WO2018128537A1

WO2018128537A1 - Crosslinker slurry compositions and applications

Info

Publication number: WO2018128537A1
Application number: PCT/MY2017/000001
Authority: WO
Inventors: Diankui Fu; Hai Liu; Jin Yu ZHAO; Kong Teng Ling; Soo Hui Goh
Original assignee: Schlumberger Technology Corporation; Schlumberger Canada Limited; Services Petroliers Schlumberger; Schlumberger Technology B.V.
Priority date: 2017-01-05
Filing date: 2017-01-05
Publication date: 2018-07-12
Also published as: CN110139910A

Abstract

A method of treating a subterranean formation penetrated by a wellbore is disclosed, including: a. utilizing a composition including: boric acid; sodium tetraborate pentahydrate; a pH adjusting agent; a hydrocarbon fluid; and an organophilic clay; b. combining the composition with a mixture comprising a viscosifier and an aqueous medium to form a treatment fluid; and c. contacting the formation with the treatment fluid to treat the formation.

Description

CROSSL1NKER SLURRY COMPOSITIONS AND APPLICATIONS

FIELD

[0001] Embodiments of the present disclosure relate to methods and compositions for treating a subterranean formation. Specifically, embodiments of this disclosure relate to methods and compositions for delivering and using a crosslinker for treating a subterranean formation.

BACKGROUND

[0002] Some statements may merely provide background information related to the present disclosure and may not constitute prior art.

[0003] Fluids with a viscosity that is individually tailored for a variety of physical and chemical conditions are needed to treat subterranean formations for the recovery of hydrocarbons. Often, to achieve a specific viscosity, a vicosifier will be introduced to a fluid, then pumped down a wellbore to fracture the formation rock. The variety of viscosifiers commercially available for this purpose is vast. Often, however, a small subset of commodity grade viscosifiers is selected for use. These viscosifiers may benefit from the presence of a crosslinker to increase or otherwise tailor the resulting fluid viscosity. The crosslinkers are selected for their ability to encourage crosslinking of the viscosifier depending upon the formation conditions and viscosifier properties. Borate crosslinked fluids are favored over metal-crosslinked fluids because the former are not sensitive to mechanical shearing and can recover their viscosity after shearing. It has been recognized by the industry that good shear recovery is important to the success of hydraulic fracturing treatment. It is known to the industry that guar-based fracturing fluid crosslinked with borate can significantly recover its viscosity after high shear. Lowering polymer loading is known to improve fracture conductivity, however it will also reduce fluid viscosity and the ability to recover after shear. One of the biggest challenges for formulating a low polymer loading guar fracturing fluid for use in low temperature environments is to secure both a reasonably high viscosity and a short shear recovery time.

SUMMARY

[0004] Embodiments of the disclosure relate to a method of treating a subterranean formation penetrated by a wellbore, the method including: a. utilizing a composition including: boric acid; sodium tetraborate pentahydrate; a pH adjusting agent; a hydrocarbon fluid; and an organophilic clay; b. combining the composition with a mixture including a viscosifier and an aqueous medium to form a treatment fluid; and c. contacting the formation with the treatment fluid to treat the formation.

[0005] Embodiments of the disclosure relate to a method of treating a subterranean formation penetrated by a wellbore, including: a. preparing a dry mixture of boric acid; sodium tetraborate pentahydrate; and a pH adjusting agent selected from the group consisting of calcium hydroxide, potassium hydroxide, sodium hydroxide, potassium carbonate, an amine containing compound, or a combination thereof; b. combining the dry mixture with a viscosified fluid medium including a hydrocarbon fluid and an organophilic clay to form a composition; c. combining the composition with a mixture including a viscosifier and aqueous medium to form a treatment fluid; and d. contacting the formation with the treatment fluid to treat the formation.

[0006] Embodiments of the disclosure relate to a method of preparing a composition, including: a. preparing a dry mixture of boric acid; sodium tetraborate pentahydrate; and a pH adjusting agent selected from the group consisting of calcium hydroxide, potassium hydroxide, sodium hydroxide, potassium carbonate, an amine containing compound, or a combination thereof; and b. combining the dry mixture with a viscosified fluid medium including a hydrocarbon fluid and an organophilic clay to form the composition.

FIGURES

[0007] FIG. 1 is a plot of viscosity and shear rate as a function of time showing rheology profiles for various fracturing fluids with varying polymer loadings for an embodiment of the disclosure.

[0008] FIG. 2 is a plot of viscosity and shear rate as a function of time showing shear rate recovery for various fracturing fluids with varying polymer loadings for an embodiment of the disclosure. [0009] FIG. 3 is a plot of viscosity and shear rate as a function of time for various crosslinked fracturing fluids including crushed and uncrushed breaker for an additional embodiment of the disclosure.

DETAILED DESCRIPTION

[0010] At the outset, it should be noted that in the development of any such actual embodiment, numerous implementation-specific decisions are made to achieve the developer's specific goals, such as compliance with system related and business related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. The description and examples are presented solely for the puipose of illustrating certain of the embodiments of the disclosure and should not be construed as a limitation to the scope and applicability of the disclosure herein. While the compositions are described herein as comprising certain materials, it should be understood that the composition could optionally comprise two or more chemically different materials. In addition, the composition can also comprise some components other than the ones already cited.

[001 1] In the summary, and in this description, each numerical value should be read once as modified by the term "about" (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. Also, in the summary and this detailed description, it should be understood that a concentration range listed or described as being useful, suitable, or the like, is intended such that any and every concentration within the range, including the end points, is to be considered as having been stated. For example, "a range of from 1 to 10" is to be read as indicating each and every possible number along the continuum between about 1 and about 10. Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to only a few specific data points, it is to be understood that inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that inventors have disclosed and enabled the entire range and all points within the range.

[0012] Often, boron is delivered into the polymer solution for crosslinking in a number of forms, such as dissolved borax, slurry of solid borax or ulexite, boric acid solution, as well as other boron sources. However, as the concentration of the boron-containing crosslinker becomes more important, the amount of material transported to location for a treatment as well as the rate at which it is added on-the-fly into the polymer solution becomes logistically significant. It is a logistical advantage to have the chemical additives for a fracturing treatment as compact and/or concentrated as practical.

[0013] In accordance with an embodiment, a method of treating a subterranean formation penetrated by a wellbore is disclosed, the method comprising, consisting of, or consisting essentially of: a. utilizing a composition comprising, consisting of, or consisting essentially of boric acid; sodium tetraborate pentahydrate; a pH adjusting agent; a hydrocarbon fluid; and an organophilic clay; b. combining the composition with a mixture comprising a viscosifier and an aqueous medium to form a treatment fluid; and c. contacting the formation with the treatment fluid to treat the formation.

[0014] The pH adjusting agent can be selected from the group consisting of calcium hydroxide, potassium hydroxide, sodium hydroxide, potassium carbonate, an amine containing compound, or a combination thereof; and the hydrocarbon fluid can be diesel or any other nonaqueous fluid medium. The pH of the composition may be tailored to maximize the transportation, stability, and/or crosslinking properties of the compositions; and can range from pH of 8.90 to about 9.80 for low temperature applications (68 to 80 °F) and can range from pH of 12.12 to 12.74 for high temperature applications (200 to 290°F). [0015] The boric acid can be present in the composition in an amount of from about 6% to about 13% or about 7% to about 10% or about 7% to about 8%, by weight, based upon total weight of the composition. The sodium tetraborate pentahydrate can be present in the composition in an amount of from about 6% to about 13% or about 7% to about 10% or about 7% to about 8%, by weight, based upon total weight of the composition. The pH adjusting agent can be present in the composition in an amount of from about 2% to about 5% or about 2% to about 4% or about 2% to about 3%, by weight, based upon total weight of the composition. The diesel can be present in the composition in an amount of from about 65% to about 85% or about 70% to about 85% or about 75% to about 80%, by weight, based upon total weight of the composition. The organophilic clay can be present in the composition in an amount of from about 3% to about 4.5% or about 3.5% to about 4.5% or about 3.5% to about 4%, by weight, based upon total weight of the composition. The composition can be free or substantially free of water, or can comprise less than about 10% or less than 5% or less than 2% or less than 1% or less than 0.5% water, by weight, based upon total weight of the composition. [0016] The composition can be added to the mixture in an amount of from about 0.5 to about 3 or about 1 to about 3 or about 1 to about 2 gallons per thousand gallons of the mixture. The viscosifier can be present in the treatment fluid in an amount of at most about 18 or at most about 16 or at most about 14 or from about 14 to about 18 or from about 14 to about 16 pounds per thousand gallons of the treatment fluid. The temperature of the subterranean formation treated with the treatment fluid can be at most about 30°C or at most about 25°C or at most about 20°C or from about 15°C to about 20°C.

[0017] The boric acid, the sodium tetraborate pentahydrate, and the pH adjusting agent can be dry mixed to form a dry mixture, the organophilic clay can be added to the hydrocarbon fluid to form a viscosified fluid medium; and the dry mixture can be combined with the viscosified fluid medium to form the composition described herein.

[0018] The viscosifier can comprise a hydrated polymer selected from the group consisting of guar, high-molecular weight polysaccharides composed of mannose and galactose sugars, guar derivatives such as hydroxypropyl guar (HPG), carboxymethyl guar (CMG), and carboxymethylhydroxypropyl guar (CMHPG), synthetic polymer. Cellulose derivatives such as hydroxyethylcellulose (HEC) or hydroxypropylcellulose (HPC) and carboxymethylhydroxyethylcellulose (CMHEC) may also be used. Any useful polymer may be used in either crosslinked form, or without crosslinker in linear form. Xanthan, diutan, and scleroglucan, three biopolymers, have been shown to be useful as viscosifying agents. Another viscosifying agent is schizophyllan, which in some cases crosslinks with boron on a very slow kinetic: order of >10 hours in some conditions. Synthetic polymers such as, but not limited to, polyvinylalcohol, polyacrylamide and polyacrylate polymers and copolymers, are used typically for high-temperature applications, but could also be used herein. Also, associative polymers for which viscosity properties are enhanced by suitable surfactants and hydrophobically modified polymers can be used, such as cases where a charged polymer in the presence of a surfactant having a charge that is opposite to that of the charged polymer, the surfactant being capable of forming an ion-pair association with the polymer resulting in a hydrophobically modified polymer having a plurality of hydrophobic groups. [0019] In some embodiments, the viscosifier is a water-dispersible, nonionic, hydroxyalkyl galactomannan polymer or a substituted hydroxyalkyl galactomannan polymer. Examples of useful hydroxyalkyl galactomannan polymers include, but are not limited to, hydroxy-Cl -C4- alkyl galactomannans, such as hydroxy-Cl-C4-alkyl guars. Examples of such hydroxyalkyl guars include hydroxyethyl guar (HE guar), hydroxypropyl guar (HP guar), and hydroxybutyl guar (HB guar), and mixed C2-C4, C2/C3, C3/C4, or C2/C4 hydroxyalkyl guars. Hydroxymethyl groups can also be present in any of these.

[0020] As used herein, substituted hydroxyalkyl galactomannan polymers are obtainable as substituted derivatives of the hydroxy-Cl-C4-alkyl galactomannans, which include: 1) hydrophobically-modified hydroxyalkyl galactomannans, e.g., Cl-C18-alkyl-substituted hydroxyalkyl galactomannans, e.g., wherein the amount of alkyl substituent groups can be about 2% by weight or less of the hydroxyalkyl galactomannan; and 2) poly(oxyalkylene)- grafted galactomannans. Poly(oxyalkylene)-grafts thereof can comprise two or more than two oxyalkylene residues; and the oxyalkylene residues can be C1-C4 oxyalkylenes. Mixed- substitution polymers comprising alkyl substituent groups and poly(oxyalkylene) substituent groups on the hydroxyalkyl galactomannan are also useful herein. In various embodiments of substituted hydroxyalkyl galactomannans, the ratio of alkyl and/or poly(oxyalkylene) substituent groups to mannosyl backbone residues can be about 1 :25 or less, i.e. with at least one substituent per hydroxyalkyl galactomannan molecule; the ratio can be: at least or about 1 :2000, 1 :500, 1 : 100, or 1 :50; or up to or about 1 :50, 1 :40, 1:35, or 1 :30. Combinations of galactomannan polymers can also be used.

[0021] As used herein, galactomannans comprise a polymannose backbone attached to galactose branches that are present at an average ratio of from 1 : 1 to 1 :5 galactose branches:mannose residues. Galactomannans useful herein can comprise a l→4-linked 13-D- mannopyranose backbone that is l→6-linked to a-D-galactopyranose branches. Galactose branches can comprise from 1 to about 5 galactosyl residues; in various embodiments, the average branch length can be from 1 to 2, or from 1 to about 1.5 residues. Branches can be monogalactosyl branches. In various embodiments, the ratio of galactose branches to backbone mannose residues can be, approximately, from 1 : 1 to 1 :3, from 1 : 1.5 to 1 :2.5, or from 1 : 1.5 to 1 :2, on average. In various embodiments, the galactomannan can have a linear polymannose backbone. The galactomannan can be natural or synthetic. Natural galactomannans useful herein include plant and microbial (e.g., fungal) galactomannans. In various embodiments, legume seed galactomannans can be used, examples of which include, but are not limited to: tara gum (e.g., from Cesalpinia spinosa seeds) and guar gum (e.g., from Cyamopsis tetragonoloba seeds). In addition, although embodiments may be described or exemplified with reference to guar, such as by reference to hydroxy-Cl-C4-alkyl guars, such descriptions apply equally to other galactomannans, as well.

[0022] The mixture can further comprise any one or combination of the following: an alcohol having from 1 1 to 14 carbon atoms per molecule, and which is both ethoxylated and butoxylated; tetramethyl ammonium chloride; and an ammonium persulfate breaker. The ammonium persulfate breaker can be selected from the group consisting of diammonium peroxidisulphate, encapsulated ammonium persulfate, and combinations thereof.

[0023] In accordance with an embodiment, a method of treating a subterranean formation penetrated by a wellbore is disclosed, comprising, consisting of or consisting essentially of: a. preparing a dry mixture of boric acid; sodium tetraborate pentahydrate; and a pH adjusting agent selected from the group consisting of calcium hydroxide, potassium hydroxide, sodium hydroxide, potassium carbonate, an amine containing compound, or a combination thereof; b. combining the dry mixture with a viscosified fluid medium comprising a hydrocarbon fluid and an organophilic clay to form the composition as described herein; c. combining the composition with the mixture comprising a viscosifier and aqueous medium, as described herein, to form the treatment fluid as described herein; and d. contacting the formation with the treatment fluid to treat the formation.

[0024] In accordance with an embodiment, a method of preparing the composition as described herein is disclosed, comprising: a. preparing a dry mixture of boric acid; sodium tetraborate pentahydrate; and a pH adjusting agent selected from the group consisting of calcium hydroxide, potassium hydroxide, sodium hydroxide, potassium carbonate, an amine containing compound, or a combination thereof; and b. combining the dry mixture with a viscosified fluid medium comprising the hydrocarbon fluid and the organophilic clay to form the composition.

[0025] Fluids incorporating polymer based viscosifiers may have any suitable viscosity, such as a viscosity value of about 50 mPa-s or greater at a shear rate of about 100 s— 1, or about 75 mPa-s or greater at a shear rate of about 100 s-1, or about 100 mPa-s or greater at a shear rate of about 100 s-1 , at treatment temperature as described herein. [0026] The fluid may be nonfoamed, foamed, or energized, depending upon the particular formation properties and treatment objective. When incorporated, a gas component can be included and can be produced from any suitable gas that forms a foam or an energized fluid when introduced into the aqueous medium. The gas component comprises a gas selected from the group consisting of nitrogen, air, carbon dioxide and any mixtures thereof. The gas component may in some cases assist in a fracturing operation and/or well clean-up process. The fluid may contain from about 10% to about 90% volume gas component based upon total fluid volume percent, or from about 30% to about 80% volume gas component based upon total fluid volume percent, or from about 40% to about 70% volume gas component based upon total fluid volume percent. [0027] The treatment fluid may further contain other additives and chemicals. These include, but are not necessarily limited to, materials such as surfactants, breakers, breaker aids, oxygen scavengers, alkaline pH adjusting agents, clay stabilizers (i.e. KC1, TMAC), high temperature stabilizers, alcohols, proppant, scale inhibitors, corrosion inhibitors, fluid-loss additives, bactericides, and the like. In some embodiments, one, a portion, or all of these components may be encapsulated. Also, they may include a co-surfactant to optimize viscosity or to minimize the formation of stable emulsions that contain components of crude oil.

[0028] The treatment of the subten anean formation can be a hydraulic fracturing treatment of the subterranean formation. Techniques for hydraulically fracturing a subterranean formation will be known to persons of ordinary skill in the art, and will involve pumping the fracturing fluid into the borehole and out into the surrounding formation. The fluid pressure is above the minimum in situ rock stress, thus creating or extending fractures in the formation. See Stimulation Engineering Handbook, John W. Ely, Pennwell Publishing Co., Tulsa, Okla. (1994), U.S. Pat. No. 5,551,516 (Normal et al.), "Oilfield Applications", Encyclopedia of Polymer Science and Engineering, vol. 10, pp. 328-366 (John Wiley & Sons, Inc. New York, N.Y., 1987) and references cited therein, the disclosures of which are incorporated herein by reference thereto.

[0029] In most cases, a hydraulic fracturing consists of pumping a proppant-free viscous fluid, or pad, usually water with some fluid additives to generate high viscosity, into a well faster than the fluid can escape into the formation so that the pressure rises and the rock breaks, creating artificial fractures and/or enlarging existing fractures. Then, proppant particles are added to the fluid to form a slurry that is pumped into the fracture to prevent it from closing when the pumping pressure is released. The proppant suspension and transport ability of the treatment base fluid traditionally depends on the type of viscosifying agent added.

[0030] In the fracturing treatment, fluids such as the treatment fluids described hererin may be used in the pad treatment, the proppant stage, or both. The components of the treatment fluid may be mixed on the surface. Alternatively, a portion of the treatment fluid may be prepared on the surface (such as the composition and/or the mixture as described herein) and pumped down tubing while another portion could be pumped down the annular to mix down hole.

[0031] Another embodiment includes the use of treatment fluids as described herein for cleanup. The term "cleanup" or "fracture cleanup" refers to the process of removing the fracture fluid (without the proppant) from the fracture and wellbore after the fracturing process has been completed. Techniques for promoting fracture cleanup traditionally involve reducing the viscosity of the fracture fluid as much as practical so that it will more readily flow back toward the wellbore.

[0032] In another embodiment, slurries and fluids as described herein are useful for gravel packing a wellbore. As a gravel packing fluid, it can comprise gravel or sand and other optional additives such as filter cake clean up reagents such as chelating agents referred to above or acids (e.g. hydrochloric, hydrofluoric, formic, acetic, citric acid) corrosion inhibitors, scale inhibitors, biocides, leak-off control agents, among others. For this application, suitable gravel or sand is typically having a mesh size between 8 and 70 U.S. Standard Sieve Series mesh. [0033] The following examples are presented to illustrate the preparation and properties of some embodiments of the disclosure, and should not be construed to limit the scope, unless otherwise expressly indicated in the appended claims. All percentages, concentrations, ratios, parts, etc. are by weight unless otherwise noted or apparent from the context of their use.

5 EXAMPLES

[0034] A slurry crosslinker composition was prepared in accordance with the disclosure, and with the component amounts as shown in Table 1 below.

Table 1: Slurry crosslinker composition

Component Concentration

(w/w%)

Boric Acid <200mesh, 200-400mesh 7.17

Sodium tetraborate pentahydrate 400-5 OOmesh 7.17

Calcium hydroxide <325 mesh 2.33

Diesel 79.37

Organophilic clay 3.97

0

[0035] Several fracturing fluid formulations were prepared in accordance with the disclosure for rheology testing, in the amounts shown in Table 2.

Table 2: Fracturing Fluid Formulation for testing

Formulation

Component

A B C D E F

High Yield Guar Gelling

14 ppt 16ppt 18ppt 16 ppt 16 ppt 16 ppt Agent

Coalbed Methane

Additive, Alcohols, Cl l-

2 gpt 2gpt 2gpt gpt 2 gpt 2gpt 14-isoalky], C13-rich,

butoxylated, ethoxylated

Tetra methyl ammonium

- - - gpt 2 gpt 2gpt chloride, 50% Slurry Crosslinker

i gpt 1.5gpt 2gpt 2 gpt 2 gpt 2gpt

(from Table 1 )

Diammonium

5 ppt - Peroxidisulphate

20/40 mesh Encapsulated 6 ppt 6 ppt

Ammonium Persulfate (uncrushed) (crushed)

**ppt = lbm/lOOOgal

**gpt = gal/1000gal

[0036] FIG. 1 shows the fluid rheology profiles of the fracturing fluid formulations A, B and 5 C using polymer loading varying from 14 lb_m/1000gal to 181b_m/1000gal. The fluid formulations each show a viscosity higher than lOOcP @100sec-l when tested at 68°F (20°C).

[0037] FIG. 2 shows that fracturing fluid formulations A, B and C (each having low polymer loadings) have acceptable shear recovery.

[0038] FIG. 3 shows that the crosslinked fluid formulations D, E and F can be broken by0 using encapsulated ammonium persulfate breakers which have been crushed (formulation F) and by using unencapsulated ammonium persulfate breakers (formulation C) when tested at 68°F (20°C).

[0039] The particular embodiments disclosed above are illustrative only, as the disclosures may be modified and practiced in different but equivalent manners apparent to those skilled in5 the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details herein shown, other than as described in the claims below. It is therefore evident that the particular embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the disclosure. Accordingly, the protection sought herein is as set forth in the claims below.

Claims

We claim:

1. A method of treating a subterranean formation penetrated by a wellbore, the method comprising: a. utilizing a composition comprising: boric acid; sodium tetraborate pentahydrate; a pH adjusting agent; a hydrocarbon fluid; and an organophilic clay; b. combining the composition with a mixture comprising a viscosifier and an aqueous medium to form a treatment fluid; and c. contacting the formation with the treatment fluid to treat the formation.

2. The method of claim 1 , wherein the pH adjusting agent is selected from the group consisting of calcium hydroxide, potassium hydroxide, sodium hydroxide, potassium carbonate, an amine containing compound, or a combination thereof; and the hydrocarbon fluid is diesel.

3. The method of claim 2, wherein: the boric acid is present in the composition in an amount of from about 6% to about 13%, by weight, based upon total weight of the composition; the sodium tetraborate pentahydrate is present in the composition in an amount of from about 6% to about 13%, by weight, based upon total weight of the composition; the pH adjusting agent is present in the composition in an amount of from about 2% to about 5%, by weight, based upon total weight of the composition; the diesel is present in the composition in an amount of from about 65% to about 85%, by weight, based upon total weight of the composition; and the organophilic clay is present in the composition in an amount of from about 3% to about 4.5%, by weight, based upon total weight of the composition.

4. The method of any one of claims 1 - 3, wherein the composition is added to the mixture in an amount of from about 0.5 to about 3 gallons per thousand gallons of the mixture.

5. The method of any one of claims 1 - 4, wherein the boric acid, the sodium tetraborate pentahydrate, and the pH adjusting agent are dry mixed to form a dry mixture, the organophilic clay is added to the hydrocarbon fluid to form a viscosified fluid medium; and the dry mixture is combined with the viscosified fluid medium to form the composition.

6. The method of any one of claims 1 - 5, wherein the viscosifier comprises a hydrated polymer selected from the group consisting of guar, high-molecular weight polysaccharides composed of mannose and galactose sugars, guar derivatives such as hydroxypropyl guar (HPG), carboxymethyl guar (CMG), and carboxymethylhydroxypropyl guar (CMHPG), synthetic polymer, cellulose derivatives, synthetic polymer, guar-containing compounds, and combinations thereof.

7. The method of any of claims 1 - 6, wherein the viscosifier is present in the treatment fluid in an amount of at most 18 pounds per thousand gallons of the treatment fluid.

8. The method of any of claims 1 - 7, wherein the temperature of the subterranean formation treated with the treatment fluid is at most 30°C.

9. The method of any one of claims 1 - 8, wherein the mixture further comprises an alcohol having from 1 1 to 14 carbon atoms per molecule, and which is both ethoxylated and butoxylated.

10. The method of any one of claims 1 - 9, wherein the mixture further comprises tetramethyl ammonium chloride.

1 1. The method of any one of claims 1 - 10, wherein the mixture further comprises an ammonium persulfate breaker.

12. The method of claim 1 1 wherein the ammonium persulfate breaker is selected from the group consisting of diammonium peroxidisulphate, encapsulated ammonium persulfate, and combinations thereof.

13. The method of any one of claims 1 - 12, wherein the composition comprises less than about 10% water, by weight, based upon total weight of the composition.

14. A method of treating a subterranean formation penetrated by a wellbore, comprising: a. preparing a dry mixture of boric acid; sodium tetraborate pentahydrate; and a pH adjusting agent selected from the group consisting of calcium hydroxide, potassium hydroxide, sodium hydroxide, potassium carbonate, an amine containing compound, or a combination thereof; b. combining the dry mixture with a viscosified fluid medium comprising a hydrocarbon fluid and an organophilic clay to form a composition; c. combining the composition with a mixture comprising a viscosifier and aqueous medium to form a treatment fluid; and d. contacting the formation with the treatment fluid to treat the formation.

15. The method of claim 14, wherein the hydrocarbon fluid is diesel.

16. The method of claim 15, wherein: the boric acid is present in the composition in an amount of from about 6% to about 13%, by weight, based upon total weight of the composition; the sodium tetraborate pentahydrate is present in the composition in an amount of from about 6% to about 13%, by weight, based upon total weight of the composition; the pH adjusting agent is present in the composition in an amount of from about 2% to about 5%, by weight, based upon total weight of the composition; the diesel is present in the composition in an amount of from about 65% to about 85%, by weight, based upon total weight of the composition; and the organophilic clay is present in the composition in an amount of from about 3% to about 4.5%, by weight, based upon total weight of the composition.

17. The method of any one of claims 14 - 16, wherein the composition is added to the mixture in an amount of from about 0.5 to about 3 gallons per thousand gallons of the mixture.

18. The method of any one of claims 14 - 17, wherein the viscosifier comprises a hydrated polymer selected from the group consisting of guar, high-molecular weight polysaccharides composed of mannose and galactose sugars, guar derivatives such as hydroxypropyl guar (HPG), carboxymethyl guar (CMG), and carboxymethylhydroxypropyl guar (CMHPG), synthetic polymer, cellulose derivatives, synthetic polymer, guar-containing compounds, and combinations thereof.

19. The method of any of claims 14 - 18, wherein the viscosifier is present in the treatment fluid in an amount of at most 18 pounds per thousand gallons of the treatment fluid.

20. The method of any of claims 14 - 19, wherein the temperature of the subterranean formation treated with the treatment fluid is at most 30°C.

21. The method of any one of claims 14 - 20, wherein the mixture further comprises an alcohol having from 1 1 to 14 carbon atoms per molecule, and which is both ethoxylated and butoxylated.

22. The method of any one of claims 14 - 21, wherein the mixture further comprises tetramethyl ammonium chloride.

23. The method of any one of claims 14 - 22, wherein the mixture further comprises an ammonium persulfate breaker selected from the group consisting of diammonium

peroxidisulphate, encapsulated ammonium persulfate, and combinations thereof.

24. The method of any one of claims 14 - 23, wherein the composition comprises less than about 10% water, by weight, based upon total weight of the composition.

25. A method of preparing a composition, comprising: a. preparing a dry mixture of boric acid; sodium tetraborate pentahydrate; and a pH adjusting agent selected from the group consisting of calcium hydroxide, potassium hydroxide, sodium hydroxide, potassium carbonate, an amine containing compound, or a combination thereof; and b. combining the dry mixture with a viscosified fluid medium comprising a hydrocarbon fluid and an organophilic clay to form the composition.

26. The method of claim 25, wherein the hydrocarbon fluid is diesel.

27. The method of claim 26, wherein: the boric acid is present in the composition in an amount of from about 6% to about 13%, by weight, based upon total weight of the composition; the sodium tetraborate pentahydrate is present in the composition in an amount of from about 6% to about 13%, by weight, based upon total weight of the composition; the pH adjusting agent is present in the composition in an amount of from about 2% to about 5%, by weight, based upon total weight of the composition; the diesel is present in the composition in an amount of from about 65% to about 85%, by weight, based upon total weight of the composition; and the organophilic clay is present in the composition in an amount of from about 3% to about 4.5%, by weight, based upon total weight of the composition.

28. The method of any one of claims 25 - 27, wherein the composition comprises less than about 10% water, by weight, based upon total weight of the composition.