EA009529B1 - Improved fracturing fluid and method of use - Google Patents

Abstract

Improved aqueous fracturing fluids are disclosed that are useful to fracture tight (low permeability) subterranean formations. Gas wells treated with these fracturing fluids have rapid cleanup and enhanced production. The fluids contain small but sufficient amounts of certain amine oxides to aid in the removal of fracturing fluid from the formation. By facilitating the removal of fluid from invaded zones, the damage to fracture faces in the formation is minimized. The amine oxides correspond to formula I, wherein Ris an aliphatic group of from 6 to about 20 carbon atoms, and Rand Rare each independently alkyl of from 1 to about 4 carbon atoms. The amine oxides in which Ris an alkyl group are preferred, and those in which Ris an alkyl group of from 8 to 10 carbon atoms and Rand Rare each methyl or ethyl groups are most preferred.

Description

The scope of the invention

Improved hydraulic fracturing aqueous fluids have now been discovered, which are particularly useful as well stimulating fluids in the case of subterranean formations with closed fractures (low permeability). Gas wells treated with such fracturing fluids are characterized by quick pumping to obtain a clean product (s1eapir) and increased well productivity. Fluids contain small but sufficient amounts of certain amino oxides to help remove frac fluid from the formation. Facilitating the removal of fluid from the penetration zone, fracture surfaces of cracks in the formation are minimized.

BACKGROUND OF THE INVENTION

Various amino oxides have been used as surfactants to create foams and remove “embedded fluids from wellbores” according to US Pat. No. 3,303,896; they were also used as foam stabilizers according to US Pat. No. 3,317,430. Certain amino oxides were also used in combination with quaternary ammonium compounds as foaming agents and sludge suspending agents. See, for example, US Patent No. 4108782 and No. 4113631. The use of amine oxide surfactants when injecting chemical solutions into the formation to increase oil recovery is described in the thematic report of Bau1b K. O1kep in ΝΙΡΕΚ-417 (August 1989) on the work performed for the US Department of Energy on the basis of a joint agreement BE-EU22-63EЕ60149 with the National Institute for Oil and Energy Research (Ναΐίοηαΐ 1пк1йи1е £ ogo Re1go1eit apb Epegdu Kekeages). However, as is known to the applicants, amine oxides were not used to improve the properties of fracturing fluids and to facilitate rapid pumping to obtain a clean product, or to increase the productivity of a fractured well.

Hydraulic fracturing of underground rocks has long been known as an effective means of stimulating the production of hydrocarbon fluids from a wellbore. In case of hydraulic fracturing, the fluid for stimulating inflow into the well (usually referred to as the so-called fluid for hydraulic fracturing or “hydraulic fracturing”) is injected in and through the wellbore and overcoming the resistance of the surface of the underground formation through which the wellbore passes, at least enough pressure to create cracks in the formation. Typically, a “cushion fluid” is first injected (slave Di1b) to create a fracture, and then hydraulic fracturing fluid, often containing a granular proppant, is injected under pressure and at a rate sufficient to extend the fracture from the wellbore deeper into the formation. If a proppant is used, the task is usually to create a zone filled with a proppant (otherwise called a proppant barrier) from the top of the fracture back to the wellbore. In any case, a hydraulically generated fracture is more permeable than the formation itself and acts as a path or channel for hydrocarbon fluids in the formation to flow into the wellbore and then to the surface where they are collected. Fracturing methods are well known and can be varied to meet customer requirements, but most of them follow this basic operation (which is overly simplified).

The fluids used as fracturing fluids have also been modified, but many, if not most of them, are water-based fluids that have “thickened” or made more viscous by adding natural or synthetic polymers (crosslinked or non-crosslinked). The carrier fluid is usually water or brine (for example, dilute aqueous solutions of sodium chloride and / or potassium chloride). The thickening polymer is usually a soluble (or hydratable) polysaccharide, such as galakotmannanoy resin, glycomannan resin or a cellulose derivative. Examples of such polymers include guar gum, hydroxypropyl guar gum, carboxymethyl guar gum, carboxymethyloxyethyl guar gum, hydroxyethyl cellulose, carboxymethyloxyethyl cellulose, hydroxypropyl cellulose, xanthan, and other polymers. Among them, guar gum, hydroxypropyl guar gum derivative and carboxymethyloxyethyl guar gum are generally preferred because of their commercial availability and cost characteristics.

In many examples, if not most, the thickener polymer is crosslinked with a suitable crosslinking agent. A crosslinked polymer has an even higher viscosity, and it is even more effective in transferring a proppant inside a fractured rock. As a cross-linking agent, borate ion was widely used, usually in high pH liquids, for guar gum, derivatives of guar gum and other galactomannans. See, for example, US Patent No. 3059909 and a number of other patents that describe this classic aqueous gel as a fracturing fluid. Other crosslinking agents include, for example, crosslinking agents based on titanium (US Pat. No. 3,888,312), chromium, iron, aluminum and zirconium (US Pat. No. 3,301,723). Among them, titanium and zirconium crosslinking agents are usually preferred. Examples of commonly used zirconium-based crosslinking agents include complexes of zirconium triethanolamine, zirconium acetylacetonate, zirconium lactate, zirconium carbonate and chelates (cie1ap!) Of organic alpha-hydroxycarboxylic acid (a1рйайу

- 1 009529 bogusus boghuis ac1b) and zirconium. Examples of commonly used titanium-based crosslinking agents include complexes of titanium triethanolamine, titanium acetylacetonate, titanium lactate, and organic alpha hydroxycarboxylic acid and titanium chelates.

Additional information on fracturing can be found in the description of 1ae1 Si1b | 8 and Kxjagb M. Nobde in Ch. 7 of the “Stimulation stimulation” guide / Kegeguo1 g 811t1a1yup published by 1o1t \ UP1su & 8opk, Yb, Tygb Yebuyp, 2000 (Publishers Muyaye 1. Esopot1be§ and Keppey S. Yoye), which is incorporated here by reference. Some fracturing fluids were also given greater activity by adding gas (e.g. nitrogen or carbon dioxide) to create a foam. See, for example, the pioneering work of Co1apb E. B1aieg and C1agepse 1. Engbogsau in US Pat. No. 3,937,283 (“Hydraulic fracturing by stable foams” / Gogtlüp Ggasligss \ νί11ι 81а1е Goatk). The rheology of traditional water-based polymer solutions, as well as complex liquids such as foams, can, as is usually done, be modified and strengthened with some additives to control their characteristics. Fluid filtration reducing additives are typically added to reduce fracturing fluid loss within the formation.

The problems associated with the loss of fracturing fluids within the formation are well known. For example, in 1978 Holditch (No1bysy) reported: “The fluid injected during processing for hydraulic fracturing seeps into the formation and reduces the relative gas permeability in the area of its penetration. Near a crack, gas permeability decreases to zero. " In addition, Holditch said: "In some cases, injection fracturing fluid can reduce the permeability of the formation in the penetration zone." 81erNep A. No1bysy, 8RE 7561 (presented at the 53rd Annual Autumn Technical Conference and Exhibition of the Society of Petroleum Engineers of the American Institute of Mining Engineers, held in Houston, Texas, October 1-3, 1978). Damage to the formation could be significant, which practically meant a decrease in hydrocarbon flow, low productivity and low profitability of the well. Despite the fact that the current level of technology has improved significantly since Holditch reported problems associated with the leakage of fracturing fluid, the same problems remain. See, for example, Vegpop S. SopShep, Seogde ^. On ^ kshk, V.K. Rgibotte and K.esha1bo №1uagge1e. ch. 8, entitled “Characteristics of Materials for Hydraulic Fracturing of a Formation“ RegGogtapse ok Ggasigtd Ma1epa1k ”and other chapters on formation of fractures in a reservoir and stimulation of inflow into a well in“ Stimulation of a Formation ”/ K.Ke8eguo1g 811ti1a1yup, published by 1Онп \ УП1е & 8 , Tybb Ebyup, 2000 (Publishers M1syae1 1. Esopot1be§ and KepieN S. YoNe), the description of which is incorporated herein by reference. These and other authors emphasize the importance of “fast pumping to obtain a clean product” or “fast pumping from a fracture to a clean product” to optimize the production rate of hydrocarbon fluids from a well. The term “quick pumping to obtain a clean product” or “fast pumping from a crack to a clean product” refers to the process of removing hydraulic fracturing fluid (without proppant) from the cracks after completion of the hydraulic fracturing process. Techniques to facilitate rapid pumping from fractures to produce a clean product often include lowering the fracture fluid viscosity as much as practicable so that it more easily flows back toward the wellbore. In many examples, so-called “thinners” were used to lower the viscosity of the liquid. The diluents can be enzymes (oxidizing agents and oxidizing agents), and they can be encapsulated to slow their release. See, for example, U.S. Patent 4,741,401 (\ Wa11eek e! A1.), Owned by 8CITBegdeo Eo \\ 'e11 and incorporated herein by reference. Another technique for implementing fast pumping to obtain a pure product, albeit with the opposite approach, was found in U.S. Pat.

There is still a need for improved fracturing fluids, and the following invention partially satisfies this need.

Disclosure of invention

Improved hydraulic fracturing aqueous fluids have now been discovered, which are particularly useful as well stimulating fluids in the case of subterranean formations with closed fractures (low permeability). Gas wells treated with such fracturing fluids are characterized by quick pumping to obtain a clean product and increased well productivity. The fluids contain small amounts of some amino oxides that are small but sufficient to help remove frac fluid from the formations. Facilitating the extraction of fluid from the penetration zone, fracture surfaces of cracks in the formation are minimized. Amino oxides correspond to the formula

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I _r (formula I) where K | is an aliphatic group having from 6 to about 20 carbon atoms, and where each of B ₂ and B ₃ independently is alkyl having from 1 to about 4 carbon atoms. Amino oxides in which B ₁ is an alkyl group are preferred, and particularly preferred are amine oxides in which B ₁ is an alkyl group having from 8 to 12 carbon atoms (in particular where B ₁ is a linear alkyl group), and each of B ₂ and B ₃ is methyl or ethyl groups.

Brief Description of the Drawings

In FIG. 1 shows the dependence of gas permeability on chain length. This drawing shows a graph of the degree of restoration of permeability on the chain length of aliphatic groups, In ₁ , some amino oxides.

DETAILED DESCRIPTION OF THE INVENTION

The amino oxides used in the present invention are known compounds, and many of them are commercially available. They can be obtained by various methods, one of which consists in the interaction of a tertiary amine (corresponding to the formula Β ₁ Β ₂ Β ₃ Ν, where B ₁ , B ₂ and B _{3 are} defined above) with peroxide in a suitable aqueous reaction medium. Products formed in this way are aqueous liquids containing up to 30 wt.% Amino oxides. Aqueous solutions of amino oxides are a simple and preferred form of the product in this invention because they are easy to pump or otherwise dispense into a fracturing fluid or mixed with other components of the fracturing fluid.

Examples of amino oxides of Formula I above include, but are not limited to, such amino oxides in which B ₁ is a straight chain alkyl group of 8 to 20 carbon atoms (e.g., octyl, nonyl, decyl, dodecyl, tetradecyl, octadecyl, and the like) or a straight chain alkenyl group of 8 to 20 carbon atoms (e.g. oleyl, erucyl, etc.), and each of B ₂ and B ₃ is methyl, ethyl, n-butyl or 2 a hydroxyethyl group. The most preferred amino oxides are n-octyldimethylamine oxide and n-decyldimethylamine oxide. While all amino oxides of Formula I could reasonably be classified as surfactants, many of them are known as foaming agents, but preferred amino oxides for use in the present invention (e.g. n-octyldimethylamine oxide and n-decyldimethylamine oxide), in particular are not effective foaming agents. For example, preferred amino oxides have a foam half-life of less than one (1) min when tested in a 2% aqueous potassium chloride solution (2% KCl), 3% hydrochloric acid solution, 0.2% aqueous solution of tetramethylammonium chloride, or ΑΡΙ brine (American Petroleum Institute). The half-life of the foam is determined using tests that are established in US patent No. 4108782, count. 5 and 6, entitled “Testing the Volume of the Initial Foam” and “Testing the Half-Life of the Foam,” the description of which is incorporated herein by reference. Thus, the preferred amino oxides do not contribute to the formation of emulsions (foams are a type of emulsion) in the presence of fracturing fluids, and they provide the desired change (i.e., increase) in the wetting angle.

Amino oxides are added to the fracturing fluids in small but sufficient quantities to facilitate rapid pumping to a pure product. Usually they are added in the form of aqueous solutions in amounts of from about 0.01 to about 1 wt.% Amino oxide, based on the mass ratio (g / g) and preferably from about 0.006 to 0.024 wt.%. Amino oxides can be added to the fracturing fluid “during processing”, i.e. as it is injected into the wellbore, or amine oxides can be added to the so-called "tanks for the preparation of fracturing fluid" in which water is stored to prepare the fracturing fluid. The order in which the amine oxide is added to the fracturing fluid is not critical. Amino oxides, apparently, are compatible mainly with all ingredients of the fracturing fluid, as far as the inventors are aware of this. They are compatible with acids (such as hydrochloric acid), and therefore, they can be used in so-called “acid hydraulic fracturing” works when aqueous acid is used as a fracturing fluid (usually in the presence of acid inhibitors). Amino oxides are also compatible with bases and can be used in hydraulic fracturing fluids having an alkaline pH, which is common for hydraulic fracturing fluids containing guar gum or guar gum derivatives (eg, hydroxypropyl guar gum derivative (“OPG”), carboxymethyl guar gum derivative, carboxymethyl-hydroxypropyl derivative of guar gum (“CMOS”) as thickeners, these liquids can be crosslinked with borates or zirconium or titanium crosslinking agents, as well as other different visibility). Typically, fracturing fluids have a pH in the range of

- 3 009529 le from about 4 to 12, and in such liquids amino oxides can be used. Alkaline pH fracturing fluids are generally more thermally stable and are thus generally preferred for use in hydraulic fracturing with low permeability. The fracturing fluids of the present invention may also contain other additives commonly found in fracturing fluids. For example, proppants, other additives to reduce their filtration, anti-emulsifiers (Pop-Shetik), thinning systems, formation stabilizers, bactericides, etc.

The fracturing fluids of the present invention are used in accordance with known fracturing operations in subterranean formations. See, for example, hydraulic fracturing operations established in the Stimulation Guide (YaekeguoYa 811i1a1yup) cited above.

Examples of the invention

The following examples will further illustrate the invention.

Examples 1-9.

Various amino oxides and one commercial fluorocarbon surfactant (referred to as Ρ75Ν, not an example of the invention) were tested in some liquids in a core filtration study using the operations below. Each amino oxide corresponded to formula 1

P ₂ where each of Z ₂ and Z ₃ is methyl, and K. ₁ is n-octyl, n-decyl, n-dodecyl, ntetradecyl, n-hexadecyl, oleyl or erucil (the last two groups are alkenyl groups 18 and 22 carbon atoms, respectively). The data are presented in FIG. 1, where white circles refer to restoration of brine flow filtration, and black squares relate to restoration of nitrogen filtration. Detailed core filtering studies are presented below. The data show that amino oxides provide a degree of reduction that varies with the chain length of the aliphatic group I! in amine oxide. Surprisingly, those amino oxides in which the aliphatic group H1 has from 8 to 10 carbon atoms exhibit better characteristics (for example, a higher degree of reduction) than the commercial surfactant Ρ75Ν, one of the best additives in the technology of promoting fast pumping to obtain a pure product . The data in FIG. 1 also show that it is possible to change the pumping rate to obtain a pure product or to restore permeability by choosing amino oxide with different chain lengths for the aliphatic group H1. This provides the user with a means of changing the rate at which fast pumping is achieved until a clean product is obtained and a well is developed. For example, if it is desired to achieve a high rate of fast pumping to obtain a pure product and productivity, the user would select an amino oxide with fewer carbon atoms in H1 (for example, n-octyl or n-decyl). If the user wants to have a low rate of fast pumping to obtain a pure product (for example, to prevent the formation of ducts and the possible incomplete return of the fracturing fluid), then he could choose an amino oxide with a large number of carbon atoms in H1 (for example, n-hexadecyl, n- octadecyl or oleyl). It is expected that mixtures of such amino oxides could also be used to achieve any particular desired fast pumping result to obtain a pure product. The ability to change the rate of selection and achieve predictable and controlled methods for rapidly pumping fluids to stimulate the formation to produce a clean product to improve gas permeability after processing is a useful tool in the engineer’s arsenal. Amino oxides are more environmentally friendly than commercial fluorocarbon surfactants (Ρ75Ν), and cost effective. It was also noted that amino oxides in which H1 has a greater number of carbon atoms (for example, either 18 or more) were both viscoelastic and surface-active. This combination of surface activity and viscoelasticity makes these amine oxides effective in well treatment where friction reduction and optimal quick pumping to a pure product are especially desirable. The industry provides such fracturing fluids (for example, aqueous viscoelastic fluids that do not contain guar gum or any derivative of guar gum) under the designation “water with a small amount of non-crosslinked polymer” (811 cg).

Core Filtration Study for Amino Oxide Assessment

Brine Filtration:

1. Pre-impregnate (rge-regt) dry cores with nitrogen to level (that! Her) cores.

2. Saturate the cores with deionized water with 2% No. C1.

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3. Determine the initial permeability of 2% No. 1C1 when filtering in the forward direction for a total of 25 pore volumes.

4. Pump the surfactant solution in the opposite direction for a total of five (5) pore volumes.

5. Determine the restored permeability of 2% No. 1C1 in the forward direction for a total of 25 pore volumes.

6. Determine the ratio of the restored permeability at 2% No. 1С1 to the initial permeability at 2% NaCl.

Kerosene Filtration:

1. Pre-impregnate dry cores with nitrogen to level the cores.

2. Saturate the cores with deionized water with 2% No. C1.

3. Determine the initial permeability of 2% No. 1C1 when filtering in the forward direction for a total of 25 pore volumes.

4. Pump the surfactant solution in the opposite direction for a total of five (5) pore volumes.

5. Determine the restored kerosene permeability in the forward direction for a total of 25 pore volumes.

6. To determine the ratio of the restored kerosene permeability to the initial permeability by 2% NaCl.

Nitrogen Filtration:

1. Pre-impregnate (rge-regt) dry cores with nitrogen to level the cores.

2. Soak the cores with deionized water with 2% No. 1C1.

3. Determine the initial permeability of 2% No. 1C1 when filtering in the forward direction for a total of 25 pore volumes.

4. Pump the surfactant solution in the opposite direction for a total of five (5) pore volumes.

5. Determine the restored nitrogen permeability in the forward direction at 0.7 MPa (100 psi) for a total time equivalent to 25 pore volumes of brine at 1.0 ml / min (+/- 140 min).

6. Determine the ratio of the restored nitrogen permeability to the initial permeability at 2% NaCl.

Pore volume calculations:

Assumption:

Porosity is 15%

Equation for volume:

SU = {3.1416 (O ² ) b} / 4 RU = SU (porosity) / 100 where RU is the pore volume in cm ³ ,

SU is the core volume in cm ³ ,

Ό is the core diameter in cm and

B is the core length in cm.

The above equation, with an assumed porosity of 15%, gives a pore volume of 1.93 cm ³ per 2.54 cm (one inch) of core length. For simplicity, the pore volume will be rounded to 2 cm ³ per 2.54 cm (one inch) of core length.

Example 10

A gas well is drilled into the Lobo 6 formation in western Texas to a depth of approximately 2865.12 m (9400 ft). The productive zone is in sandstone with low permeability. The temperature at the bottom of the well is approximately 115.5 ° C (240P) and the pressure in the reservoir is approximately 30.7 MPa (4450 psi). The well is traditionally cemented and perforated using 4 holes per 0.305 m (1 ft) interval. The well is ruptured with dilute hydrochloric acid and plugged (ba11eb oi1). Obviously, all openings accept fluid. Then, the well is stimulated by hydraulic fracturing, injecting sequentially, with an injection rate of 4451.7 (28 barrels) per minute (BVM), cushion fluid, hydraulic fracturing fluid with a proppant, and washed with a fluid stream according to the injection scheme shown in the table below. one.

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Table 1

Stage Liquid Stage volume, L (gallons) Proppant stage * Average discharge pressure, MPa (psi) Concentration, kg (lb) DRA kg (Pounds) one Fluid A 870555 (23,000) 0,0 0,0 48,825 (6975) 2 Fluid A 15140 (4000) 0.908 (2.0) 3628.7 (8,000) 49,455 (7065) 3 Fluid A 15140 (4000) 1,361 (3.0) 5443 (12,000) 49.7 (7100) 4 Fluid A 18925 (5000) 1,814 (4.0) 9072 (20,000) 50,505 (7215) 5 Fluid B 30280 (8000) 2,268 (5.0) 18144 (40,000) 47.25 (6750) 6 Fluid B 37850 (10000) 2,722 (6.0) 27216 (60,000) 44.38 (6340) 7 Fluid B 15140 (4000) 3,175 (7.0) 12701 (28,000) 45.22 (6460) 8 Fluid B 15140 (4000) 3,629 (8.0) 14515 (32,000) 46,655 (6665) nine 5___________________________________________ Fluid C 12491 (3300) 0,0 0,0 41.02 (5860)

* - proppant is a commercial proppant sand coated with resin.

Fluid A is an aqueous polymer solution of a guar gum derivative (CMOS at 18.144 kg (40 pounds) of polymer per 3785.00 L (1000 gallons) of fracturing fluid) containing a zirconate crosslinking agent, a high temperature gel stabilizer, clay stabilizer and pH buffering agents. Fluid B is an aqueous polymer solution of a guar gum derivative (CMOS at 13.608 kg (30 pounds) of polymer per 3785.00 L (1000 gallons) of fracturing fluid) containing a zirconate crosslinking agent, a high temperature gel stabilizer, clay stabilizer, and a gelled polymer thinner. Fluids A and B further include an addition of ndecyl-CHA-dimethylamino oxide so that each modified liquid contains an amine oxide in a concentration of 0.1 wt.%. In most cases, this corresponds to the addition of a surfactant in a ratio of from 3.785 to 7.571 liters per 3,785 liters (1 to 2 gallons per thousand gallons) or 0.10.2 vol.%.

In step 1, fluid A is pumped as a fracture cushion fluid.

At stages 2–8, proppants are added to the modified fracturing fluids A and B “during processing” as the fluid is injected, and its concentration is linearly increased from the initial 0.907 kg (2.0 lb) of the added proppant (DRA) at the stage 2 to 3.629 kg (8.0 pounds) of DRA in stage 8.

In step 9, fluid C, a commercial CMOS based fracturing fluid, at 15.876 kg (35 pounds) of polymer per 3785 l (1000 gallons) of fracturing fluid, was used as a "fluid stream" to replace and push the fracturing fluid containing a proppant from the pipeline and into the reservoir. The amine oxide of the invention is usually not needed at this stage of jet substitution / washing. After flushing, the work is completed and the well is shut.

Injection work is carried out until completion without incident. An unfastened crack is obtained having a half-length (X _£ ) of approximately 249.94 m (820 ft) with an average conductivity (K ₍ lu) of approximately 1275 mD ft (shb.y).

Then the well is locked for several hours and then the selection from the well is carried out. Pumping to obtain a clean product is significantly accelerated (by 20–25% or higher) compared to previous work performed on neighboring wells using comparable sampling parameters (pressure and size of the flow fitting). Gas production from the well also increases significantly compared to previous neighboring wells.

Similar results are obtained using fracturing fluids and the operations described in Example 10 above, except that the CMOS polymer was crosslinked with a titanate crosslinking agent.

Similar results are also obtained when using fracturing fluids and the operations described in Example 10 above, except that guar gum is used instead of CMOS as a thickener.

Similar results are also obtained when using fracturing fluids and operations described in Example 10 above, except that a guar gum is used instead of CMOS as a thickener and a titanate crosslinking agent is used instead of a zirconate crosslinking agent.

Similar results are also obtained when using fracturing fluids and the operations described in Example 10 above, except that a guar gum instead of CMOS is used as a thickener, and a borate crosslinking agent is used instead of a zirconate crosslinking agent. These liquids have an alkaline pH.

Wetting angle

As noted previously, some preferred amino oxides in the presence of formation fluids provide the desired increase in wetting angle. The wetting contact angles were measured according to a method consisting in packing finely ground solids into a tube and then measuring the rate at which liquid penetrates the block. When the aqueous liquid comes into contact with a block of finely divided solids, it begins to move frontally inside the block.

Assuming that the block consists of a large number of capillaries, an expression can be derived to describe the speed with which the fluid moves inside the block. According to Wockep in “Surface Active Substances and Interphase Phenomena” (8gGas1ap1k apb 1n1gGas1a1 Ryepotepa, 8esopb Ebjyup, 1oBn ^ beu apb 8opk, 1989, p. 247), the distance I, which the fluid with viscosity η travels over time I, is equal to the following expression:

- Where r is the average size of the capillaries of the voids inside the powder and k is a constant value related to tortuosity. It is obvious then that the kg value depends on the packing of solids. The value of kg is measured by passing a fluid with a known surface tension through the block; a suitable choice is water. The wetting angle of a liquid with a known surface tension is also known or is taken to be 0, which is a good assumption in the case where the tested liquid is water and the block consists of sand, clay and silica flour. In the method, it is believed that neither flocculation, nor dissolution, nor scattering change the packing of the particles. We also believe that the contact angle of the preform, θ ₁ , is 0. In the method, it is further believed that the concentration of the surfactant never drops below the critical micellar concentration due to the adsorption of the surfactant. Finally, since some amino oxides can increase the viscosity of the test solution, we must take into account any differences in viscosity. So, we will assume that η ₂ represents the viscosity of the test solution. If we further use the relative data for the length of the absorbent column, then 1 ₁ = 1. We also know that the surface tension of water without a surfactant is Υ1 = 72 dyne / cm, which leads to the following formula for the surface wetting angle (in radians ):

72 / f θ ₂ - Yagssoz—— “Y ₂

The following table compares the absorption data with the wetting angle.

Sample K, dyne / cm I, relative Θ, degrees Billet 72 1.00 0 C8 OMAO 39,4 0.11 88.8 XU ϋΜΑΟ 37.0 0.26 82.5 C12 OMAO 43.1 0.36 76 3 C14 OMAO 42.6 0.21 57.8 oleyl OMAO 47.5 0.2 <50 Ρ75Ν (famous 21 0.41 54.8 prior art) _

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X ΌΜΆΘ is an amino oxide according to formula 1, where Κι is X, and K ₂ and K ₃ are methyl. When X = Cn, then X is a linear alkyl chain of η carbon

It is particularly noteworthy that some of the test surfactants according to the invention form a contact angle much greater than the contact angle of the surfactant Ε75Ν of the prior art, in particular, form a contact angle greater than 60 ° and in some cases more than 80 °, and actually approaching 90 °.

Claims (9)

CLAIM 1. Water-based fracturing fluid, characterized by the addition of 0.006 to about 0.1% by weight of aminoxide, corresponding to the formula AZ "where Κ ₁ is a branched or linear alkyl or alkenyl group having from 6 to about 20 carbon atoms, preferably a linear alkyl group having from 8 to 12 carbon atoms, and where each of K ₂ and _{3 is} independently alkyl, having from 1 to about 4 carbon atoms, preferably each of them is methyl, to facilitate the removal of the filtrate of fracturing fluid from the reservoir. 2. The method of hydraulic fracturing of an underground reservoir, through which the wellbore passes, including the injection of a hydraulic fracturing fluid based on water according to claim 1, possibly containing a propping agent, inside and through the specified wellbore under pressure sufficient to fracture the specified underground reservoir to way to create a continuous conductive zone from the top of the crack back to the wellbore. 3. The method of hydraulic fracturing according to claim 2, in which the aminoxide is present, at least in the initial portions of the fracturing fluid, which is injected into the well (cushion fluid). 4. The method of hydraulic fracturing according to claim 2, in which the aminoxide is added to the fracturing fluid, essentially continuously throughout the treatment along the hydraulic fracture. 5. The method of hydraulic fracturing according to any one of claims 2-4, wherein said amino oxide is added in amounts from 0.006 to about 0.024 wt.%. 6. An aqueous fracturing fluid, said fluid comprising an aqueous fluid carrier comprising a thickening amount of a soluble polysaccharide and from 0.006 to about 1% by weight of an amine oxide corresponding to the formula where Κ ι is an aliphatic group having from 6 to about 20 carbon atoms, and where each of Κ ₂ and Κ _{3 is} independently alkyl having from 1 to about 4 carbon atoms. 7. The fracturing fluid of claim 6, wherein said soluble polysaccharide is a galactomannan gum, preferably a guar gum or a guar gum derivative, a glycomannan gum or a cellulose derivative. 8. The fracturing fluid according to claim 7, in which said soluble polysaccharide is crosslinked with a borate, or zirconium, or titanium crosslinking agent. 9. A water-based fracturing fluid, characterized by the addition of a small amount of aminoxide, which is small but sufficient to facilitate rapid pumping of the filtrate to a pure product and an increase in the permeability of the formation; - 8 009529 where Κι is an aliphatic group having from 6 to about 20 carbon atoms, and where each of Κ ₂ and K _{3 is} independently alkyl, having from 1 to about 4 carbon atoms, to obtain a wetting angle above 60 °.