EP2459673A1 - Method of fracturing subterranean formations - Google Patents

Abstract

A method of fracturing subterranean formations which comprises using a low residue fluid that facilitates the clean up of the wellbore following the treatment is disclosed. The system includes a surfactant compound that forms micelles above a critical concentration. Under certain conditions the addition of an associative thickener compound yields a network based on hydrophobic interactions. The resulting viscous fluid can transport proppants, be applied neat or as a foamed or energized system, or used in an acidizing treatment. The method may further include a breaking step.

Description

METHOD OF FRACTURING SUBTERRANEAN FORMATIONS

FIELD OF THE INVENTION

[0001] The present invention relates to a method of fracturing subterranean formations using low residue fluid fracturing systems.

BACKGROUND OF THE INVENTION

[0002] In the oil and gas industry, hydraulic fracturing involves injecting a specially blended fracturing fluid through a wellbore and into a formation under sufficiently high pressure to create fractures, thereby providing channels through which formation fluids such as oil, gas or water, can flow into the wellbore and thereafter be withdrawn. Fracturing fluids are designed to enable the initiation or extension of a fracture and the simultaneous transport of suspended proppant (for example, naturally-occurring sand grains, resin-coated sand, sintered bauxite, glass beads, ultra lightweight polymer beads and the like) into the fracture to keep the fracture open when the pressure is released. The performance and the ability of a fracturing fluid to carry proppant are largely dependent upon its viscous properties.

Additional desirable characteristics of a fracturing fluid include the ability to be broken and cleaned out of the fracture following the treatment, good fluid-loss control and low friction pressures during application. Common fracturing fluids are based upon either aqueous or hydrocarbon systems, although aqueous fluids (for example, those based on water-soluble polymers, guar gums and guar derivatives) are generally more popular due to lower costs. While it is possible to increase the viscosities of guar-based fluids by elevating the concentration, a more economical approach involves cross-linking the polymers by applying cross-linking agents.

[0003] Polymer-free, water-based fracturing fluids may be prepared using surfactants.

Compared to a common gel prepared from guar derivatives, a surfactant-based fracturing fluid minimizes the amount of residue remaining in the formation after the treatment.

Depending on the grade of the selected guar polymer, the residue can be significant and impede the success of the fracturing procedure. The residue typically includes not only breakdown products resulting from the enzymatic or oxidative decomposition of the polymer structure following the treatment, but also contamination arising during processing of the guar. While modified guars usually contain fewer contaminants due to additional purification, such contaminants cannot be eliminated completely and economically.

[0004] Surfactant-based systems are purely synthetic and thus not dependent on the weather or economically-related changes in the harvest of the raw material (for example, guar beans) which may influence availability on the world market. Surfactant-based systems form stable foams when applied under energized conditions. Compared to guar-based fluids, it is possible to obtain the desired fluid property without the addition of a foaming agent. Energized fluids require less base fluid, allowing for application in water-sensitive formations and decreasing the amount of chemical additives needed for the treatment. The reduced amount of fluid that needs to be flowed-back can be of importance in places where the disposal of waste fluid comprises a significant cost factor. [0005] Surfactant-based fracturing systems are well known and valued for their ability to withstand high shear applications. Preferred surfactants can have a range of ionic character; anionic, non-ionic, cationic and zwitterionic species have all been used successfully.

However, some cationic surfactants are toxic and are not readily biodegradable.

[0006] Viscous fracturing fluids must also be able to be 'broken', by disruption of the structure that causes the increase in viscosity of the fluid in first place. Depending on the composition of the fluid, this disruption can be achieved either by physical or chemical means. If accomplished by an additive, the additional chemical should have no, or only a minimal effect on the gel performance during the actual treatment, but should react rapidly once the treatment is finalized. It is important that the method allows for a certain degree of control over the time involved in the decrease of the gel strength, whereby the formation temperature and pressure may play a vital role.

[0007] Typical breaker additives used in combination with guar based fracturing fluids are oxidizers and enzymes. Oxidizing chemicals like ammonium, potassium or sodium salts of peroxydisulfate cause the radical decomposition of the carbohydrate polymers, reducing their molecular weight and therefore their viscosifying ability. Certain amine based additives are available that can enhance the reactivity of the breakers.

[0008] Enzymatic breakers provide a less aggressive way to degrade carbohydrate based polymers. Common enzymes used in the oilfield are hemicellulases. Their application is limited to a smaller pH range (3.5 to 8) and lower temperatures compared to oxidizing breakers.

[0009] Surfactant-based fracturing fluids can be applied without breaker, depending solely on either the dilution of the network with formation water or the disruption of the micelles by contact with a sufficient amount of hydrocarbon, to reduce the viscosity of the fluid. However, this approach has the disadvantage that there is no means of control over the duration of the 'break'. Furthermore, it may be less economical due to the increased shut-in time of the well.

[0010] Numerous formulations for fracturing comprising surfactants and/or polymers have been suggested in the state of the art.

[0011] WO 92/08753 discloses polymer compounds which are useful as thickeners for aqueous compositions and in particular for latex dispersions. [0012] EP 0 225 661 describes the preparation of gels by crosslinking phosphate esters with polyvalent metal cations, in particular with aluminum ions.

[0013] WO 02/102917 describes aqueous compositions which comprise polymers having nonionic, ionic and hydrophobic functional groups, whose viscosity is increased under the action of shear forces or which form a gel under the action of shear forces. [0014] WO 2005/071038 describes compositions and methods for shortening the recovery time of cationic, zwitterionic and amphoteric viscoelastic surfactant compositions after the action of shear forces by addition of three-block oligomers having hydrophilic and

hydrophobic moieties, the surfactants preferably having a betaine structure.

[0015] US 2006/0128597 describes compositions and methods for shortening the recovery time of cationic, zwitterionic and amphoteric viscoelastic surfactant compositions after the action of shear forces by addition of partly hydrolyzed polyvinyl esters or partly hydrolyzed polyacrylates, the surfactants likewise preferably having a betaine structure.

[0016] US 2006/011 1248 describes methods for shortening the recovery time of zwitterionic viscoelastic surfactant compositions after the action of shear forces by addition of

compounds of the general formula

where R is a C3-Ci8-alkyl group, R' is a Co-Cu-alkylene group, EO is ethyleneoxy and PO is propyleneoxy, the surfactants preferably having a betaine structure.

[0017] US 6,194,356 describes well treatment fluids which comprise a viscoelastic surfactant in combination with a crosslinkable, hydrophobically modified polymer.

[0018] US 7,084,095 describes the use of encapsulated polymers in an aqueous

composition comprising a viscoelastic surfactant, the polymer producing a change in the rheological properties of the aqueous composition under the conditions in the interior of the well. [0019] WO 02/11874 discloses a viscoelastic well treatment fluid which comprise a sufficient amount of an oligomeric surfactant for controlling the viscoelastic properties of the fluid. The monomers of the surfactant used are ionic or zwitterionic compounds which have at least one charged head group and one long-chain hydrophobic hydrocarbon radical.

[0020] WO 03/056130 describes aqueous viscoelastic fluids for breaking open rock formations, which comprise a viscoelastic surfactant, especially a betaine, and a

hydrophobically modified polymer, the polymer preferably having a molecular weight in the range from 10⁴ to 10⁷ g/mol. [0021] WO 2005/040554 describes methods for increasing the viscosity of viscoelastic surfactant compositions for the treatment of wells by addition of hydrophilic-lipophilic organic compounds, such as, for example, alkyl alcohols, alkylthiols or alkylamines.

[0022] WO 2008/065172 A2 discloses a pH-regulated thickener system and its use for the treatment of underground geological formations. The composition with pH-dependent viscosity comprises at least one anionic surfactant of the general formula

R-[-(EO/PO)i-2o-]0)_kP(=0)(OH)₃-k wherein R is a hydrophobic group comprising 12 to 22 carbon atoms, EO/PO are

ethyleneoxy and/or propyleneoxy groups, and k is 1 or 2 and furthermore at least one polymeric thickener comprising at least two hydrophobic groups connected via hydrophilic groups.

[0023] WO 2008/065173 relates to a thickener system which is suitable for preparing a thickener composition and consists of at least one anionic surfactant A and at least one polymer B which comprises at least one hydrophobic group and at least one hydrophilic group, the concentration of the polymer B in the thickener composition being below the overlap concentration c^* of the polymer, to the use of an inventive thickener system for preparing a thickener composition, to a thickener composition comprising an inventive thickener system and to the use of inventive thickener compositions.

[0024] Although various fracturing fluids are presently used, there remains a need for fracturing fluid systems which mitigate disadvantages of the prior art formulations.

SUMMARY OF THE INVENTION

[0025] In one aspect, the invention comprises a method of fracturing a subterranean formation penetrated by a well bore, comprising the step of formulating an aqueous fracturing fluid and pumping the fracturing fluid down the wellbore at a rate and pressure sufficient to initiate or extend a fracture in the formation, wherein the fracturing fluid comprises an aqueous base fluid, a surfactant component and an associative thickener, whereby the fluid does not display the desired viscosity without both the surfactant component and the associative thickener. [0026] The surfactant component comprises at least an anionic surfactant and may further comprise a non-ionic surfactant. The associative thickener comprises a polymer which has at least one hydrophilic group and at least one hydrophobic group. The associative thickener is preferably added at a concentration less than the overlap concentration of the polymer. The fracturing fluid components are readily water soluble. Accordingly, the use of the described fluid may lower the amount of residue left in the formation and the damage to the proppant pack involved. The fracturing fluid may further comprise a breaker.

[0027] The fracturing fluid comprises micelles networked by an associative thickener. The micelles are formed by at least one anionic surfactant and, optionally, non-ionic surfactants. In one embodiment, the concentration of the polymer in the fracturing fluid is below the overlap concentration of the polymer. Without restriction to a theory, it is believed the micelles formed by the surfactants disclosed herein are substantially spherical.

[0028] In a preferred embodiment of the invention the anionic surfactant comprises a compound of formulae I. a to l.f or salts thereof, or mixtures thereof:

O O O

I l _{1 1} Il H Il ₁

HO-P-O-Y-R R—Y-O-P-O-Y-R HO-P- Z-O-Y-R

I I I OH OH OH

(La) (Lb) (Lc)

O O O

HO-S-O-Y-R¹ HO-S-Z-O-Y-R¹ Jl ,

II N HO Z-O-Y-R O O

(Ld) (l.e) (Lf) in which:

R¹ is selected from linear or branched Ci6-C22-alkyl, Ci6-C22-alkenyl, C16-C22- alkynyl, (Ci5-C2i-alkyl)carbonyl, (Ci5-C2i-alkenyl)carbonyl and (C15-C21- alkynyl)carbonyl,

Y is a group consisting of from 1 to 20 alkyleneoxy units and Z is Ci-C₄-alkylene.

BRIEF DESCRIPTION OF THE DRAWINGS

[0029] The invention will now be described by way of an exemplary embodiment with reference to the accompanying simplified, diagrammatic, not-to-scale drawings. [0030] Figure 1 is a graph showing the viscosity over time at 20-80⁰C for gels prepared from mixtures of nonionic (Nl) surfactants that differ in the hydrophilicity of the surfactants used. [0031] Figure 2 is a graph showing the viscosity over time from a shear history study in which the fluid comprises 2 w% active material containing an anionic-to-non-ionic surfactant ratio of 4 to 1.

[0032] Figure 3 is a graph showing the viscosity over time at 20-80⁰C for gels prepared with different loadings of associative thickener and surfactant. [0033] Figure 4 is a graph showing the viscosity over time at 20-50⁰C for different associative thickener and surfactant loadings.

[0034] Figure 5 is a graph showing the apparent viscosity at different shear rates for energized fluids that differ in foam quality. Data is presented for measurements at 30 and 50°C. [0035] Figure 6 is a graph showing the viscosity and pH of a gel in dependence on the amount of alkaline added.

[0036] Figure 7 is a graph showing the break profiles for a gel at 25°C for different compositions of light burnt MgO - emulsified in mineral oil with or without a retarding additive. [0037] Figure 8 represents the data obtained for a field trial described in Example 5 below. The pressures and sand concentrations on surface and down hole for the period of the treatment are shown.

DETAILED DESCRIPTION OF THE INVENTION [0038] The present invention relates to a method of fracturing subterranean formations using low residue fluid fracturing systems. When describing the present invention, all terms not defined herein have their common art-recognized meanings. To the extent that the following description is of a specific embodiment or a particular use of the invention, it is intended to be illustrative only, and not limiting of the claimed invention. The following description is intended to cover all alternatives, modifications and equivalents that are included in the spirit and scope of the invention, as defined in the appended claims.

[0039] In one aspect, the present invention relates to a method of fracturing a subterranean formation penetrated by a wellbore to aid in the recovery of oil and gas. In one embodiment, the fracturing fluid comprises an aqueous base fluid, a surfactant component and an associative thickener. The fracturing fluids do not display the desired viscosity without both the surfactant component and the associative thickener. The surfactant component comprises at least one anionic surfactant, or a mixture of an anionic surfactants and at least one non-ionic surfactant. [0040] Aqueous base fluids are well known in the art and embodiments of the present invention may be implemented with a wide variety of aqueous base fluids. Without restriction to a theory, it is believed the fracturing fluid systems of the present invention involve the formation of spherical micelles by the surfactant component. It is not believed that any rod- or chain-like micelles form. [0041] The aqueous base fluid comprises water as the main component and may in addition comprise organic solvents miscible with water. In general, the amount of water is at least 60 wt. % related to the total amount of all solvents of the aqueous base fluid. Preferably the amount of water shall be at least 80 wt. %, more preferred at least 95 wt. % and most preferred the solvent is only water. Said additional solvents in general have a molecular weight of less than 400 g/mol, preferably less than 200 g/mol. Suitable water-miscible solvents are, for example, homo- and heterooligomers of ethylene oxide and/or propylene oxide, for example ethylene glycol or propylene glycol, alcohols, e.g. methanol, ethanol, iso- propanol, butylmonoglycol, butyldiglycol, butyltriglycol, phenoxyethanol, phenoxypropanol or o-sec-butylphenol, N-alkylpyrrolidones such as N-methylpyrrolidone, and alkylene carbonates.

[0042] The aqueous base fluid may comprise a brine solution such as a potassium chloride or an ammonium chloride solution. The salt concentration may be selected by the skilled artisan according to the desired properties of the fracturing fluid. In general, the salt concentration should be less than 8 % by weight of the fluid, preferably 0.5 to 6 % by weight and by the way of example 3 to 5 % by weight.

[0043] In one embodiment, the anionic surfactants are selected from compounds of the general formulae (I. a) to (l.f) and salts thereof:

HO-

HO-

in which: R¹ is selected from linear or branched Ci6-C22-alkyl, Ci6-C22-alkenyl, Ci6-C22-alkynyl, (Ci5-C2i-alkyl)carbonyl, (Ci5-C2i-alkenyl)carbonyl and (Ci5-C2i-alkynyl)carbonyl,

Y is a group consisting of from 1 to 20 alkyleneoxy units and Z is Ci-C4-alkylene.

[0044] When the salts of the compounds (I. a) to (l.f) are used, they comprise, as well as the anion of the particular compounds, a corresponding positively charged counterion, for example Na⁺ or K⁺.

[0045] In the context of the present invention, the expression "alkyl" comprises straight- chain and branched alkyl groups. Suitable short-chain alkyl groups are, for example, straight- chain or branched Ci-Cz-alkyl, preferably d-Cε-alkyl and more preferably Ci-C4-alkyl groups. These include in particular methyl, ethyl, propyl, isopropyl, n-butyl, 2-butyl sec. -butyl, tert- butyl, etc.

[0046] In the context of the present invention, the expression "Cn-C22-alkyl" comprises straight-chain and branched alkyl groups. They are preferably straight-chain and branched Ci5-C2o-alkyl radicals, more preferably straight-chain and branched Ci6-Ci8-alkyl radicals and most preferably straight-chain Ci6-Ci8-alkyl radicals. They are especially predominantly linear alkyl radicals, as also occur in natural or synthetic fatty acids and fatty alcohols, and also oxo alcohols. They include, for example, n-undecyl, n-dodecyl, n-tridecyl, myristyl, pentadecyl, palmityl (= cetyl), heptadecyl, octadecyl, nonadecyl, arachinyl, behenyl, etc.

[0047] In the context of the present invention, Cn-C22-alkenyl, represents straight chain and branched alkenyl groups which may be mono-, di- or polyunsaturated. They are preferably straight-chain and branched Ci5-C2o-alkenyl, more preferably straight-chain and branched Ci6-Ci8-alkenyl and most preferably straight-chain Ci6-Ci8-alkenyl. They are especially predominantly linear alkenyl radicals, as also occur in natural or synthetic fatty acids and fatty alcohols, and also oxo alcohols. They include in particular octenyl, nonenyl, decenyl, undecenyl, dodecenyl, tridecenyl, tetradecenyl, pentadecenyl, hexadecenyl, heptadecenyl, octadecenyl, nonadecenyl, linolylyl, linolenylyl, eleostearyl, etc., and especially oleyl (9- octadecenyl).

[0048] In the context of the present invention, Cn-C22-alkynyl represents straight-chain and branched alkynyl groups which may be mono-, di- or polyunsaturated. They are preferably Ci5-C2o-alkynyl. They are especially predominantly linear alkynyl radicals. [0049] In the context of the present invention, the term "Cn-C2i-alkylcarbonyl" comprises straight-chain and branched alkyl groups as defined above, which are bonded via a carbonyl group (-C(=O)-). The same applies to the terms "Cn-C2i-alkenylcarbonyl" and "C11-C21- alkynylcarbonyl". [0050] The R¹ radicals of the compounds of the general formulae (I. a) to (l.f) have, on average, preferably at most one, more preferably at most 0.5 and especially at most 0.2 branch. In particular, the R¹ radicals are each independently selected from palmityl, stearyl, oleyl, linoleyl, arachidyl, gadoleyl, behenyl, erucyl, isostearyl, 2-hexyldecyl, 2-heptyldecyl, 2- heptylundecyl and 2-octyldodecyl. [0051] The Y groups in the compounds of the general formulae (I. a) to (l.f) are preferably selected from groups of the general formula (II),

-[(O-(CH₂)2)xi(O-CH(CH3)CH₂)x2]- (II) in which the sequence of the alkyleneoxy units is as desired and x¹ and x² are each independently an integer from 0 to 20, where the sum of x¹ and x² is from 1 to 20. [0052] The ratio of x¹ to x² averaged over the surfactants of the general formulae (I. a) to (l.f) present is preferably at least 2:1. In a specific embodiment of the inventive composition, the poly(alkyleneoxy) groups of the general formula (II) consist exclusively of ethyleneoxy units and x² is thus especially 0.

[0053] In the compounds of the formulae (I. a) to (l.f), the ratio of the anionogenic groups to the alkyleneoxy units of the R¹ groups is preferably within a range of from 1 :2 to 1 :10. In this connection, anionogenic groups refer to those groups which have an acidic proton and form an anionic group under basic conditions. When, instead of the compounds of the formulae (I. a) to (l.f), their salts are used, the aforementioned ratio relates correspondingly to the anionic groups. [0054] The anionic surfactants are preferably selected from compounds of the general formulae (I. a) or (l.b) and are more preferably selected from compounds of the formula (I. a).

[0055] Surfactants of the general formulae (I. a) and (l.b) used in accordance with the invention can, for example, be provided by reacting phosphoric acid or a suitable phosphoric acid derivative, for example P2O5, P4O1O, polyphosphoric acid (H3PO4 x (HPOs)_n where n > 1 ) or metaphosphoric acid ((HPOs)_n where n > 3), with a suitable alkoxylated alcohol of the formula R^l-[(O-(CH2)2)xi(O-CH(CH₃)CH₂)x2]-OH or mixtures of these alkoxylated alcohols, as are provided especially by reacting natural or synthetic mixtures of fatty alcohols and oxo alcohols with ethylene oxide and/or propylene oxide. As well as inorganic phosphoric acids, this typically affords mixtures of phosphoric monoesters and phosphoric diesters of the general formula (I. a) and (l.b).

[0056] The surfactant component of the present invention preferably comprises at least one phosphoric monoester of the general formula (I. a). Preferably at least 50 % by weight, more preferably at least 80 % and especially at least 90 % of the surfactant component present are selected from compounds of the general formula (I. a). [0057] The associative thickener comprises a water soluble polymer which has at least one hydrophilic group (α) and two hydrophobic groups. Preferably, the polymer is selected from compounds comprising at least two hydrophobic radicals R² which are bonded to one another via a bridging hydrophilic group (α). The hydrophilic group preferably comprises polyether units and/or polyvinyl alcohol units, more preferably polyether units. [0058] The hydrophobic R² groups preferably have a structure which corresponds to the hydrophobic R¹ groups of the surfactant component. The term "corresponding" shall mean that the number of carbon atoms in the groups R¹ and R² should not differ by more than 3 carbon atoms, preferably by not more than 2 carbon atoms and preferably the number of carbon atoms should be the same. Most preferably, the groups R¹ and R² should be identical.

[0059] The rheological properties of the fluid of the present invention are determined by interactions of the polymers, specifically of their hydrophobic R² groups, with micelles of the surfactants. These interactions are physical hydrophobic-hydrophobic interactions, thus forming overlapping networks. [0060] Surfactants form micelles in water even at very low concentrations. The

concentration at which the first micelles are formed is referred to as the critical micelle concentration (cmc). This is typically determined by the surface tension, solubilization, conductivity (in ionic surfactants) or NMR. The anionic surfactants used in the current invention are notable for a relatively high critical micelle concentration. The critical micelle concentration of such anionic surfactants is preferably within a range from 1 to 50 mg/L and more preferably within a range from 15 to 30 mg/L. The ranges specified relate to the concentrations determined at 25°C for a salt concentration and a pH which correspond to the use conditions. In order to form overlapping networks, the concentration of the surfactant in the thickener compositions is preferably above its critical micelle concentration. [0061] The hydrophobic R² groups of the polymers comprise, on average, preferably at least 14 and especially at least 16 carbon atoms. The upper limit of the carbon atom number is generally uncritical and is, for example, up to 100, preferably up to 50 and especially up to 35. More preferably, less than 10% of the hydrophobic R² groups present in the polymers comprise less than 15 and more than 23 carbon atoms. [0062] Preferably, on average, less than 20% and especially less than 5% of the R² groups present have a carbon-carbon double bond.

[0063] The hydrophobic R² groups are preferably selected from linear and branched C12- C22-alkyl, Ci2-C22-alkenyl or 2-hydroxy(Ci2-C22-alk-1-yl).

[0064] The R² radicals of the polymers have, on average, preferably at most one, more preferably at most 0.5 and especially at most 0.2 branch. In particular, the R² radicals are each independently selected from palmityl, stearyl, oleyl, linoleyl, arachidyl, gadoleyl, behenyl, erucyl, isostearyl, 2-hexyldecyl, 2-heptyldecyl, 2 heptylundecyl, 2-octyldodecyl and 2-hydroxypalmityl, 2-hydroxystearyl, 2-hydroxyoleyl, 2-hydroxylinoleyl, 2-hydroxyarachidyl, 2- hydroxygadoleyl, 2-hydroxybehenyl, 2-hydroxyerucyl and 2-hydroxyisostearyl. Preferably at least 70% of the R² groups present in the polymers are unbranched.

[0065] In a specific embodiment, the hydrophilic groups (α) comprise at least two hydrophilic units (β). The hydrophilic units (β) may have identical or different definitions. Identical hydrophilic units (β) are always bonded to one another via a bridging group (γ). Different hydrophilic units (β) may be bonded directly to one another or via a bridging group (γ).

[0066] In a preferred embodiment of the present invention, the bridging hydrophilic group (α) comprises, as hydrophilic units (β), polyether units and/or polyvinyl alcohol units. More preferably, the bridging hydrophilic group (α) consists of polyether units at least to an extent of 90%.

[0067] In a specific embodiment of the present invention, the hydrophilic units (β) of the polymers are at least partly selected from polyether units of the general formula (III)

-[(O-(CH₂)2)yi(O-CH(CH3)CH2)y₂]- (IN) in which the sequence of the alkyleneoxy units is arbitrary and y¹ and y² are each

independently an integer from 0 to 300, where the sum of y¹ and y² is from 10 to 300.

[0068] The sum of y¹ and y² denotes the number of alkyleneoxy units of this polyether chain and has, averaged over all polyether units of the formula (III) present, preferably a value in the range from 20 to 200, more preferably from 30 to 150. [0069] The ratio of y¹ to y² expresses the ratio of ethyleneoxy to propyleneoxy units.

Averaged over the polyether chain of the general formula (III) present, the ratio of y¹ to y² is preferably at least 2:1 , more preferably at least 5:1.

[0070] Various hydrophilic polyether units are preferably bonded to one another without bridging groups (γ). Such polyether units include, for example, EO/PO block copolymer units. [0071] In a specific embodiment of the present invention, the polyether chain of the formula consists exclusively of ethyleneoxy units. In this embodiment, y² is 0.

[0072] In a further specific embodiment of the present invention, the hydrophilic groups (α) are composed of hydrophilic units (β) which are bonded to one another via bridging groups (γ), the bridging groups (γ) being structurally different from the repeat units of which the hydrophilic units (β) are composed.

[0073] The bridging groups (γ) between the hydrophilic units (β) of the polymer in the fracturing fluid composition are preferably selected from m-valent, preferably 2- to 4-valent, groups containing from 1 to 10 bridging atoms between the flanking bonds, where the m- valent groups has structures which are selected from -OC(=O)-, -C(=O)OC(=O)-, -OC(=O)O-, -OC(=O)NH-, -NC(=O)NH-, alkylene, alkenylene, arylene, heterocycylene, cycloalkylene, where alkylene and alkenylene may be interrupted once or more than once by oxygen, sulfur, -NH- and -N(Ci-Cio-alkyl)-, arylene, heterocyclylene and cycloalkylene may be mono- or polysubstituted by Ci-C4-alkyl, and m is an integer in the range from 2 to 4. The bridging groups (γ) preferably have -OC(=O)NH- as terminal structural units.

[0074] In this context, the term "m-valent group" means that the bridging group (γ) is capable of forming m chemical bonds, where m is an integer and is preferably 2, 3 or 4.

[0075] When alkylene or alkenylene is interrupted by one or more, for example 1 , 2, 3, 4, 5, 6, 7 or 8 nonadjacent groups which are each independently selected from oxygen, sulfur, - NH- and N(Ci-Cio-alkyl)-, the termini of the alkylene or alkenylene group is formed by carbon atoms.

[0076] When the m-valent group (γ) has a valency greater than 2, branching of the polymer is enabled. In this case, the polymer may also comprise more than two hydrophobic R² groups. [0077] The polymer preferably comprises from two to six, more preferably from two to four hydrophobic R² groups.

[0078] Such polymers used in accordance with the invention can, for example, be provided by reacting polyisocyanates, polyols, polyamines, polycarboxylic acids with a suitable alkoxylated alcohol, for example an alkoxylated alcohol of the formula R²-[(O-(CH2)2)_yi(O- CH(CH3)CH2)y2]-OH or mixtures of these alkoxylated alcohols. These alcohols are provided especially by reacting natural or synthetic mixtures of fatty alcohols and oxo alcohols with ethylene oxide and/or propylene oxide. This typically affords mixtures of alcohols with a different number of alkyleneoxy units, which can be used as such. The polymers used in accordance with the invention can likewise be provided by reacting compounds which comprise at least two different functional groups with the aforementioned alcohols. The polymers are preferably provided starting from polyisocyanates or polyols.

[0079] Suitable polyisocyanates, especially diisocyanates and triisocyanates, for providing polymers are the aliphatic, cycloaliphatic, araliphatic and aromatic di- or polyisocyanates mentioned below by way of example. These preferably include 4,4'-diphenylmethane diisocyanate, the mixtures of monomericdiphenylmethanediisocyanates and

oligomericdiphenylmethanediisocyanat.es (polymer-MDI), tetramethylenediisocyanate, tetramethylenediisocyanatetrimers, hexamethylenediisocyanate,

hexamethylenediisocyanatetrimers, isophoronediisocyanatetrimer, 4,4'- methylenebis(cyclohexyl) diisocyanate, xylylenediisocyanate,

tetrarnethylxylylenediisocyanate, dodecyldiisocyanate, lysine alkyl ester diisocyanate where alkyl is Ci-Cio-alkyl, 1 ,4-diisocyanatocyclohexane or 4-isocyanatomethyl-l,8-octamethylene diisocyanate, and more preferably hexamethylenediisocyanate and 4,4'-diphenylmethane diisocyanate.

[0080] Suitable diols for providing the polymers are straight-chain and branched, aliphatic and cycloaliphatic alcohols having generally from about 1 to 30, preferably from about 2 to 20 carbon atoms. These include 1 ,2-ethanediol, 1 ,2-propanediol, 1 ,3-propanediol, 1 ,2- butanediol, 1 ,3-butanediol, 1 ,4-butanediol, 2,3-butanediol, 1 ,2-pentanediol, 1 ,3-pentanediol, 1 ,4-pentanediol, 1 ,5-pentanediol, 2,3-pentanediol, 2,4-pentanediol, 1 ,2-hexanediol, 1 ,3- hexanediol, 1 ,4-hexanediol, 1 ,5-hexanediol, 1 ,6-hexanediol, 2,5-hexanediol, 1 ,2-heptanediol, 1 ,7-heptanediol, 1 ,2-octanediol, 1 ,8-octanediol, 1 ,2-nonanediol, 1 ,9-nonanediol, 1 ,2- decanediiol, 1 ,10-decanediol, 1 ,12-dodecanediol, 2-methyl-1 ,3-propanediol, 2-methyl-2- butyl-1 ,3-propanediol, 2,2-dimethyl-1 ,3-propanediol, 2,2-dimethyl-1 ,4-butanediol, pinacol, 2- ethyl-2-butyl-1 ,3-propanediol, diethylene glycol, triethylene glycol, dipropylene glycol, tripropylene glycol, polyalkylene glycols, cyclopentanediols, or cyclohexanediols.

[0081 ] Suitable triols for providing the polymers are, for example, glycerol, butane-1 ,2,4- triol, n-pentane-1 ,2,5-triol, n-pentane-1 ,3,5-triol, n-hexane-1 ,2,6-triol, n-hexane-1 ,2,5-triol, trimethylolpropane, trimethylolbutane. Suitable triols are also the esters of hydroxycarboxylic acids with trihydric alcohols. They are preferably triglycerides of hydroxycarboxylic acids, for example lactic acid, hydroxystearic acid and ricinoleic acid. Also suitable are naturally occurring mixtures which comprise hydroxycarboxylic acid triglycerides, especially castor oil. Preferred triols are glycerol and trimethylolpropane. [0082] Suitable higher polyhydric polyols for providing polymers are, for example, sugar alcohols and derivatives thereof, such as erythritol, pentaerythritol, dipentaerythritol, treitol, inositol and sorbitol. Also suitable are reaction products of the polyols with alkylene oxides, such as ethylene oxide and/or propylene oxide. It is also possible to use higher molecular weight polyols with a number-average molecular weight in the range from about 400 to 6000 g/mol, preferably from 500 to 4000 g/mol. These include, for example, polyesterols based on aliphatic, cycloaliphatic and/or aromatic di-, tri- and/or polycarboxylic acids with di-, tri- and/or polyols, and also the polyesterols based on lactone. These further include polyetherols which are obtainable, for example, by polymerizing cyclic ethers or by reacting alkylene oxides with a starter molecule. These further also include customary polycarbonates with terminal hydroxyl groups which are known to those skilled in the art and are obtainable by reacting the above-described diols or else bisphenols, such as bisphenol A, with phosgene or carbonic esters. Also suitable are α,ω-polyamidols, α,ω-polymethyl (meth)acrylatediols and/or α,ω-polybutyl (meth)acrylatediols, for example MD-1000 and BD-9000 from

Goldschmidt. [0083] Suitable dicarboxylic acids for providing polymers are, for example, oxalic acid, malonic acid, succinic acid, glutaric acid, adipic acid, pimelic acid, suberic acid, azelaic acid, sebacic acid, undecane-α,ω-dicarboxylic acid, dodecane-α,ω-dicarboxylic acid, cis- and trans-cyclohexane-1 ,2-dicarboxylic acid, cis- and trans-cyclohexane-1 ,3-dicarboxylic acid, cis- and trans-cyclohexane-1 ,4-dicarboxylic acid, cis- and trans-cyclopentane-1 ,2- dicarboxylic acid, cis- and trans-cyclopentane-1 ,3-dicarboxylic acid, phthalic acid, isophthalic acid, terephthalic acid and mixtures thereof.

[0084] The abovementioned dicarboxylic acids may also be substituted. Suitable substituted dicarboxylic acids may have one or more radicals which are preferably selected from alkyl, cycloalkyl and aryl, as defined at the outset. Suitable substituted dicarboxylic acids are, for example, 2-methylmalonic acid, 2-ethylmalonic acid, 2-phenylmalonic acid, 2-methylsuccinic acid, 2-ethylsuccinic acid, 2-phenylsuccinic acid, itaconic acid, 3,3-dimethylglutaric acid, etc.

[0085] Dicarboxylic acids can be used either as such or in the form of derivatives. Suitable derivatives are anhydrides and their oligomers and polymers, mono- and diesters, preferably mono- and dialkyl esters, and acid halides, preferably chlorides. Suitable esters are mono- or dimethyl esters, mono- or diethyl esters, and also mono- and diesters of higher alcohols, for example n-propanol, iso-propanol, n-butanol, iso-butanol, tert-butanol, n-pentanol, n-hexanol, etc, and also mono- and vinyl esters and mixed esters, preferably methyl ethyl esters.

[0086] Preferred polycarboxylic acids for providing the polymers are succinic acid, glutaric acid, adipic acid, phthalic acid, isophthalic acid, terephthalic acid or their mono- or dimethyl esters. Particular preference is given to adipic acid.

[0087] Suitable polyamines are, for example, ethylenediamine, propylenediamine, diethylenetriamine, triethylenetetramine, tetraethylenepentamine, polyethyleneimine, 1 ,3- propanediamine, N,N-bis(aminopropyl)amine, N, N, N -tris(aminoethyl)amine, N, N, N',N'- tetrakis(aminoethyl)ethylenediamine, N,N,N',N",N"-pentakis(aminoethyl)-diethylenetriamine, neopentanediamine, hexamethylenediarnine, octamethylenediamine or isophoronediamine.

[0088] Further compounds suitable for providing the polymers are compounds which comprise at least two different functional groups, for example ethanolamine, N- methylethanolamine, propanolamine, hydroxyacetic acid, lactic acid, glutamic acid, aspartic acid.

[0089] In a particularly preferred embodiment, the polymer is provided proceeding from (a) C14-C22 fatty alcohol ethoxylates and mixtures thereof, (b) polyethylene glycol, EO-PO copolymers, trimethylolpropaneethoxylates/trimethylolpropanepropoxylates,

glycerylethoxylates/propoxylates and mixtures thereof, and (c) hexamethylenediisocyanates. [0090] In a further particularly preferred embodiment, the polymer is provided proceeding from (a) polyethylene glycol, EO-PO copolymers, trimethylolpropaneethoxylat.es and/or - propoxylates, glycerylethoxylates and/or -propoxylates and mixtures thereof, and (b) 1 ,2- epoxy-Ci4-C22-alkanes and mixtures thereof. [0091 ] The preferred range for the molecular weight of the polymer comprising at least one hydrophilic group and at least two hydrophobic groups arises through multiplication of the number of hydrophobic R² groups present with a value of from 1500 to 8000 g/mol.

[0092] The polymers preferably have, on average, a molecular weight M_n in the range from 3000 to 50,000 g/mol, more preferably in the range from 5000 to 30,000 g/mol. [0093] The fracturing fluids used according to the present invention may comprise further components.

[0094] In a preferred embodiment of the invention, the fracturing fluid may comprise further surfactants besides the anionic surfactants, in particular the anionic surfactants of the formulas I. a ti l.f. Preferably, such further surfactants may included non-ionic surfactants. Cationic surfactants or zwitterionic surfactants may be used in special cases but should in general not be used.

[0095] In a preferred embodiment of the present invention, the fracturing fluid additionally comprises at least one linear or branched aliphatic C4-Ci8-monoalcohol as co-surfactant. Such co-surfactants have headgroups smaller than the headgroups of the surfactant they are added to, and generally insert into micellar solutions to relieve packing stress as a result of their smaller headgroup size. The monoalcohol co-surfactants have preferably at most one branch. When a plurality of aliphatic C4-Ci8-monoalcohols is present, they have on average preferably at most 0.5 and more preferably at most 0.2 branch. Preferred monoalcohols are linear or branched aliphatic C6-Ci6-monoalcohols, for example, n-hexanol, n-heptanol, n- octanol, n-nonanol, n-decanol, n-undecanol and n-dodecanol. In one embodiment, the co- surfactant comprises 2-ethylhexanol or n-octanol.

[0096] In this embodiment, the fracturing fluids comprise advantageously an amount of at least one linear or branched aliphatic monoalcohols as co-surfactant in the range from 0.1 to 20% by weight, preferably from 0.5 to 15% by weight and more preferably from 1 to 8% by weight based on the total weight of the components other than the in the fracturing fluid.

[0097] In one embodiment, the fracturing fluid additionally comprises at least one non-ionic surfactant of the general formula (IV) as additional surfactant

R³-[(O(CH₂)2)zi(OCH(CH₃)CH2)z2]-OH (IV) in which: the sequence of the alkyleneoxy units is as desired,

R³ is selected from Ci2-C22-alkyl, Ci2-C22-alkenyl, Ci2-C22-alkynyl, (Cn-C2i-alkyl)- carbonyl, (Cn-C2i-alkenyl)carbonyl and (Cn-C2i-alkynyl)carbonyl, and z¹ and z² are each independently an integer from 0 to 20, where the sum of z¹ and z² is from 1 to 20.

[0098] The R³ radicals of the non-ionic surfactants of the general formula (IV) preferably have on average at most one, more preferably at most 0.5 and in particular at most 0.2 branch. In particular, the R³ radicals are each independently selected from palmityl, stearyl, oleyl, linoleyl, arachidyl, gadoleyl, behenyl, erucyl, isostearyl, 2-hexyydecyl, 2-heptyldecyl, 2- heptylundecyl and 2-octyldodecyl.

[0099] In one embodiment, the non-ionic surfactants have a (poly)alkyleneoxy group which consists of z¹ ethyleneoxy and z² propyleneoxy groups joined to one another in any sequence.

[00100] Non-ionic surfactants of the general formula (IV) used in accordance with the invention are, for example, provided by reacting natural or synthetic mixtures of fatty alcohols and oxo alcohols with ethylene oxide and/or propylene oxide. This typically affords mixtures of compounds of the formula (IV) with a different number of alkyleneoxy units. These may be used as mixtures in the inventive compositions.

[00101] The sum of z¹ and z² averaged over the compounds of the general formula (IV) present is preferably in the range from 4 to 18 and more preferably in the range from 10 to 16, and most preferably 11 to 15. Specifically, each non-ionic surfactant of the general formula (IV) present in the thickener composition has, for the sum of z¹ and z², a value in the range from 10 to 16 and more preferably a value in the range from 11 to 15.

[00102] The ratio of z¹ to z² averaged over the non-ionic surfactants of the general formula (IV) present is preferably at least 2:1. In a specific embodiment of the inventive fluid composition, the (poly)alkyleneoxy groups of the surfactants of the general formula (IV) consist exclusively of ethyleneoxy units and z² is therefore especially 0.

[00103] Embodiments of the non-ionic surfactant may be hydrophilic or hydrophobic in nature. For example, if the number of polyethoxy units (n) attached to the alkyl chain is greater than about 13, the non-ionic surfactant may be considered hydrophilic. If n<13, the surfactant may be considered hydrophobic.

[00104] The pH-value of the fracturing fluid is less than 8, preferably less than about 7 and more preferably less than about 6. In one preferred embodiment, the fracturing fluid is pH adjusted to a slight acidic value, using a suitable acid such as hydrochloric acid or acetic acid. In one embodiment, the pH of the fracturing fluid is between about 4 and 5, preferably between pH 4 and 4.5.

[00105] The addition of a polymer associative thickener to the surfactant component of the present invention leads to the formation of interactions between the polymer and the micelles formed by the anionic surfactant and the non-ionic surfactant (if present). The resulting micellar network results in the increase in viscosity of the fracturing fluid. [00106] In one embodiment, the associative thickener is applied at a concentration below the polymer overlap concentration, c^*, preferably at least 0.1 c^*, and more preferably within a range of about 0.2 to 0.7 c^*. The polymer overlap concentration is obtained by plotting the log of the zero shear viscosity of the polymer fluid as a function of the log of its concentration (without a surfactant component), as defined in United States Patent

Application No. 2005/0107503, the contents of which are incorporated herein by reference, where permitted. The curve will define three distinct slopes having two intersecting points, each referred to as a break point. The more dilute break point is the overlap concentration of the polymer, while the less dilute break point is the entanglement concentration.

[00107] The total amount all surfactant components and the associative thickener together (the "active material") may be varied to achieve a desired viscosity or other properties of the fluid, and may range from 0.1 to 30 wt. %, preferably 0.2 to 10 wt. %. In one embodiment, the active material may comprise from about 0.5 wt% to about 5.0 wt% of the fluid. In one embodiment, the active material may comprise about 1.0 wt% to about 4.0 wt% of the fluid. In one preferred embodiment, the active material may comprise about 2.0 wt% of the fluid.

[00108] The ratio of the surfactant components to associative thickener may also be varied with successful results. In one embodiment, the ratio of the surfactant components to associative thickener, in particular the ratio of the anionic and non-ionic surfactant to associative thickener may be about 1 :1 to about 100:1 by weight, preferably 2:1 to 20:1 , more preferably 3:1 to 15:1 and most preferred 5:1 to 12:1. In one further preferred embodiment, the ratio of surfactant to associative thickener may be about 9:1 by weight.

[00109] The fluids disclosed display particular properties which make them suitable hydraulic fracturing fluids. In one embodiment, the fracturing fluid is not viscoelastic. The property of viscoelasticity in general is well known and reference is made to S. Gravsholt, Journal of Coll. And Interface ScL, 57(3), 575 (1976); Hoffmann et al., "Influence of Ionic Surfactants on the Viscoelastic Properties of Zwitterionic Surfactant Solutions", Langmuir, 8, 2140-2146 (1992); and Hoffmann et al., The Rheological Behaviour of Different Viscoelastic Surfactant Solutions, Tenside Surf. Det, 31 , 389-400, 1994. Of the test methods specified by these references to determine whether a liquid possesses viscoelastic properties, one test which has been found to be useful in determining the viscoelasticity of an aqueous solution consists of swirling the solution and visually observing whether the bubbles created by the swirling recoil after the swirling is stopped. Any recoil of the bubbles indicates viscoelasticity. Another useful test is to measure the storage modulus (G') and the loss modulus (G") at a given temperature. If G'>G" at some point or over some range of points below about 10 rad/sec, typically between about 0.001 to about 10 rad/sec, more typically between about 0.1 and about 10 rad/sec, at a given temperature and if G'>10^"2Pascals, preferably 10^"1 Pascals, the fluid is typically considered viscoelastic at that temperature. Rheological measurements such as G' and G" are discussed more fully in "Rheological Measurements", Encyclopedia of Chemical Technology, vol. 21 , pp. 347-372, (John Wiley & Sons, Inc., N.Y., N.Y., 1997, 4th ed.). These references are expressly incorporated herein by reference, where permitted.

[001 10] A fracturing fluid used in the method of the present invention may be mixed at the surface in a batch or continuous process, and used to treat a wellbore using conventional and well known techniques. In general, the fracturing fluid is mixed at the surface using conventional equipment and techniques. In one embodiment, concentrated solutions of the components described herein may be added to a salt solution as a base fluid to achieve the final desired concentrations. The components may be added in any order. The fluid is then thoroughly mixed to achieve the desired viscosity, and a proppant may be added.

[001 11] The fluid is then pumped into a wellbore to create a bottomhole pressure sufficient to open a fracture in the formation. The bottomhole pressure is determined by the surface pressure produced by the surface pumping equipment and the hydrostatic pressure of the fluid column in the wellbore, less any pressure loss caused by friction. The minimum bottomhole pressure required is determined by formation properties and therefore will vary from application to application. [001 12] The fluid may be used to transport proppants which are well known in the art.

The proppants may comprise naturally occurring or man-made particles such as sand, resin- coated proppants, ceramics, bauxite, crushed walnut shells and the like.

[001 13] The fluid may be foamed or energized using well-known and conventional techniques such as those disclosed in US 3,937,283 or US 5,069,283. Particularly high pumping pressures may be required for foamed systems where the hydrostatic pressure is low due to the presence of gas. Foamed systems include foam or energized fluids, and comprise stable mixtures of gas and liquid, which are mainly used in fracturing low pressure or water sensitive formations. Foam and energized fracturing fluids are generally described by their foam quality, i. e. the ratio of gas volume to the foam volume. If the foam quality is between 52% and 95%, the fluid is usually called foam. Above 95%, a foam is generally changed to mist. Stable dispersion of gas in liquid with foam quality less than 52% is typically called energized fluid. In the present patent application, the term "foamed system" will be used however to describe any stable mixture of gas and liquid, whatever the foam quality is. The foam half-life is another important parameter to evaluate the stability of foam or energized fluids. The half life of a foam or energized fluids is the time necessary for one-half of the liquid used to generate the foam to break out of the foam under atmospheric conditions.

[001 14] Examples of gases which may be used for energizing or foaming the fluid include air, nitrogen, carbon dioxide, Argon or hydrocarbons gaseous under the conditions prevailing in the formation. Preferably, the fluid may be foamed or energized using ISb and/or CO2 and most preferably using N2. [001 15] Foamed systems may provide numerous advantages. They expand when they flow back from the well and therefore force the fluid out of the fracture, consequently ensuring a superior clean-up. They typically require less viscosifying agent while presenting good fluid loss control and fluid efficiency. As a result, foamed systems are often cheaper than conventional systems unless the cost benefit due to the use of lower quantities of chemicals is overturned by the need of higher horse power, and consequently of specific pumping equipment.

[001 16] In one preferred embodiment, the method of fracturing a subterranean formation according to the invention comprises an additional breaking step after the treatment of the formation with the fracturing fluid. In such breaking step the viscosity of the fracturing fluid used is reduced in order to enhance back flow of fracturing fluid out of the formation so that the fluid can be removed from the formation into the well more quickly. In order to achieve a reduction in viscosity, viscosity reducing components, so called "breakers" may be injected into the subterranean formation after the fracturing steps and/or such breakers may be added to the fracturing fluid itself. In the latter case, the effect of the breaker should not set in immediately after preparing the fracturing fluid but the onset of the effect should be delayed.

[001 17] The fracturing fluids of the present invention are sensitive to pH. The pH- sensitivity is very pronounced for fracturing fluids comprising anionic surfactants of formulas I. a to l.f , in particular those wherein the anionic surfactants comprises at least 50 % by weight of anionic surfactants of formula I. a. Therefore, the viscosity of the fracturing fluid may easily be reduced by increasing the pH of the fluid. In one embodiment of the invention, the pH-value of the fluid may be increased to a value of at least 8, preferably to a pH-value of about 8.

[001 18] Therefore, in one embodiment, for breaking a liquid alkali can be applied to the subterranean formation following the fracturing treatment.

[001 19] In another embodiment, a precursor material of a base may be added directly to the fracturing fluid, which upon elapsed time or temperature increase the precursor will undergo a physical or chemical reaction forming an alkaline material, leading to an increase in pH and thus the decomposition of the network structure. In one embodiment, the precursor material may comprise an alkaline earth metal oxide such as magnesium or calcium oxide. Upon dissolution in an aqueous medium, the respective alkaline hydroxide is formed: such as MgO (s) + H2O (I) -> Mg(OH)2 (l). Since this reaction occurs rapidly upon contact with water it is necessary to delay the process. This can be achieved by decreasing the surface area of the active material utilizing a prill or pellet like formulation. Furthermore it is possible to partially deactivate the active material on the surface during the manufacturing process by physically or chemically applying a coating layer, which dissolves or erodes over time. [00120] In one embodiment, the breaker may comprise magnesium oxide.

Magnesium oxides are classified into light burnt magnesium oxide (about 600 ⁰C to 900 ⁰C) and hard burnt magnesium oxide (about 1 ,100 ⁰C to 1 ,500 ⁰C). The former are generally more reactive. Suitable particles may have a particle size of 1 - 20 μm, for example 3 to 8 μm or about 10 μm. [00121] In another embodiment, a base releasing breaker in the form of powdered material, in particular MgO in the form of particles may be suspended in a hydrocarbon slurry, e.g. in a mineral oil. Further control over the release can be achieved by addition of retarding agents to the mineral oil slurry. Suitable retarding agents include surface active materials to the mixture to alter the properties of the suspension such as fatty acids, fatty alcohols or alkaline sulfonate salts. Such formulations allow the utilization of an operational setup suitable for the addition of liquid samples as well as the decrease of the impact on health and environment.

[00122] Because the viscosifying properties of the fluids of the present invention are based on a network of interlinked surfactant micelles, it is also possible to break the network by dilution of the fluid with water.

[00123] Furthermore, it may also be possible to break the network by addition of a surfactant species that interfere with the micellar structure. Thus, in one embodiment, such breaker surfactants may include non-ionic surfactants based on alkylpolyethylene glycol ethers. The alkyl chain consists of a linear, saturated fatty alcohol, with a chain length of C12 to C25, preferably C14 to Ciβ. In one embodiment, the degree of ethoxylation may vary between 10 and 80, and is preferably about 50. The material can be added in solid form (powder or granulates), solution (aqueous), emulsion, encapsulated or as an emulsion of the encapsulated species.

[00124] In case of a foamed or energized fluid it advantageous not to use carbon dioxide for foaming if the fluid comprises a base releasing breaker but preferably an inert gas such as nitrogen should be used. In case of using a surfactant breaker also carbon dioxide may be used for foaming.

[00125] The fluid fracturing system of the present invention leaves relatively little residue once the viscosity has been broken, whether applied in a foamed system, or not. The amount of residue left by a particular fluid may be determined by permeability regain tests such as those described in the examples below. For a low residue fracturing fluid, a regain permeability of 50% or more is expected, in comparison to values around 25% which are typically observed for a guar-based fluid. [00126] Examples - The following examples are presented for illustrative purposes only and are not to be interpreted as limiting the claimed invention in any way.

[00127] Example 1

[00128] The fracturing fluid comprises a mixture of anionic and nonionic surfactants, a polymer associative thickener and n-octanol as a co-surfactant. Initial performance tests showed a stable gel at a temperature of 70⁰C and significant pH dependence of the obtained viscosities. The anionic surfactants consisted of a mixture of about 70 mol% Ci6-Ciβ-alkyl- (O-(CH₂)₂)4-OP(=O)(OH)₂ and 30mol% of [(Ci6-Ci8-alkyl-(O-(CH₂)₂)4)-O]2-P(=O)(OH). The polymer (also referred to herein as the associative thickener) consisted of a 25% solution of a reaction mixture comprising the polymers obtained from the reaction of Ci6-Ciβ-alkyl-[(O- (CH₂)₂)i4o]-OH (78% by wt), PEG 12000 (20% by wt) and hexamethylenedi-isocyanate (2% by wt.), in a mixture of 1 ,2-propanediol, iso-propanol and water. The non-ionic surfactant consisted of Ci6-Ci8-alkyl-[(O-(CH₂)₂)i₃]-OH.

[00129] a) Gel preparation

[00130] A base fluid comprising a brine solution containing 3% potassium chloride was prepared. It is possible to use lower (e.g. 2%) as well as higher (e.g. 7% or higher) salt concentrations. Ammonium chloride may also be suitable. A specified volume of the base fluid was adjusted to a pH of 4.3 using aqueous solutions of either hydrochloric acid (HCI) or acetic acid (AcOH). Under agitation of the solution by applying an overhead stirrer with an impeller blade at a set speed (usually 1000 rpm), the anionic surfactant (IO), the non-ionic surfactant (Nl) and the associative thickener (AT) were added as individual and diluted solutions. The order of addition (sequential or simultaneously) does not appear to affect the resulting performance of the resultant gel. Unless otherwise stated, the added quantities were based on a total amount of 2 w% of active material, whereby the ratio of the total amount of surfactant to thickener was 9:1. The ratio of anionic to non-ionic surfactant can be varied depending on the desired application. In order to ensure a homogeneous mixture, the samples were stirred for two minutes so as to mimic the respective mixing time in field operations. All temperature stability tests were carried out on a Brookfield™ PVS

Rheometer. The gels were investigated under a constant shear rate of 100 s^"1, applying a temperature ramp that comprises data collection for 60 minutes at each temperature.

[00131] Table 1 shows the viscosities of a gel prepared from 1.4 w% anionic surfactant (IO), 0.4 w% non-ionic surfactant (Nl) and 0.2 w% associative thickener (AT) in a 3% solution of KCI in water. Aqueous AcOH was added to obtain a pH of 4.3. The rheological properties at a certain temperature were studied in dependence on the order of addition of the components. Table 1

[00132] Different approaches regarding an operational "two-component" mixture were investigated. Possible solutions involved the addition of the buffer solution to the anionic surfactant or the non-ionic surfactant, which can be premixed with the associative thickener component.

[00133] b) Variation of the ratio of surfactant components

[00134] The influence of the ratio of the non-ionic (Nl) to the anionic (IO) surfactant on the gel performance was investigated. The quantity of associative thickener added to the mixture was kept constant, while the amount of buffer was adjusted according to the experimental requirements (Table 2).

Table 2

[00135] The influence of the hydrophilicity of the non-ionic surfactant was investigated by preparing a premixed solution of varying amounts of surfactant components which differ in the number of polyethoxy units (n) attached to the alkyl chain. The premixed solution included three components, namely the base component (Nl, n=13), a hydrophobic version (Nl(-), n<13) and a hydrophilic version (Nl(+), n>13). The total amount of non-ionic surfactant was kept constant at 0.3 w%, the amount of anionic surfactant at 1.5 w% and the associative thickener at 0.2 w% active material. The results given in Table 3 are also depicted in Figure 1.

Table 3

[00136] c) Variation of loadings

[00137] The gel performance of fluids prepared with different amounts of active material (surfactants and thickener) was investigated in dependence on temperature. Table 4 summarizes the results obtained for the various gels of the compositions set out below. The amount is defined as weight-percent of the sum of active material relative to the fluid. In one embodiment, an application as low as 0.8 w% active material is possible, depending on the desired temperature range in which the fluid will be used. In addition to tests comprising temperature ramps, standard API procedures have been followed to investigate the stability of the respective gels at certain temperatures (data not shown).

Table 4

[00138] d) Shear history

[00139] The influence of shear on the quality of the fluid was investigated for a temperature range of 20 to 60⁰C. The experiment carried out on a Brookfield™ PVS Rheometer which simulates shear conditions a fracturing fluid would encounter when applied operationally. The shear history program comprised high shear rates (51 1 to 850 S^"1) at lower temperatures that account for the transport in the wellbore and through the

perforations, followed by lower shear (100 to 10 S^"1) at elevated temperatures that mimic the flow through the fracture itself. The quality or strength of the gel was not hampered by high shear rates (up to 850 S^"1). Viscosities were found to be higher at low shear rates, though no significant difference was observed for the values obtained for 40 and 1 1 s^"1. Figure 2 provides a graphical representation of the shear history data.

[00140] e) Compatibility with fracturing sand

[00141] Qualitative tests were performed to investigate the compatibility of the fluids with respect to fracturing sand. The experimental setup comprised 100 ml. of a fluid prepared according to the above mentioned procedure and quantities. Fracturing sand was added to the viscous fluid under shear. The impact of the addition on the fluid rheology and the settling behaviour upon removal of the shear stress was determined (data not shown). No significant settling of the fracturing sand was observed during the course of the experiment.

[00142] Example 2

[00143] In this example, the fracturing fluid comprises one anionic surfactant, a polymer associative thickener, and a co-surfactant. The anionic surfactant in this example consisted of a mixture of [Ci8-alkyl-(O-(CH₂)2)4-OP(=O)O₂]²-2Na⁺ and Ci₈-alkyl-(O-(CH₂)₂)₄- OP(=O)(OH)₂ with Ci8-alkyl-(O-(CH₂)₂)4-OP(=O)(OH)2 present in 25 to 50% by weight of active material. The thickener and co-surfactant were identical to that used in Example 1. An acid or base component was used to provide the optimal pH of the brine solution. In one embodiment, the acid is selected from, for example, HCI or AcOH. In one embodiment, the base is selected from, for example, sodium hydroxide (NaOH) or potassium hydroxide (KOH). The gel preparation is similar to the manner described in Example 1 , i.e., adding the anionic surfactant and the associative thickener (AT) as individual and diluted solutions. The order of addition (subsequently or simultaneously) does not appear to be detrimental to the resulting performance of the gel. Unless otherwise stated, the added quantities were based on a total amount of 2 w% of active material, whereby the ratio of surfactant to thickener was 9:1. Unless otherwise stated, the gels were prepared in a 3% KCI solution, and the pH adjusted to 4.3 using aqueous AcOH. In order to ensure the presence of a homogeneous mixture, the samples were stirred for two minutes.

[00144] a) Gel preparation 45] To exclude any influence of the order of addition of the various components, gels were prepared in three different ways. Simultaneously, the temperature range of the experiment was extended to investigate the viscosities at temperatures of up to 80⁰C by applying a temperature ramp (stepwise increase of temperature in 10⁰C steps) and measuring the viscosities at a shear rate of 100 S^"1 for a minimum of 30 minutes at each temperature (Table 5). The results indicate that there is no significant influence of the order in which the components are added. This is important for a potential field application and standardisation of the gelation process.

Table 5

[00146] While the preferred base fluid is a brine solution containing 3% potassium chloride, the possibility exists to decrease or increase the salt concentration if so desired. Table 6 shows the temperature dependent viscosities at a shear rate of 100 S^"1 for fluids prepared with different amounts of potassium chloride. It will be appreciated by those skilled in the art that other monovalent and divalent salts, such as ammonium chloride or calcium chloride, may also be suitable. The obtained values show that the fluid can be applied across a broad range of salinity that allows the use of base fluids with higher brine contents.

Table 6

[00147] b) pH dependence

[00148] Table 7 provides examples for the performance of fluids prepared using different acidic compounds for the adjustment of the pH. The pH of the fluid was measured with a Horiba™ pH meter.

Table 7

[00149] It is further possible to add the buffer (acid or base) required for the adjustment of the pH at different stages of the gelation process. It is possible to premix or partially premix the buffer with the anionic surfactant (IO), and thus change the pH of that particular component without significantly affecting the gelation process or the quality of the resulting gel, as shown by the results in Table 8.

Table 8 [00150] While operationally more involved, the individual addition of buffer via a separate pump offers a higher degree of flexibility and allows for immediate changes in loading/concentration if desired.

[00151] The pH and the amount of acid/base used significantly influences the gel properties and the speed of the gelation process. To explore the performance of the fluid at different pH, temperature dependent rheology was investigated for various amounts of acid added to the mixture. The fluid tolerates a deviation in pH and is thus applicable over a greater range (Table 9). The variation of pH allows optimization of the fluid properties towards the application at a certain temperature range. In one embodiment, the optimum pH for an application of higher temperatures is 4.3-4.5.

Table 9

[00152] Further investigations with respect to the method of preparation included the variation of mixing speeds. Gels were mixed under three different speeds, which indicates the effect of different pump rates on the gel performance. The results indicate that the fluid is applicable under various conditions, allowing for flexibility with respect to the shear arising during the blending and pumping processes (Table 10).

Table 10

[00153] c) Thickener-surfactant ratio

In one embodiment, the polymer-to-anionic surfactant ratio is 1 :9, with a total of 0.2 w% active material within the fluid. The influence of the amount of polymer associative thickener on the performance of the fluid was investigated by increasing the active amount of the associative thickener in the fluid, while maintaining the amount of the anionic surfactant constant. The speed of the gelation process was enhanced by increasing in the amount of associative thickener. The performance of the resulting fluids with respect to their rheological properties varies upon changes to the ratio surfactant - thickener and an optimum value can be defined depending on the desired applicable temperature range. The results (Table 1 1) show that the system is robust and tolerates deviation from preferred ratios.

[00154] d) Mixtures of anionic surfactant components

[00155] The alkyl-residue of the anionic surfactant may vary in length and saturation. Depending on the choice of the surfactant component, the available temperature range of the fluid can be attenuated. Generally, anionic surfactants with a lower polarity provide an enhanced high temperature performance.

[00156] Alternatively, it is possible to further increase the applicable temperature range of the system without altering the performance of the gel at lower temperatures by applying mixtures of different mono-alkyl phosphate esters. Tests were conducted with surfactants differing in the number of ethoxylate units. The main focus was the influence on the gelation time, which is assumed to increase, and likewise on the gel quality at low temperatures. Surfactants differing in their hydrophilicity were mixed and homogenized prior to their addition to the fluid. Homogenisation was achieved by applying heat to the solution either using an external heat source or microwaves. The solutions were cooled to room temperature prior to use. Table 12 summarizes examples of the effect of varying the ratio of a mixture of more (Nl(+)) and less (Nl(-)) hydrophilic anionic surfactants on the rheological properties of the resulting fluids.

Table 12 [00157] Table 13 shows the values obtained when investigating the influence of increasing the amount of associative thickener in the fluid that was obtained using a 5:1 ratio of more (Nl(+)) and less (Nl(-)) hydrophilic anionic surfactants. It can be summarized that the loss in gel strength due to the decreased hydrophilicity can be compensated by altering the ratio of surfactant and thickener.

Table 13

[00158] e) Surfactant - Thickener premix

[00159] To study the influence of premixing the surfactant and thickener component, experiments were carried out with fluids prepared from associative thickener-surfactant premixed solutions that contained increasing amounts of anionic surfactant (10). The total amount of anionic surfactant in each gel remained the same, and the remaining surfactant was added to the base fluid separately. The presence of anionic surfactant in the

concentrated solution of the associative thickener can influence the gelation process due to the primed formation of the micellar network. The mixtures were prepared using an undiluted sample of the anionic surfactant to the thickener solution (which is a solution of AT and co- surfactant). A homogeneous mixture was achieved by agitation and the application of an external heat source. The amount of surfactant that can be premixed with the thickener is limited due to the increasing strength of the network and thus increasing viscosity of the concentrate. The percentage reflects the amount of surfactant premixed with thickener with respect to the total amount of surfactant added to the gel. Premixing 13% of the total amount of surfactant with the thickener compound yielded the best overall performance when investigating the viscosities of the fluids at temperatures between 20 and 50⁰C (Table 14).

Table 14

[00160] f)

[00161] Preferably, the anionic surfactant compound is soluble in water at a pH higher than 3. In order to increase the concentration of active material in solution, alternative solvents and solvent mixtures can be applied. The concentration of the surfactant solution and the solvents used influence the gel strength and thus the performance of the fluid as fracturing treatment fluid. Consequently, gelation times and gel properties of various fluids were investigated upon addition of surfactant solutions in various solvents. Non-limiting examples of suitable solvents include iso-propanol, 1 ,2-propandiol, ethanol, and aqueous mixtures of thereof. Table 15 provides an example for the application of different iso- propanol (iPrOH)/water mixtures as solvents for the surfactant component and the strengths of the resulting fluids.

Table 15

[00162] The increase in the amount of iso-propanol in the fluid influenced the fluid properties, especially at elevated temperatures. A similar effect can be achieved by increasing the concentration of active material in solution, which leads to a decrease of additional solvent in the fluid. Table 16 summarizes experiments carried out to compare the performance of gels prepared with iso-propanol/water (1/1) solutions containing 25% and 50% active material applying three different samples of premixed surfactant - thickener packages. The term w%(IO) refers to the weight % of anionic surfactant contained in the surfactant-thickener pre-mix and the term w%(sol) refers to the concentration of the anionic surfactant formulation. It can be concluded that the application of 50% solution leads to an enhanced gel performance with respect to higher temperatures. The best overall performance is achieved for a gel prepared with 13% of the total amount of surfactant being premixed with the thickener.

Table 16

^* delayed gelation (20 minutes)

[00163] g) Variation of loadings

[00164] In order to be applicable as fracturing fluid, a viable system requires a certain degree of control over the viscosity obtained at given temperature. This is commonly achieved by the variation of the gellant loading, which equals the total amount of active material in the fluid. Several experiments were carried out to investigate the effect of the change in loadings on the gel performance at different temperatures. The loadings are given in weight percent based on the sum of active material of surfactant and associative thickener. A graphical representation of the data shown in Table 17 can be found in Figure 3. An increase in loadings yielded significantly higher viscosities and sufficient gel strength at temperatures as high as 80⁰C. The reduction of the loadings showed the desired decrease in viscosity, enabling a more cost efficient system when applied in low temperature wells.

Table 17

[00165] Further experiments were conducted to investigate the possibility to further optimize the gel properties by independent variation of the two components (Table 18). A viable gel was still achieved for various combinations of loadings. This experiment indicates the high degree of flexibility that is available using the system. Figure 4 provides a graphical summary of the findings with respect to the potential decrease in loading to enable a more economic approach for field applications especially when performed at low temperatures.

Table 18

[00166] h) Application as energized fluid

[00167] Flow loop experiments were conducted using a fluid which was prepared with

1.8 w% anionic surfactant and 0.2 w% associative thickener in a 3% KCI solution at pH 4.5. Compressed nitrogen was used in order to energize the fluid, creating a foam of 60% or 80% quality respectively. The rheological performance of the foams was investigated under different shear rates and various temperatures. In addition, the homogeneity of the fluid was observed in a transparent section of the loop. A stable and homogeneous foam was generated without addition of a foaming agent. It will be appreciated by those skilled in the art that a foaming agent additive could be added if desired. The results show that the system is suitable to be applied as energized fluid (Table 19, Figure 5). Table 19

[00168] i) Stability under field conditions

[00169] A viable fracturing fluid system has to be applicable using different grades of water that may differ in quality. To confirm the applicability of the system, the gel performance of fluids prepared with water from different sources was investigated. The gels were prepared using 1.8 w% anionic surfactant and 0.2 w% associative thickener. Apart from the "field water" sample that was premixed with 3% KCI, brine was added prior to the gellant components. In all three cases, the same amount of buffer was required in order to adjust the pH to 4.3-4.5. The results confirm that the system is applicable under conditions present in field operations (Table 20). Tap water is Calgary tap water, Dl is deionised Calgary tap water, and field water may be highly variable depending on its source and method of transport.

Table 20

[00170] Further experiments towards the application under field conditions comprise the use of quaternary amine based supplemental clay control agents which have to be compatible with the system when applied in concentrations required for the successful treatment of formation clays. As an example an additive based on a solution of alkoxylated quaternary amines was tested (Table 21).

Table 21

[00171] Example 3 - Breaking the System

[00172] In order to determine the critical pH value at which the gel network is destroyed, the pH of a gel was increased by stepwise addition of a liquid alkali. The investigated gel was prepared using 1.8 w% anionic surfactant and 0.2 w% of the associative thickener compound. The pH of the solution in 3% KCI water was adjusted to a pH of 4.3 prior to the addition of the alkaline. Experimental tests with a 5% solution of sodium hydroxide in water-methanol reveal that the integrity of the network was disrupted at a pH > 8 as shown in Figure 6.

[00173] Unless otherwise stated the following tests were carried out with a gel prepared with 2 w% active material (1.8 w% surfactant and 0.2 w% associative thickener) in an aqueous solution containing 3% KCI with the pH being adjusted to 4.3 by addition of an aqueous solution of AcOH. The gels were mixed at a speed of 1000 rpm using an overhead stirrer with an impeller blade. In order to achieve a homogeneous mixture the gels are stirred for two minutes prior to the measurements. The breaker additives were mixed directly into the gel solutions. The 'break time' is defined as the time after which the viscosity of the fluid sheared at 100 S^"1 is lower than 10 cP.

[00174] Table 22 summarizes the results obtained using a powdered form of light burnt magnesium oxide (MgO) material (bulk density - 352 kg/m³, particle size - 3 to 8 μm, surface area - 20-30 m/g).

Table 22

[00175] The experiments were carried out at 25°C. Similar experiments carried out at elevated temperatures (50⁰C) revealed a reduction in the duration of the break and a loss in control over the respective time.

[00176] The retarding effects due to the application of MgO as slurry in mineral oil

(MO) was investigated using a 40 w% suspension. A homogeneous mixture was obtained by agitation. Further investigations were carried out with suspensions that also contained retarding additives. Those additives could comprise fatty acids or fatty alcohols as well as alkaline sulfonate salts. Table 23 offers a comparison of the duration of the break observed in dependence on the formulation in which the light burnt magnesium oxide is applied.

Graphical break profiles are provided for several examples in Figure 7. Table 23

[00177] Separate tests have shown that the effect of pure mineral oil itself (without

MgO) is negligible in the applied quantities. At elevated temperatures the addition of pure mineral oil will lead to a disruption of the network if applied in considerable quantities. Those however greatly exceed the amount used in conjunction with the magnesium oxide suspensions.

Table 24

[00178] In general a decrease in break time is observed when investigating break times at elevated temperatures. Break times at elevated temperatures are commonly observed by immersing the fracturing fluid in a water or oil bath at the desired temperature immediately after addition of the breaker material. However, temperature studies in the field have shown that the increase in temperature of the fluid is delayed for several minutes due to the high rate with which the fluid is pumped down the wellbore. A comparative study revealed a considerable increase in the duration of the break upon delay of the temperature increase.

Table 25

[00179] Further tests were carried out using a hard burnt species of magnesium oxide

(bulk density > 1121 Ikg/m³, particle size ~ 10 μm). Due to its production process, this material is less reactive. The bigger particle size and reduced surface area of the hard burnt material result in a decrease in reactivity. Table 26 provides examples for break times obtained with hard burnt MgO at 25°C. The degradation of the viscosifying network is considerably slower. Similar to experiments with the more reactive species, the formulation of MgO as a suspension in mineral oil leads to further increase in the time required for completion of the reaction.

Table 26

[00180] While the increase in temperature is accompanied with a loss of controllability of break time for the light burnt species, the lower reactivity of the hard burnt material enables sufficient control over the reaction. Table 27 summarised the results obtained for powdered samples as well as emulsified material at 50⁰C, while table 28 provides the data obtained at 70⁰C

Table 27

Table 28

[00181] The results show that it is possible to break the gel both at high and low temperatures.

[00182] Surfactant-based breaker

[00183] Unless otherwise stated tests are carried out with a gel prepared with 2 w% active material (1.8 w% anionic surfactant and 0.2 w% associative thickener) in an aqueous solution containing 3% KCI with the pH being adjusted to 4.3 by addition of an aqueous solution of AcOH. The gels are mixed at speed of 1000 rpm using an overhead stirrer with an impeller blade. In order to achieve a homogeneous mixture the gels are stirred for two minutes prior to the measurements. The breaker additives are mixed directly into the gel solutions. The 'break time' is defined as the time after which the viscosity of the fluid sheared at 100 S^"1 is lower than 10 cP.

[00184] Table 29 shows the results obtained when measuring the duration of the break of the network applying different loadings of a neat alkylpolyethylene glycol ether (APG) to the fracturing fluid.

Table 29

[00185] The effective break time can be triggered either by variation of the

concentration of the breaker additive as shown above or the composition of the

alkylpolyethylene glycol ethers. Table 30 shows values obtained investigating two different species that differ in the degree of ethoxylation.

Table 30

[00186] The surfactant breaker may be formulated in a variety of different manners. An encapsulated form of the surfactant breaker (10 w% active in an inert matrix) can be applied as is shown in Table 31.

Table 31

[00187] The comparative data shows that the encapsulation affect the duration of the break, delaying the release of the active material. Similar studies at elevated temperatures confirm the applicability of the material as well as the effectiveness. Table 32

[00188] Example 4 - Regain Permeability Testing

[00189] The term "regain permeability" refers to the degree to which a permeability of a formation that has been treated with a fracturing fluid differs from the original permeability of the subterranean formation. An ideal completion fluid, from a regain permeability perspective, has a regain permeability at low drawdown pressure (1-2% of maximum) which matches that of the original undamaged baseline measurements, indicating no permanent damage has been caused. Due to the water-solubility of all components, the use of an embodiment of the fracturing fluid described herein may result in improved clean-up properties and reduced loss of the components into the formation or the sand pack.

[00190] The objective of the fluid evaluation or leak off test described in this example is to provide an evaluation of the total effect of the completion fluid system on the formation. In this experiment, a regain permeability apparatus was equipped with a core sample from the Bakken formation and placed in an oven that was set to the formation temperature of 69 ⁰C. The sample was rich in carbonates and its dimensions were length - 5.70 cm, diameter - 3.77 cm and pore volume - 6.11 cm³. As is typical of the Bakken formation, the permeability was very low, 0.04 millidarcies air permeability, much lower than average oil reservoirs. In this case, regain permeability to oil was being measured and therefore, in order to ensure representative test conditions, the core was brought to its original state by reconditioning it in oil from the respective formation for a period of six weeks prior to the experiment.

[00191] The testing parameters were chosen as follows: fracture pressure - 23240 kPa, pore pressure - 1 1000 kPa, net overburden pressure - 16158 kPa. The baseline permeability as well as the regain permeability measurements were taken in the forward direction, whereas the fracturing fluid was circulated in the reverse direction. The

composition of the fracturing fluid was based on a target viscosity of 150 - 200 cP (at 100 s- 1) and a reduction of the viscosity to <15 cP (at 100 s-1 ) within four hours.

[00192] The gel was prepared similar to the manner described in Example 2. 2.1 w% of the anionic surfactant and a premixed solution of 0.3 w% of the anionic surfactant and 0.3 w% of the associative thickener (AT) were added subsequently to an aqueous solution containing 5.25% potassium chloride. In addition, a suspension of 0.15 w% magnesium oxide and 0.15 w% mineral oil were added.

[00193] After a leakoff exposure time of 30 minutes a total volume of 0.99 ml. and a linear penetration depth of 0.84 cm was recorded. Table 33 shows the permeabilities measured for specific pressures applied to the core. The regain permeability represents the percentage of permeability recovered with respect to the baseline permeability of 0.009 mD.

Table 33

[00194] While the regained permeability does not match the baseline permeability, the recovery of 69.1 % of the permeability is considered a high yield when evaluating a fluid under stringent test conditions (tight carbonate formation at high temperatures) present in the described experiment. Compared to values generally expected for guar-based fluids, the value indicates that the amount of damage that this fluid caused to the formation would be low.

[00195] Example 5 - Field Test Conditions

[00196] In order to demonstrate the viability of the described fluid system, field tests were performed on two shallow gas wells in Northern Alberta. The wells had an average depth of 575 m with the perforations located in the Colorado formation from 471 to 475 m and 458 to 461 m for one well and from 497 to 499 m and 490.5 to 494.5 m for the second one. Bottom hole temperature, pressure and fracture gradient are estimated to be 20⁰C, 4100 kPa and 20.5 kPa/m, respectively.

[00197] Based on the treatment specifications, the composition of the fluid was programmed to 0.88 w% of anionic surfactant and 0.18 w% associative thickener, with 2- ethylhexanol as a co-surfactant (AT : co-surfactant = 90.9 to 9.1). The fluids were applied separately with the thickener being partially premixed with 20% of the total amount of active surfactant. A 50 w% suspension of magnesium oxide in mineral oil, which contained further additives to ensure homogeneity, was also added. The initial concentration of the magnesium oxide suspension was set to 0.05 w% and was continuously increased to a final amount 0.1 w% at the end of the treatment.

[00198] The base fluid - a 5.5% solution of potassium chloride in water - was supplied in bulk trucks. The potassium chloride solution had a slightly red colour which indicated somewhat higher iron content compared to tap water. [00199] To limit the amount of water in contact with the formation, the fluid was applied as energized system. The aqueous fluid was foamed with nitrogen with the initial foam quality being set to 80% and the clean fluid-gas ratio being subsequently decreased to 3:5 (60% foam quality) on the last proppant stage. The wellbores were flushed with 100% nitrogen. The foamed fluid was pumped into the formation at a programmed rate of 5.5 m³/min down 114.3 mm casing. The total treatment volumes indicated that 20.7 m³ and 19.4 m³ of fluid were pumped into the formations.

[00200] Following an initial pad without proppant, 20/40 mesh Ottawa sand was blended into the low pressure liquid, which was pumped to a horsepower unit. The horsepower then pumped the fluid on the high pressure side which combined with nitrogen and was pumped down hole. The proppant concentration was continuously step-ramped up during the subsequent stages, resulting in an average amount of 20 tonnes of proppant pumped into formation per well.

[00201] Figure 8 shows a treatment report for one of the two wells. It shows the surface treatment pressure, as well as the sand concentration on the surface. The data obtained during the treatment indicated that the amount of proppant placed in the formation matched the volume of the created fracture and thus confirms the success of the treatment.

[00202] In addition, it was reported that the fluid system to be easy to pump compared to an alternative surfactant based fluid. The reduced amount of pump cavitations suggested that the described system, comparatively, provided a more homogenous foam without sections of separated nitrogen and liquid.

[00203] Figure 8 represents the data obtained for the field test described in Example

5. The pressures and sand concentrations on surface and down hole for the period of the treatment are provided.

Claims

CLAIMS:

1. A method of fracturing a subterranean formation penetrated by a well bore, comprising the steps of formulating an aqueous fracturing fluid and pumping the fracturing fluid down the wellbore at a rate and pressure sufficient to initiate or extend a fracture in the formation, wherein the formulation comprises • an aqueous base fluid,

• at least one associative thickener comprising at least a water soluble polymer comprising at least one hydrophilic group and at least two hydrophobic groups, and

• at least one surfactant comprising at least one anionic surfactant, wherein the total amount of the associative thickener and the surfactants is from 0,1 to

30 % by wt. of the fluid, the ratio surfactants / associative thickener is from 1 :1 to 100 : 1 , the fluid has a pH less than about 6, and wherein the fracturing fluid comprises micelles comprising anionic surfactants which are networked by the polymer.

2. The method of claim 1 wherein the anionic surfactant comprises a compound of

formulae I. a to l.f or salts thereof, or mixtures thereof:

(La) (Lb) (Lc)

O O O

N - I , I l

HO-S-O-Y-R HO-S-Z-O-Y-R A ,

II N HO Z-O-Y-R

(Ld) (l.e) (Lf) in which:

R¹ is selected from linear or branched Ci6-C22-alkyl, Ci6-C22-alkenyl, C16-C22- alkynyl, (Ci5-C2i-alkyl)carbonyl, (Ci5-C2i-alkenyl)carbonyl and (C15-C21- alkynyl)carbonyl,

Y is a group consisting of from 1 to 20 alkyleneoxy units and Z is Ci-C4-alkylene

3. The method of claim 2 wherein the anionic surfactant is comprised of at least about 50% compounds of formula I. a.

4. The method of claim 2 wherein the anionic surfactant is comprised of a mixture of Ciβ- Ci8-alkyl-(O-(CH₂)2)4-OP(=O)(OH)₂ and [(Ci6-Ci8-alkyl-(O-(CH₂)₂)4)-O]2-P(=O)(OH).

5. The method of claims 1 to 4, wherein the surfactant further comprises a non-ionic

surfactant of formula (IV)

R³-[(O(CH₂)2)zi(OCH(CH₃)CH2)z2]-OH (IV) in which: the sequence of the alkyleneoxy units is as desired,

R³ is selected from Ci2-C22-alkyl, Ci2-C22-alkenyl, Ci2-C22-alkynyl, (Cn-C2i-alkyl)- carbonyl, (Cn-C2i-alkenyl)carbonyl and (Cn-C2i-alkynyl)carbonyl, and z¹ and z² are each independently an integer from 0 to 20, where the sum of z¹ and z² is from 1 to 20.

6. The method of claim 5 in which the R³ radicals are each independently selected from palmityl, stearyl, oleyl, linoleyl, arachidyl, gadoleyl, behenyl, erucyl, isostearyl, 2- hexyydecyl, 2-heptyldecyl, 2-heptylundecyl and 2-octyldodecyl.

7. The method of one of the claims 5 or 6 wherein the sum of z¹ and z² is from 10 to 16.

8. The method of one of the claims 1 to 7 wherein the fluid further comprises an aliphatic CA- to Cis-monoalcohol as co-surfactant.

9. The method of one of the claims 1 to 8 wherein the water soluble polymer comprises a hydrophilic bridging group (α) comprising polyether units and at least two hydrophobic groups R², selected from linear or branched Ci2-C22-alkyl, Ci2-C22-alkenyl or 2- hydroxy(Ci2-C22-alk-1 -yl) groups.

10. The method of claim 9 wherein the hydrophilic groups (α) comprises at least two

hydrophilic units (β) selected from polyether units of the general formula (III)

-[(O-(CH2)2)yi(O-CH(CH3)CH2)y2]- in which the sequence of the alkyleneoxy units is arbitrary and y¹ and y² are each independently an integer from 0 to 300, where the sum of y¹ and y² is from 10 to 300.

1 1. The method of claim 10 wherein the hydrophilic units (β) are linked via bridging groups (γ), the bridging groups (γ) being structurally different from the repeat units of which the hydrophilic units (β) are composed.

12. The method of one of the claims 1 to 1 1 wherein the polymer has a molecular weight M_n of between about 3000 to about 50,000 g/mol

13. The method of one of the claims 1 to 12 wherein the fluid has pH of about 4 to about 4.5.

14. The method of one of the claims 1 to 13 wherein the fluid has a storage modulus (G') lower than the loss modulus (G") when measured at frequencies below 10 rad/sec.

15. The method of one of the claims 1 to 14 wherein the polymer is added at a

concentration less than the overlap concentration of the polymer.

16. The method of one of claims 1 to 15 wherein the fluid is foamed or energized using a gas.

17. The method of aims 1 to 16 wherein the fluid further comprises suspended proppants.

18. The method of one of the claims 1 to 17 wherein after the treatment of the formation with the fracturing fluid the viscosity of the fracturing fluid is reduced.

19. The method of claim 18 wherein the pH-value of the fluid is increased to a value of more than 8.

20. The method of claim 19 wherein the fluid further comprises a breaker which is capable to release a base.

21. The method of claim 20 wherein the breaker comprises light burnt magnesium oxide or hard burnt magnesium oxide.

22. The method of one of the claims 20 or 21 wherein the breaker is suspended in mineral oil.

23. The method of claim 22 wherein the mineral oil slurry further comprises a retarding agent.

24. The method of claim 23 wherein the retarding agent is selected from the group of fatty acids, fatty alcohols and alkaline sulfonate salts.

25. The method of claim 18 wherein a breaking surfactant is used.

26. The method of claim 25 wherein the breaking surfactant comprises a non-ionic

surfactant based on alkylpolyethylene glycol ethers, wherein the alkyl chain comprises a linear, saturated fatty alcohol with a chain length of C12 to C2s and wherein the degreee of ethoxylation varies between 10 and 80.

27. The method of one of the claims 25 or 26 wherein the breaking surfactant is added in solid form (powder or granulates), solution (aqueous), emulsion, encapsulated or as a suspension or emulsion of the encapsulated form.