates, polyols, and alkoxyamines.

17. A method of drilling, comprising:

circulating a wellbore fluid into a wellbore, the wellbore fluid comprising:

an aqueous base fluid; and

a stabilizing complex, wherein the stabilizing complex is prepared from the reaction of an alkali metal aluminate salt and one or more selected from a group consisting of a phosphoric acid and a monobasic phosphate salt.

18. The method of claim 17, wherein the wellbore fluid further comprises one or more temperature stabilizing agents selected from a group consisting of amino-phosphates, fulvates, humates, polycarboxylates, polyols, and alkoxyamines.

19. The method of claim 17, wherein the wellbore fluid comprises an amine, and wherein the amine has the general formula:

where R¹, R², and R³ are each the same or different and are selected from a group consisting of hydrogen, alkyl, haloalkyl, alkenyl, alkoxy, and alkoxy ether.

20. The method of claim 19, wherein R¹ is hydrogen or methyl, R² is hydrogen or methyl, and R³ is hydrogen or methyl.

21. The method of claim 17, wherein the amine is provided in a second wellbore fluid as at least one of a preflush or an overflush.

22. A method of drilling, comprising:

circulating a wellbore fluid into a wellbore, the wellbore fluid comprising:

an aqueous base fluid; and

an amine, wherein the amine has the general formula:

23. The method of claim 22, wherein the amine is present at a concentration that ranges from 1 ppb to 10 ppb.

24. The method of claim 22, wherein the pH of the wellbore fluid ranges from pH 7 to pH 13.

25. The wellbore fluid of claim 22, wherein the wellbore fluid has an electrical conductivity of no more than 10,000 μ8Λ;ιη.

26. The wellbore fluid of claim 22, wherein the wellbore fluid has an electrical conductivity

27. The method of claim 22, wherein the wellbore fluid further comprises an alkali metal silicate.

28. A wellbore fluid, comprising:

an aqueous base fluid; and

a stabilizing complex, wherein the stabilizing complex is prepared from the reaction of a metal oxide and one or more selected from a group consisting of a phosphoric acid, a phosphate salt, and an amine -phosphoric acid mixture.

29. The wellbore fluid of claim 28, wherein the phosphate salt can be described by the general formula:

30. The wellbore fluid of claim 28, wherein the metal oxide is one or more selected from a group consisting of calcium oxide, calcium hydroxide, magnesium oxide, magnesium hydroxide, zinc oxide, and zinc hydroxide.

31. The wellbore fluid of claim 28, wherein the stabilizing complex is prepared from a metal oxide and phosphate salt, wherein stoichiometric ratio of metal oxide to phosphate salt is 1 :1.

32. The wellbore fluid of claim 28, wherein the stabilizing complex is present in the wellbore fluid at a concentration that ranges from 0.1 ppb to 50 ppb.

33. The wellbore fluid of claim 28, wherein the wellbore fluid comprises an amine, and wherein the amine is one or more selected from a group consisting of an alkylxanthine derivative, a pyrimidine derivative, a polyether amine, and a polyalkylene amine. The wellbore fluid of claim 28, wherein the wellbore fluid comprises an amine general formula:

1 2 3