EA041391B1 - DIFFERENT ACIDS CONTAINING WATER-SOLUBLE RETAILER, AND METHODS OF MANUFACTURING AND APPLICATION - Google Patents

Description

Related Application Information

This application claims priority from U.S. Provisional Application No. 62/214,047, filed March 3, 2015, which is incorporated herein in its entirety.

Technical field

The present invention relates to diverting acids containing water-soluble acid retardants, as well as to methods of manufacture and use.

State of the art

This section provides background information for a better understanding of various aspects of the present invention. It should be understood that the statements in this section of this document are to be read in that light and not as acceptance of the prior art.

The maintenance and stimulation of oil and gas wells with specially designed fluids is critical to the efficient extraction of such resources. Well treatment fluids perform many functions: hydraulic fracturing, gravel packing, flooding, and acidizing. Acidizing is considered the oldest well stimulation technology, first applied in 1895. When pumped at low rates into carbonate formations, hydrochloric acid (HCl) can form conductive channels that extend radially from the wellbore. Acids can also be injected into subterranean formations at rates high enough to cause fracture. In this case, the acid unevenly dissolves the walls of the fracture surface such that if pumping is stopped and the fracture surface closes, conductive channels running the length of the fracture surface remain.

HCl is highly reactive and at higher temperatures (>200°F) and/or low injection rates promotes surface dissolution during channeling in matrix treatments. For this reason, the search for less reactive acid formulations continued. One approach is to use organic acids such as formic and acetic acids. Organic acids have higher pKa values than HCl and will not be completely consumed in the reservoir. The second approach is to slurry the acid as an oil-in-water emulsion, which limits the contact of the aqueous acid solution with the formation and thus slows down the reaction rate. In the latter work, the authors of the present invention have developed a method by which the reactivity of HCl is weakened by the use of certain water-soluble compounds with the formation of one-phase systems based on the acid delayed action.

During acid treatment, the highest permeability portions of the formation will receive the most acid, thus increasing the permeability of such high permeability zones even more. Continuous processing of such same zones slightly intensifies production in other parts of the reservoir. Diverting fluids are often injected between acid stages to redirect acid flow to less permeable parts of the formation. Diverting fluids are designed to penetrate into the most permeable areas of the formation and form a temporary plug. The next acid stage will be directed to a different part of the formation, and such stages may be repeated to achieve optimal fluid placement.

A number of substances can act as diverting agents. Simple compounds such as benzoic acid flakes are used to plug the formation very close to the wellbore and then dissolve in natural hydrocarbons as the well is produced. Oil-soluble resins also work on this principle. Other fluids, often containing polymer or surfactants, are designed to increase the viscosity in the formation by setting a thick plug that will break after completion of the treatment.

The essence of the invention

The Summary of the Invention section provides a selection of concepts that are described in more detail later in the Detailed Description of the Invention. The Summary of the Invention section is not intended to indicate key or essential features of the claimed subject matter, nor should it be construed as limiting the scope of the claimed subject matter.

In a first aspect of the present invention, there is provided an aqueous composition(s) comprising: water; viscoelastic surfactant; acid; and a water-soluble acid retarding agent.

In another aspect of the present invention, methods are provided comprising a) providing an aqueous composition comprising: water; viscoelastic surfactant; an acid and a water-soluble acid retarding agent; and b) treating the formation fluidly connected to the wellbore with an oilfield treatment fluid containing the aqueous composition.

Brief description of graphic materials

Some embodiments of the present invention will be described hereinafter with reference to the accompanying drawings, in which like reference numerals designate like elements. However, it should be understood that the accompanying figures

- 1 041391 illustrate various implementations described in this document and are not intended to limit the scope of the various technologies described in this document, and at the same time:

in fig. 1 depicts an example of equipment used to treat a wellbore and/or a formation fluidly connected to the wellbore, in accordance with certain embodiments of the present invention;

in fig. 2 shows curves of breakthrough pore volume versus pore velocity for aqueous acid solutions based on tests carried out at 70°F in accordance with the present invention;

in fig. 3 shows curves of breakthrough pore volume versus pore velocity for aqueous acid solutions based on tests conducted at 200°F in accordance with the present invention;

in fig. 4A-E depict the dissolution profile for core samples calculated in accordance with the present invention; and in FIG. 5 shows curves of the concentration of formed calcium as a function of time for certain aqueous solutions of acids, calculated in accordance with the present invention;

in fig. 6 shows viscosity versus shear rate for fresh VDA containing viscoelastic surfactant and HCl, with and without MgCl ₂ ;

in fig. 7 shows viscosity versus shear rate for spent VDA containing viscoelastic surfactant and HCl, with and without MgCl ₂ ;

in fig. 8 shows pore volume to break through (PVBT) versus flow rate for VDA containing viscoelastic surfactant and HCl, with and without MgCl2;

in fig. 9 shows channel configurations in limestone core after VDA treatment containing viscoelastic surfactant and HCl, with and without MgCl ₂ , and at the same flow rate of 0.2 ml/min;

in fig. 10 shows normalized pressure versus pore volume (PV) for VDA containing viscoelastic surfactant and HCl, with and without MgCl ₂ , at a flow rate of 6 ml/min;

in fig. 11 shows a computer simulated plot of MD (measured depth) versus channel radius (at 100/1 mD (millidarcy) permeability contrast at a total injection rate of 0.5 bbl/min VDA containing a viscoelastic surfactant and HCl, with MgCl ₂ and without it;

in fig. 12 shows a computer simulated plot of velocity per zone versus time (at 100/1 mD permeability contrast) at a total injection rate of 0.5 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl2;

in fig. 13 shows a computer simulated plot of MD (wellbore length) versus channel radius (at a permeability contrast of 100/1 mD) at a total injection rate of 1 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl2 ;

in fig. 14 shows a computer simulated plot of velocity per zone versus time (at a permeability contrast of 100/1 mD) at a total injection rate of 1 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl ₂ ;

in fig. 15 shows a computer simulated plot of MD (wellbore length) versus channel radius (at a permeability contrast of 100/1 mD) at a total injection rate of 5 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl2 ;

in fig. 16 shows a computer simulated plot of velocity per zone versus time (at a permeability contrast of 100/1 mD) at a total injection rate of 5 bbl/min VDA containing a viscoelastic surfactant and HCl, with and without MgCl2;

in fig. 17 shows a computer simulated plot of MD (wellbore length) versus channel radius (at a permeability contrast of 100/1 mD) at a total injection rate of 10 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl ₂ him;

in fig. 18 shows a computer simulated plot of velocity per zone versus time (at 100/1 mD permeability contrast) at a total injection rate of 10 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl ₂ ;

in fig. 19 shows a computer simulated plot of MD (wellbore length) versus channel radius (at a permeability contrast of 100/10 mD) at a total injection rate of 0.5 bbl/min VDA containing a viscoelastic surfactant and HCl, with MgCl2 and without him;

in fig. 20 shows a computer simulated plot of velocity per zone versus time (at 100/10 mD permeability contrast) at a total injection rate of 0.5 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl ₂ ;

in fig. 21 shows a computer simulated plot of MD (wellbore length) versus channel radius (at 100/10 mD permeability contrast) at a total injection rate of 1 bbl/min VDA containing a viscoelastic surfactant and HCl, with MgCl2 and without it;

in fig. 22 shows a computer simulated plot of velocity per zone versus time (at 100/10 mD permeability contrast) at a total injection rate of 1 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl ₂ ;

in fig. 23 shows a computer simulated plot of MD (wellbore length) versus channel radius (at 100/10 mD permeability contrast) at a total injection rate of 5 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl ₂ him;

in fig. 24 shows a computer simulated plot of velocity per zone versus time (at 100/10 mD permeability contrast) at a total injection rate of 5 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl2;

in fig. 25 shows a computer simulated plot of MD (wellbore length) versus channel radius (at 100/10 mD permeability contrast) at a total injection rate of 10 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl ₂ him;

in fig. 26 shows a computer simulated plot of velocity per zone versus time (at 100/10 mD permeability contrast) at a total injection rate of 10 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl ₂ ;

in fig. 27 shows a computer simulated plot of MD (wellbore length) versus channel radius (at a permeability contrast of 100/20 mD) at a total injection rate of 0.5 bbl/min VDA containing a viscoelastic surfactant and HCl, with MgCl2 and without him;

in fig. 28 shows a computer simulated plot of velocity per zone versus time (at 100/20 mD permeability contrast) at a total injection rate of 0.5 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl ₂ ;

in fig. 29 shows a computer simulated plot of MD (wellbore length) versus channel radius (at a permeability contrast of 100/20 mD) at a total injection rate of 1 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl ₂ him;

in fig. 30 shows a computer simulated plot of velocity per zone versus time (at 100/20 mD permeability contrast) at a total injection rate of 1 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl2;

in fig. 31 shows a computer simulated plot of MD (wellbore length) versus channel radius (at 100/20 mD permeability contrast) at a total injection rate of 5 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl2 ;

in fig. 32 shows a computer simulated plot of velocity per zone versus time (at 100/20 mD permeability contrast) at a total injection rate of 5 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl ₂ ;

in fig. 33 shows a computer simulated plot of MD (wellbore length) versus channel radius (at 100/20 mD permeability contrast) at a total injection rate of 10 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl2 ;

in fig. 34 shows a computer simulated plot of velocity per zone versus time (at 100/20 mD permeability contrast) at a total injection rate of 10 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl2;

in fig. 35 shows a computer simulated plot of MD (wellbore length) versus channel radius (at 100/50 mD permeability contrast) at a total injection rate of 0.5 bbl/min VDA containing viscoelastic surfactant and HCl with MgCl ₂ and without it;

in fig. 36 shows a computer simulated plot of velocity per zone versus time (at 100/50 mD permeability contrast) at a total injection rate of 0.5 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl2;

in fig. 37 shows a computer simulated plot of MD (wellbore length) versus channel radius (at 100/50 mD permeability contrast) at a total injection rate of 1 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl2 ;

in fig. 38 shows a computer simulated plot of velocity per zone versus time (at 100/50 mD permeability contrast) at a total injection rate of 1 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl ₂ ;

- 3 041391 in Fig. 39 shows a computer simulated plot of MD (wellbore length) versus channel radius (at 100/50 mD permeability contrast) at a total injection rate of 5 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl2 ;

in fig. 40 shows a computer simulated plot of velocity per zone versus time (at 100/50 mD permeability contrast) at a total injection rate of 5 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl ₂ ;

in fig. 41 shows a computer simulated plot of MD (wellbore length) versus channel radius (at 100/50 mD permeability contrast) at a total injection rate of 10 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl2 ; and in FIG. 42 shows a computer simulated plot of velocity per zone versus time (at 100/50 mD permeability contrast) at a total injection rate of 10 bbl/min VDA containing viscoelastic surfactant and HCl, with and without MgCl2.

Detailed description of the invention

The following description of variations is merely illustrative in nature and is in no way intended to limit the scope of the present invention, its scope or applications. The description and examples are provided herein solely for the purpose of illustrating various embodiments of the present invention and should not be construed as limiting the scope and applicability of the present invention. Although compositions in accordance with the present invention are described herein as containing certain substances, it should be understood that the composition may optionally contain two or more chemically different substances. In addition, the composition may also contain certain components other than those already given. In the Summary and Detailed Descriptions, each numerical value should be taken as modified by the term approximately (unless already explicitly so modified) and then read again as not so modified unless the context dictates otherwise. Also, when reading the Summary of the Invention and the Detailed Description of the Invention, it should be understood that a range of concentrations or amounts listed or described as applicable, suitable, etc., means any and every concentration or amount within the specified range, including extreme values. For example, the range from 1 to 10 should be taken to describe all possible numbers, without exception, on a continuum of about 1 to about 10. Thus, even if certain values are within the range, or none of the values are within the range, either denoted by only a few specific values, it is to be understood that the inventors mean and understand by this that any and all values within the range should be considered as indicated, and that the authors of the present invention have in mind the entire range and values within this range.

Unless expressly stated otherwise, or refers to an inclusive or and not an exclusive or. For example, conditions A or B satisfy any of the following conditions: A is true (or true) and B is false (or not true), A is false (or not true) and B is true (or true), and A and B are true (or true). ).

In addition, the use of the singular form is used to describe elements and components of the embodiments described herein. This is only for convenience and to provide a general sense of the ideas in accordance with the present invention. This description should be read as including one or at least one, and the singular form also includes the plural form, unless otherwise indicated.

The terminology and phraseology used in this document is for descriptive purposes and should not be construed as limiting in scope. An expression such as including, containing, having, containing, or including, as well as variants thereof, is provided in a broad sense and is intended to cover the subject matter herein specified, equivalents, and additional non-specified subject matter.

Also used herein, any reference to one embodiment or some embodiment means that a particular element, feature, structure, or characteristic described in connection with an embodiment is included in at least one embodiment. The occurrence of a phrase in one embodiment at various places in this specification does not necessarily refer to the same embodiment.

The terms formation or subterranean formation as used herein should be understood in a broad sense and are used interchangeably. The formation includes any subterranean fluidly connected porous formation and may include, without limitation, any formation for receiving or producing oil, gas, condensate, a mixture of hydrocarbons, paraffin, kerobitumen, water, and/or CO2. The formation may be in fluid communication with a wellbore, which may be an injection well, a production well, and/or a fluid storage well. The wellbore may pass through the formation vertically, horizontally, in a deviated orientation, or a combination of these. The formation may include any geological section, including at least sandstone, limestone, dolomite, shale, oil sand and/or uncemented formation. The wellbore may be a single wellbore and/or part of a series of wellbores directionally diverging from several closely spaced wellbores (e.g., at a remote site or wellsite), or a single parent wellbore that is subdivided into multiple wellbores. below the surface.

The term oilfield treatment fluid as used herein should be understood in a broad sense. In some embodiments, the oilfield treatment fluid includes any fluid having utility in oil fields, including a gas, oil, geothermal, or injection well. In some embodiments, the oilfield treatment fluid includes any fluid having applicability in any formation or wellbore described herein. In some embodiments, the oilfield treatment fluid includes a matrix acidizing fluid, a wellbore fluid, a pickling fluid, a bottomhole fouling fluid, a surfactant-based treatment fluid, a non-thickened fracturing fluid (e.g., a fracturing fluid). water-based fracturing) and/or any other fluid consistent with the fluids otherwise described herein. The oilfield treatment fluid may include any type of additive known in the art from those not listed herein for purposes of clarity herein, but which may at least include friction reducers, retarders, surfactants and/or wetting agents. agents, liquid diverting agents, particulates, acid retardants (except as otherwise provided herein), organic acids, chelating agents, activating agents (e.g. CO2 or N2), blowing agents, solvents, emulsifying agents, agents for flow control, resins, breakers and/or thickeners based on non-polysaccharides.

The term high pressure pump as used in this document should be understood in a broad sense. In some embodiments, the high pressure pump includes a positive displacement pump that provides a field-appropriate pumping rate, such as at least 0.5 barrels per minute (bpm), although the specific example is not restrictive. The high pressure pump includes a pump capable of pumping fluids at an appropriate field pressure, including at least 500 psi. inch, at least 1000 psi. inch, at least 2000 psi. inch, at least 5000 psi. inch, at least 10,000 psi. inch, not more than 15000 psi. inch and/or even higher pressures. Pumps suitable for field cementing, matrix acidizing, and/or fracturing treatments are available as high pressure pumps, although other pumps may be used.

The term processing concentration as used herein should be understood in a broad sense. The treatment concentration in the context of the HCl concentration is the final concentration in the fluid before the fluid is placed in the wellbore and/or formation to be treated, and may be any concentration necessary to provide sufficient acid function. The treatment concentration may be the concentration in the mixture available from the HCl-containing fluid at the location of the well or other location to which the fluid is supplied. The processing concentration can be modified by dilution before processing and/or during processing. Additionally, the processing concentration can be modified by adding additives to the liquid. In some embodiments, the processing concentration is determined prior to the addition of additives (eg, in a blender, hopper, or mixing tank) and the change in concentration due to the addition of additives is ignored. In some embodiments, the processing concentration is the concentration of the liquid phase or acid phase in a portion of the final liquid, for example, if the liquid is an activated or emulsified liquid.

The aqueous compositions described below and used in accordance with the present invention are characterized by delayed acid reactivity, which promotes greater depth of fracture and/or matrix acid treatment. The aqueous composition may contain, essentially consist of, or consist of: water; viscoelastic surfactant; acid and a water-soluble acid retarding agent. The acid may be selected from the group consisting of hydrochloric acid (HCl), nitric acid, phosphoric acid, sulfuric acid, hydrofluoric acid, hydrobromic acid, perchloric acid, hydrogen iodide, alkane sulfonic acids, arylsulfonic acids, acetic acid, formic acid, alkyl carboxylic acids, acrylic acid, lactic acid, glycolic acid, malonic acid, fumaric

- 5 041391 acid, citric acid, tartaric acid or their derivatives and mixtures thereof. Typically, the acid is transported to the location of the well. In certain embodiments, the acid is present in the aqueous compositions in an amount of not more than about 36% by weight, or from about 7.5% to about 36% by weight, or from about 7.5% to about 28% by weight, or from about 7.5 to about 20 wt.%, and in terms of the total weight of the composition. In certain other embodiments, the acid is present in the aqueous compositions in an amount of at least about 37% by weight.

In certain embodiments, the acid that has shown some utility in the aqueous composition of the present invention is hydrochloric acid. In certain other embodiments, the implementation of the aqueous composition may include some amount of hydrofluoric acid (HF). HF has different reactions than HCl and is useful in some applications to increase the activity of the resulting aqueous solution. For example, HF is used in sandstone formation flushing where HCl alone is not effective in correcting certain types of formation disturbances. It is believed that an aqueous solution in accordance with the present invention will exhibit similar effects with HF as observed with HCl. Accordingly, solutions can be formulated with a total amount of acid that is significantly higher than that of currently produced formulations. In yet another embodiment, HF is present in the aqueous composition in an amount of at least 0.25% by weight. HF may be present in addition to the amount of HCl and/or instead of the amount of HCl.

Other components of aqueous compositions useful in accordance with the present invention are water soluble acid retardants (RA) that have utility in slowing the rate at which an acid solution reacts with carbonate-mineral or other surfaces within a formation. Thus, the water-soluble acid retarding agent can retard the reactivity of an acid towards carbonate-mineral surfaces without disturbing its acidity. Such retardation is used in the context of enhancing or improving production from subterranean formations that contain hydrocarbons, steam, geothermal brines, and other valuable substances known in the art. Slowing down the reaction rate can allow acid to penetrate deeper into subterranean formations than conventional acid, thereby increasing formation permeability and productivity. The water-soluble acid retarding agents used herein include any agent that reduces acid activity by a mechanism other than simple dilution. The water-soluble acid retarding agent may contain a component selected from the group consisting of a salt, urea or one of its derivatives, an alpha-amino acid, a beta-amino acid, a gamma-amino acid, an alcohol with one to five carbon atoms, a surfactant having a structure in according to formula I or II below, and combinations thereof.

ABOUT

I

A C-N-R ₃ -Y

Formula I, wherein R1 is a hydrocarbon group, which may be branched or straight chain, aromatic, aliphatic, or olefinic, and contains from about 1 to about 26 carbon atoms, and may include an amine; R ₂ is hydrogen or an alkyl group containing from 1 to about 4 carbon atoms; R ₃ is a hydrocarbon group containing from 1 to about 5 carbon atoms; and Y is an electron withdrawing group. As an example of this embodiment, the zwitterionic surfactant has a betaine structure

ABOUT

Formula II in which R represents a hydrocarbon group, which may be branched or straight chain, aromatic, aliphatic or olefinic, and contains from about 1 to about 26 carbon atoms, and may include an amine; wherein n=from about 2 to about 4; and p=1 to about 5.

The salt may contain: i) a cation selected from the group consisting of lithium, sodium, potassium, rubidium, cesium, beryllium, magnesium, calcium, strontium, barium, scandium, yttrium, titanium, zirconium,

- 6 041391 hafnium, vanadium, niobium, tantalum, chromium, molybdenum, tungsten, manganese, technetium, rhenium, iron, ruthenium, osmium, cobalt, rhodium, iridium, nickel, palladium, platinum, copper, silver, gold, zinc, cadmium , mercury, boron, aluminum, gallium, indium, thallium, tin, ammonium, alkylammonium, dialkylammonium, trialkylammonium and tetraalkylammonium and combinations thereof; and ii) an anion selected from the group consisting of fluoride, chloride, bromide, iodide, sulfate, bisulfate, sulfite, bisulfite nitrate, alkane sulfonates, arylsulfonates, acetate, formate, and combinations thereof. According to the present embodiments, the retarding agent is added to the aqueous composition in an amount not exceeding its solubility limit in the aqueous composition. In certain embodiments, the water-soluble acid retarding agent is present in the aqueous composition(s) in an amount of not more than about 40 wt.%, or from about 1 to about 40 wt.%, or from about 5 to about 35 wt. .%, or from about 5 to about 20 wt.%, and in terms of the total weight of the aqueous composition.

In certain embodiments, such as in the presence of urea, the aqueous composition may include HCl as the acid at a weight fraction greater than 37%. The presence of a retarding agent in certain aqueous compositions useful in accordance with the present invention allows the proportion of HCl to be exceeded of 37%, which typically corresponds to the solubility limit of HCl at atmospheric pressure. Such retarding agents include at least one salt compound and urea or a urea derivative. Above 37%, as a rule, the release of gaseous HCl from the solution prevents any increase in the proportion of HCl. In one or more embodiments, the implementation of the mass fraction of HCl in aqueous solution can be up to 45.7 wt.%.

Without limiting to any particular theory, the authors of the present invention investigated the mechanisms by which the suppression of acid activity occurs. The first is related to the destruction of the network of hydrogen bonds in water. In the Grotthuss proton relay mechanism, protons move through water not by Brownian motion, but rather by charge transfer via moving hydrogen bonds. Solutes are known to disrupt the Grotthuss mechanism by interacting with water itself, rather than by allowing free binding of protons. This slows down the transfer of protons to the channel wall during matrix acid treatment. The introduction of saline solutions also has a similar second effect by simply changing the water. The absence of water molecules creates a spatial obstacle for the liquid and limits the diffusion of protons. The amount of RA present in the composition may be any concentration necessary to provide sufficient acid retarding function.

The second mechanism involves the dissociation of acids in solution. As stated, organic acids have higher _pKa values than HCl, which makes protons from such acids less available for reaction. In some aspects of the present invention, compounds are used that reduce the polarizability (as indicated by the dielectric constant) of water, which therefore reduces the dissociation of acid protons. It is believed that aqueous solutions can modify the activity of acids in water in one or both of these mechanisms.

The parameter by which acid retardation is quantified is the retardation factor. The deceleration factor described herein indicates the ratio of reaction rates on the visible surface. According to the present embodiments, the retardation factor for the aqueous composition is greater than or equal to the retardation factor of the second acid solution at the same concentration corresponding to the amount of acid contained in the aqueous composition without the retarding agent. For example, in various embodiments, the aqueous composition may have an acid retardation factor greater than or equal to about 3, at least about 5, or at least about 11 at about 70°F (21°C). At about 200°F (93°C), the composition may have an acid retardation factor that is greater than or equal to about 3, greater than or equal to about 5, or greater than or equal to about 7.

Water is present in the aqueous composition in an amount sufficient to dissolve the acid and the retarding agent. In accordance with embodiments according to the present invention, the concentration of water included in the aqueous composition may be greater than 0 wt.% and may be less than or equal to 80 wt.%. In various embodiments, the water concentration may be less than 60, or less, or less than 20 wt.%, and may be equal to or greater than 8 wt.%, or may be equal to or greater than 10 wt.%. In still other embodiments, the implementation of the concentration of water may be even less than 8 wt.%.

According to certain embodiments, the amount of water is mixed with the retarding agent, where the amount of water is present in an amount that is a multiple of 0.3 to 5 times the weight of the RA, any lower limit being 0.35, 0.4, or 0.45, and any upper limit may be 1.0, 1.2, 1.25, any lower limit may be combined with any upper limit. The procedure further includes dissolving some of the acid in the combined

- 7 041391 amount of water and RA. The acid, such as HCl, may be added by any method, such as bubbling gaseous HCl through the solution. The dissolution of HCl may be carried out after the dissolution of the RA, simultaneously with the dissolution of the RA, or at least partially before the dissolution of the RA. The amount of gaseous HCl in a molar ratio corresponds to a multiple of 4.0-0.5 of the amount of RA. In yet another embodiment, the procedure includes dissolving at least a portion of the RA in water while dissolving the HCl in the combined water and RA. Exemplary operations include initiating HCl dissolution and adding RA as a solid or solution, providing a certain amount of RA in solution with water and a certain amount of RA as a solid and/or providing RA as a solid in water, and dissolving HCl in water upon dissolution RA.

Viscoelastic surfactants (VES) form aqueous gels that are used as oil well treatments for hydraulic fracturing, sand control and diversion. US Patent No. 7237608, issued to Fu et al., SELF DIVERTING MATRIX ACID, filed with the US Patent Office on October 20, 2004, issued July 3, 2007, is incorporated herein by reference in its entirety, and it describes viscoelastic surfactants, including those applicable to the aqueous composition(s) described herein. The viscoelastic surfactant may be a zwitterionic surfactant having a structure according to formula III or IV below.

R _x --С—N—R ₃ —Y

Formula III wherein R1 is a hydrocarbon group which may be branched or straight chain, aromatic, aliphatic, or olefinic, and contains from about 17 to about 26 carbon atoms, and may include an amine; R2 is hydrogen or an alkyl group containing from 1 to about 4 carbon atoms; R ₃ is a hydrocarbon group containing from 1 to about 5 carbon atoms; and Y is an electron withdrawing group. As an example of this embodiment, the zwitterionic surfactant has a betaine structure:

ABOUT

Formula IV wherein R is a hydrocarbon group, which may be branched or straight chain, aromatic, aliphatic or olefinic, and contains from about 17 to about 26 carbon atoms, and may include an amine; wherein n=from about 2 to about 4; and p=1 to about 5.

The viscoelastic surfactant may be erucic amidopropyl dimethyl betaine. In certain embodiments, the viscoelastic surfactant is present in the aqueous composition(s) in an amount of not more than about 6% v/v. or from about 0.02 to about 6% v/v, or from about 0.04 to about 4% v/v, or from about 0.2 to about 3% v/v, wherein in terms of the total volume of the aqueous composition.

The aqueous composition may be in the form of a gel. The aqueous composition may have a lower viscosity at a pH below about 0 compared to the viscosity of an equivalent aqueous composition that does not contain a water-soluble acid retarding agent. The aqueous composition may have a viscosity at temperatures from about 70°F (21°C) to about 200°F (93°C) and a pH above about 3, which is higher than the viscosity of an equivalent aqueous composition that does not contain a water-soluble acid retarding agent.

Furthermore, it is also within the scope of the present invention that the aqueous compositions may be combined with one or more other additives known to those skilled in the art, such as, without limitation, other diverters such as, but not limited to, acrylamide polymers, fibers , such as from polylactic acid, nylon or cellulose, or solid particles, such as solid particles of polylactic acid, solid particles of sodium chloride or benzoic acid flakes, corrosion inhibitors, scale inhibitors, demulsifiers, foaming agents, hydrogen sulfide scavengers, reducing agents and/or chelating agents funds, etc. For example, surface-inactive substituted ammonium-containing amino acid derivatives can be used as environmentally friendly corrosion inhibitors that effectively protect various tools used in oilfield operations by treating the surfaces of such tools.

- 8 041391

The corrosion inhibitor is typically provided in liquid form and mixed with the other components of the surface treatment fluid and then injected into the formation. The corrosion inhibitor system is present in the treatment fluid in an amount of from about 0.2 to about 3% by weight of the total treatment fluid. The corrosion inhibitor used in the fluids of the present invention includes an alkyl, alkenyl, alicyclic or aromatic substituted aliphatic ketone which includes alkenylphenones, or an aliphatic or aromatic aldehyde which includes alpha or beta unsaturated aldehydes, or a combination thereof. Alkyl, alicyclic or aromatic phenones and aromatic aldehyde compounds can also be used in some applications. Other unsaturated ketones or unsaturated aldehydes may also be used. Alkynolphenones, aromatic and acetylenic alcohols and quaternary ammonium compounds, as well as mixtures thereof, may also be used. These may be dispersed in a suitable solvent such as alcohol and may further include a dispersant and other additives.

Chelating agents are substances that are used, among other purposes, to control unwanted reactions with metal ions. In oilfield chemical treatments, chelating agents are often added to treatment acids below fracture pressure to prevent solids settling (control of metal reactions) as the acids are consumed in the formation to be treated. Such deposits include iron hydroxide and iron sulfide. In addition, chelating agents are used as components in many formulations to remove/prevent deposits. Two different types of chelating agents can be used: polycarboxylic acids (including aminocarboxylic acids and polyaminopolycarboxylic acids) and phosphonates. Surface-inactive substituted ammonium-containing amino acid derivatives can function as chelating agents when present in the treatment fluid in an amount of from about 0.05 to about 10%, or from about 1 to about 5 wt.%, and in terms of the percentage of the total weight of the treatment fluid. processing.

Certain embodiments in accordance with the present invention are methods of treating a formation through which a wellbore passes. The methods include supplying an oilfield treatment fluid, including an aqueous composition described herein, to a high pressure pump and actuating the high pressure pump to treat at least one wellbore and a formation fluidly connected to the wellbore. In one embodiment, the aqueous composition is prepared by mixing an acid, a water-soluble acid retarding agent, a viscoelastic surfactant, and water present in an amount sufficient to dissolve the other components. The mode of operation of the pump may include at least one of the following: (i) pumping the treatment fluid into the formation at rates that are lower than those at which pressure is generated in excess of the fracturing pressure; (ii) pumping the treatment fluid into the formation at a pressure equal to the pressure at which the formation fracturing occurs; and (iii) contacting at least one wellbore and formation with the oilfield fluid for treatment.

Let us now turn to FIG. 1, it depicts a system 100 used to treat a wellbore 106 and/or a formation 108 in fluid communication with the wellbore 106. Formation 108 may be any type of formation with a bottomhole temperature not greater than about 204°C (400°F). In various embodiments, the temperature is at least 38°C (100°F). Also, the temperature may range from about 38°C to about 204°C. The wellbore 106 is depicted as a vertical cased and cemented wellbore 106 having perforations allowing fluid communication between the formation 108 and the interior of the wellbore 106 . However, certain elements of the wellbore 106 are not restrictive, and the example provides an illustrative option 100 for the procedure.

System 100 includes a high pressure pump 104 with an aqueous composition source 102 as described herein. The high pressure pump 104 is fluidly connected to the wellbore 106, in the example via high pressure lines 120. Exemplary system 100 includes a piping system 126 in a wellbore 106 . The piping system 126 is optional and non-limiting. In various embodiments, the piping system 106 may be omitted, a coiled tubing unit (not shown) may be present, and/or the high pressure pump 104 may be in fluid communication with the casing or annulus 128. The piping or casing may be made of steel.

Several additives (not shown) may be added to the aqueous composition 102 to provide an oilfield treatment fluid. The additives may be added to the mixer (not shown), to the mixing tank of the high pressure pump 104, and/or in any other manner. In one or more embodiments, the second liquid 110 may be a dilution liquid,

- 9 041391 and while the aqueous composition 102, combined with a certain amount of the second fluid 110, can form an oilfield treatment fluid. The dilution fluid may not contain acid and/or may contain acid at a lower concentration than the aqueous composition 102. The second fluid 110 may further include any other substances to be added to the oilfield treatment fluid, including additional amounts of RA. In some embodiments, additional RA solution 112 is present and may be added to aqueous composition 102 during the portion when aqueous composition 102 is used. Additional RA solution 112 may include the same or different RA as in aqueous composition 102 and/or may include RA at a concentration different from that of the aqueous composition.

High pressure pump 104 may provide treatment to wellbore 106 and/or formation 108, for example, by placing fluid therein, by pumping fluid into wellbore 106, and/or by pumping fluid into formation 108. Illustrative and non-limiting operations include any oilfield processing without limitation. Potential fluid flow paths include flowing from the high pressure pump 104 into the pipeline system 126, into the formation 108, and/or into the annulus 128. The fluid may be recirculated from the well prior to entering the formation 108, for example, using a powered pump 114. Referring again to FIG. 1, annular space 128 is shown in fluid communication in piping system 126. In various embodiments, annulus 128 and piping 126 may be separated (eg, using a hydraulic collar). Another exemplary fluid flow path involves flowing the oilfield treatment fluid into the formation at a rate that is below that at which pressure is generated in excess of the fracturing pressure (e.g., the rate at which the formation is capable of receiving fluid flow through normal porous flow), and/or at a rate at which pressure is generated in excess of the fracturing pressure. Fluid flow in the formation may either flow out of the formation and/or be washed away from the wellbore by the next fluid. Fluid flowing into the formation may flow into a shaft or reservoir (not shown), back into a fluid reservoir, prepared for processing, and/or directed in any other manner known in the art. Acid remaining in the recirculating fluid can be recovered or neutralized.

Another exemplary fluid flow includes an aqueous composition 102 comprising an acid, RA, and a viscoelastic surfactant. An exemplary fluid flow includes a second aqueous solution 116 including an acid and optionally RA. The fluid flow path includes, in sequence, a first high pressure pump 104 and a second high pressure pump 118 to effect formation 108 treatment. As seen in FIG. 1, the second high pressure pump 118 is in fluid communication with the piping system 126 via the second high pressure line 122. The fluid supply structure is optional and non-limiting. In one embodiment, a single pump may supply both the aqueous solution 102 and the second aqueous solution 116. In yet another example, either the first aqueous solution 102 or the second aqueous solution 116 may be supplied first, and one or more solutions 102, 116 may be delivered in multiple and alternating stages such that the aqueous composition 102 comprising acid, RA and viscoelastic surfactant enters the most permeable portion(s) of the formation to form a temporary plug, allowing a second aqueous solution 116 comprising acid and optionally RA, flow to and penetrate less permeable portions of the formation. Theoretically, the method may also include certain stages in which the solutions 102, 116 are mixed.

The following examples are provided to further illustrate the preparation and properties of wellbore treatment fluids in accordance with the present invention and should not be construed as limiting the scope of the present invention unless expressly stated otherwise in the appended claims.

Examples

Example 1

Various formulations were prepared using various retarding agents and HCl as the acid. A number of tests were carried out to evaluate such formulations. To fully evaluate the properties of the compositions obtained, tests were carried out in an autoclave at a hydrostatic pressure of not more than 3000 psi. inch, using thermal energy transmitted through a silicon oil bath. To determine the retardation factor (RF) for some additives, reaction tests were conducted in the formation with various acid-based formulations. In the experiments, limestone cores from Indiana, which were 1 inch in diameter and 6 inches long, were held at a rock pressure of ~2800 psi. inch to ensure that no liquids form channels on the sides and heated to the desired temperature. Acid-based fluids were passed through the core at a rock back pressure of ~1200 psi. inch,

- 10 041391 which provided conditions under which the acid would predominantly form channels. If the channel ran the entire length of the core, the pressure dropped along the core, approaching zero, indicating that the fluid was no longer flowing through the porous medium, but rather approaching the tortuous tube.

The fluid pore volume numbers required to form channels were plotted against acid injection rate (u _i , FIGS. 2 and 3). The optimal injection rate (uj. _o p _t ) is the one that requires the smallest numerical values of the pore volume for the channel in order to break through the core. Using this approach, curves of pore volume to breakthrough (PVBT) versus pore velocity curves were obtained and calculated (u _i-opt and RF for each acid-based composition (Table 1) at 70°F (Fig. 2) and 200 °F (Fig. 3).

Table 1. Retarding factors for acid-based formulations

Tempera Concentration retarding action slowing down Estimated Entrance tour means action coefficient (°F) Additive funds (% by mass) deceleration (RF)

1 2 3 no urea N,N'-dimethyl urea (DMU) MgC1 ₂ 18.5 27 19 3.3 5, 8 10, 9 4 70 5 6 200 absent urea 18.5 1.3 7 MdS1 ₂ 19 3, 1

The design deceleration factor was calculated according to the following equation / \ 2 ( ^u i-opt,HCl\

RF _X - I---------I\W-opt.x J

For all aqueous liquids, calculations were made in relation to the content of hydrochloric acid (15% w/v) and corrosion inhibitor (0.6% v/v). The results show that compounds that break the hydrogen bond network in water and lower its dielectric constant are capable of slowing down the action of acid in subterranean formations. In particular, magnesium chloride (MgCl ₂ ), used as a retarding agent, showed a significant delay at similar or lower concentrations compared to other retarding agents to be evaluated.

Channels in carbonate formations can have different structures depending on the rate of acid injection. At very low injection rates, there are no channels at all, since only the outer surface of the formation is dissolved. Channels that form at low injection rates tend to be wide and tapered. Near the optimum injection rate, a predominantly narrow channel with little branching is formed. If the pumping rate is increased beyond the optimal pumping rate, the acid is pushed into less permeable zones and forms a branching (highly branched) channel. At very high pumping rates, branching structures will transition to uniformly dissolved rock. By comparing the outer surface characteristics for core injection from the acid injection experiment described in the evaluations above, estimates of the channel characteristics can be obtained. In table. 2 shows the low acid injection rates, time to breakthrough, and pore volume values from the estimates above at 200°F, while FIG. 4A-C are graphical representations of core exterior and breakthrough performance at low acid injection rates at 200°F (photographic representations are provided in U.S. Provisional Application No. 62/154,945 and are provided herein by inclusion).

- 11 041391

Table 2—Exterior Core Surface Images and Breakthrough Characteristics at Low Acid Rates at 200°F

15% HC1+18.5% 15% HC1+19% Liquid => 15% HC1 urea MdS1 ₂

Pumping rate 0.2 0.3 0.2 (ml/min)

Time to > 3:30 > 1:30 0:34 breakthrough (h:mm) Pore volume values for >3.4 >3 0.53 breakthrough

In tests conducted at 200°F, with the outer surfaces of the core treated with 15% HCl (Fig. 4A) and 15% HCl with urea (Fig. 4B), both significant surface dissolution 402 of the core and the formation of conical channels 404 were demonstrated. However, in both cases, the overburden pressure was able to break through the sleeve holding the core, as too much of the outer surface of the rock was dissolved. For the 15% HCl with MgCl ₂ fluid (FIG. 4C), the inlet channel was significantly smaller and the channels 406 broke through to the opposite outer surface in a timely manner of 34 minutes at a breakthrough pore volume value of 0.53. This indicates that at lower injection rates, the MgCl ₂ delayed acid was effective. In table. 3 shows the results of the same experiment conducted at 250°F with similar comparative results in both data and surface dissolution as shown in FIG. 4D (for HCl per se) and FIG. 4E (for HCl with MgCl ₂ ). For HCl itself, significant surface dissolution 402 of the core and the formation of conical channels 404 occurred, while for a mixture of HCl and MgCl _2, slight surface dissolution and a narrower channel 406 were achieved.

Table 3. Core Breakthrough Characteristics at Low Acid Rates at 250°F

Liquid => 15% HC1 15% HC1 + 19% MgS1 ₂

Pumping speed (ml/min) 0.4 0.4 Time to breakout (h:mm) Volume values > 2:05 0:13 breakout pore > 4 0.34

Example 2

In another example, spinning disk experiments were performed to determine the relative rates of surface reactions of acidic solutions. The experiment was carried out by rotating a marble or limestone disk at ambient temperature and 1250 rpm in an acid-based composition while periodically sampling the solution. The samples were then analyzed for calcium concentration as a function of time, resulting in a dissolution rate constant of calcareous spar (CaCO ₃ ) with solutions containing hydrochloric acid. A decrease in the rate constant is indicative of a composition containing an acid retarding agent whose surface reaction is retarded relative to hydrochloric acid itself without any retarding agent. On the graph in Fig. 5 illustrates the slower dissolution rate or slower release rate of Ca ²⁺ ions over time for a 15% HCl solution containing MgCl ₂ compared to unmodified 15% HCl for 10 minutes. The results in FIG. 5 is a comparison of 15% HCl alone with 15% HCl mixed with 18.7% MgCl ₂ retardant.

Example 3

Viscoelastic diverting acids (VDA) consist of two main components: a viscoelastic surfactant and hydrochloric acid. The viscosity of the VDA increases significantly if the acid begins to react with the carbonate formation (i.e. if the pH rises) - causing at least a portion of the viscoelastic surfactant molecules to rearrange into worm-like micelles and form a gel-like structure.

For this example, fresh VDA included 36 v/v. HCl (37 wt.% solution), 49 vol./about. MgCl ₂ (35 wt.% solution), 5% vol./about. alcohol-containing solvent, 1.6% vol./about. corrosion inhibitor and 7.9% vol./about. viscoelastic surfactant (39 wt.% active component). Applicable

- 12 041391

VES was erucic amidopropyl dimethyl betaine. The rheological properties of fresh VDA (full HCl) and spent VDA (zero HCl) are measured at ambient temperature using a Fann 35 viscometer and compared to a VDA-based fluid that does not contain the MgCl2 salt in the formulation. Spent VDA was obtained by complete neutralization of HCl with a sufficient amount of calcium carbonate powder.

As shown in FIG. 6, the viscosity of fresh VDA containing magnesium chloride was about one order of magnitude lower than that of fresh VDA that did not contain magnesium chloride. Thus, the addition of a retarder to the VDA provides a reduction in friction losses during fluid injection.

As shown in FIG. 7, spent VDA containing magnesium chloride exhibits a higher viscosity compared to that of spent VDA without magnesium chloride. Thus, the presence of magnesium chloride could theoretically improve the deflection properties of the VDA.

Mechanically, it is believed that each of magnesium chloride and urea alone can break the hydrogen bond network of water such that free protons diffuse to reach the surface of the porous media of the formation. This slows down the diffusion of the acid. In addition, it is known that magnesium chloride can reduce the dielectric constant of water. Acids tend to have lower dissociation constants in less dielectric media. The activity of a proton can be reduced in this way by stimulating its binding to its counteranion.

Example 4

Core flooding experiments with modified VDA (as described in Example 3) were performed using limestone cores from Indiana with a permeability of 70 mD and a porosity of 17%. Each core had a length of 6 and a diameter of 1. Prior to testing, the cores were saturated with 2% KCl-based brine. The test temperature was 200°F. VDA was pumped at a constant rate into the core until it broke through the other end of the core (PVBT). The pumping rate of VDA was changed in the range of 0.1-6 ml/min. The dependence of PVBT on acid injection rate is shown in FIG. 8.

As can be seen in FIG. 8, the addition of magnesium chloride results in higher VDA efficiency (less drilling fluid required). In particular, improved performance of the modified VDA is observed at low pumping rates (below 6 ml/min). As shown in FIG. 9, the channel configuration also changes if a retarding agent (magnesium chloride) is present in the VDA. The channel becomes thinner and a smaller portion of the core surface is dissolved with the VDA containing magnesium chloride.

Example 5

VDA forms a viscous gel when it penetrates the core and reacts with limestone. The viscous gel resists the flow of fluid through the core, and the discharge pressure increases. VDA can be defined as the maximum pressure reached in the core in waterflood experiments before fluid breakthrough (dP _max /dP ₀ , where dP ₀ is the brine permeability).

In FIG. 10, it can be seen that the pressure increases when the original VDA and VDA modified with magnesium chloride are pumped through the core (as described in Example 3). Indeed, the addition of magnesium chloride to the VDA results in a slightly higher pressure for core flow at the same injection rate.

Example 6

By fitting the pressure rise data and the PVBT data with the new updated correlations, the inventors of the present invention used a laboratory acid treatment simulator for some simple examples to demonstrate the benefit of VDA with MgCl2.

The simulator used in this document to obtain the following simulation results is described in the following reference document and patents, each of which is incorporated herein by reference in its entirety:

P. M. J Tardy, B. Lecerf, Y. Christanti An Experimentally Validated Wormhole Model for Self-Diverting and Conventional Acids in Carbonate Rocks Under Radial Flow Conditions, paper SPE 107854 presented at the European Reservoir Disruption Conference, Scheveningen, The Netherlands , May 30 - June 1, 2007;

P.M.J Tardy METHOD FOR PREDICTING ACID PLACEMENT IN CARBONATE RESERVOIRS; U.S. Patent No. 7,603,261, filed with the U.S. Patent Office Nov. 29, 2006, issued Oct. 13, 2009;

P.M.J. Tardy, B. Lecerf FLOW OF SELF-DIVERTING ACIDS IN CARBONATE CONTAINING HYDROCARBON RESERVOIRS; U.S. Patent #7,774,183, filed with the U.S. Patent Office July 11, 2006, issued August 10, 2010.

In this example, two layers are provided with different translucency contrast values ranging from 100/1, 100/10, 100/20 mD to no more than 100/50 mD. For each of these permeability contrast values, different injection rates were used ranging from 0.5 bbl/min,

-

Claims (8)

1 bbl/min, 5 bbl/min to no more than 10 bbl/min. With the same volume of 500 gallons of VDA or VDA/MgCl2 injected into the formation, the velocity per zone and channel length results were plotted to compare VDA/MgCl2 to baseline VDA. The input data for the example can be found in the table. The input data for the model also included the composition of the fluids obtained for Examples 3 and 4, and the PVBT data in FIG. 8 and the pressure reduction data in FIG. 10. Input data Zone 1 Zone 2 Thickness, ft 50 50 Penetration, mD 100 1-50 Porosity 15 15 Zone pressure, lb per sq. inch 3206 3206 The simulation results are shown in Fig. 11-42. From the simulation results, it can be concluded that for all the cases presented, VDA/MgCl ₂ shows a deeper penetration into the channel compared to the original VDA due to the improved retardation factor. Also, if the permeability contrast is reduced to 10 or less and the velocity is increased to 1 bbl/min or more, the deviation starts to affect the flow distribution between the two zones. Based on the simulation results, VDA/MgCl ₂ shows an improved diverting effect due to different pressure rise patterns for the two fluids. The above description of the embodiments has been provided for purposes of illustration and description. The exemplary embodiments are provided so that the description will be sufficiently exhaustive and convey the scope to those skilled in the art. The numerous details set forth, such as examples of specific components, devices, and methods, are provided to provide a thorough understanding of the embodiments of the present invention, but are not intended to exhaust or limit the present invention. It will be understood within the scope of the present invention that the individual elements or features of a particular embodiment are generally not limited to that particular embodiment, but, where applicable, are interchangeable and may be used in the selected embodiment, even if not specifically stated or described. . It can also be modified in various ways. Such changes should not be construed as a departure from the present invention, and all such modifications are intended to be included within the scope of the present invention. In addition, in some illustrative embodiments, well-known methods, well-known device structures, and well-known technologies are not described in detail. In addition, it will be apparent to those skilled in the art that changes in device design, construction, condition, erosion of components, gaps between components may occur during the development, manufacture and operation of the device to achieve the result described in the description, for example. Although the terms first, second, third, etc. may be used herein to describe various elements, components, regions, layers and/or regions, such elements, components, regions, layers and/or regions should not be limited to such terms. Such terms can only be used to distinguish one element, component, region, layer or area from another area, layer or area. Terms such as first, second, and other numerical terms used herein do not imply sequence or order unless clearly indicated in the context. Thus, the first element, component, region, layer, or region discussed below may be referred to as the second element, component, region, layer, or region, without departing from the teachings of the illustrative embodiments. While several embodiments of the present invention have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible without substantially deviating from the teachings of the present invention. Accordingly, such modifications are within the scope of the present invention as defined in the claims. CLAIM 1. An aqueous composition for treating a geological formation through which a wellbore passes, comprising: water; viscoelastic surfactant, while the viscoelastic surfactant - 14 041391 the substance has a structure in accordance with formula III E<2 I Ri--C N - R ₃ -Y Formula III wherein R1 is a hydrocarbon group which may be branched or straight chain, aromatic, aliphatic or olefinic and contains from 17 to 26 carbon atoms and may include an amine; R ₂ represents hydrogen or an alkyl group containing from 1 to 4 carbon atoms; R3 is a hydrocarbon group containing 1 to 5 carbon atoms; and Y is an electron withdrawing group; hydrochloric acid present in a concentration of from 7.5 to 45.7 wt.%, a corrosion inhibitor based on a surface-inactive substituted ammonium-containing amino acid derivative, and a water-soluble acid retarding agent in an amount of from 1 to 40 wt.%, containing at least one of: magnesium chloride (MgCl ₂ ), urea, a urea derivative, or a combination thereof. 2. An aqueous composition according to claim 1, characterized in that the water-soluble acid retarding agent additionally contains one or more compounds from the group consisting of alpha-amino acid, beta-amino acid, gamma-amino acid, alcohol with one to five carbon atoms, surfactant a substance having a structure in accordance with formula I, and combinations thereof Rx C—N—R ₃ —Y Formula I, in which R ₁ represents a hydrocarbon group, which may be branched or straight chain, aromatic, aliphatic or olefinic, and contains from 1 to 26 carbon atoms, and may include an amine; R ₂ represents hydrogen or an alkyl group containing from 1 to 4 carbon atoms; R ₃ is a hydrocarbon group containing 1 to 5 carbon atoms; and Y is an electron withdrawing group. 3. An aqueous composition according to claim 1, characterized in that the viscoelastic surfactant is an erucic amidopropyl dimethyl betaine. 4. An aqueous composition according to claim 1, characterized in that the aqueous composition is in the form of a gel. 5. An aqueous composition according to claim 4, wherein the composition has a lower viscosity at a pH below 0 compared to the viscosity of an equivalent aqueous composition that does not contain a water-soluble acid retarding agent. 6. An aqueous composition according to claim 1, having a viscosity at temperatures from 70°F (21°C) to 200°F (93°C) and a pH above 3, which is higher than the viscosity of an equivalent aqueous composition that does not contain water-soluble acid retarder means. 7. An aqueous composition according to claim 6, characterized in that the water-soluble acid retarding agent contains magnesium chloride (MgCl2). 8. A method for treating a geological formation through which a wellbore passes, comprising: a) dissolving the water-soluble acid retarding agent in water in an amount of from 1 to 40 wt.% to form a mixture, wherein the water-soluble acid retarding agent contains at least one of: magnesium chloride (MgCl2), urea, a urea derivative, or a combination thereof; b) simultaneous or sequential addition to said mixture of a viscoelastic surfactant, wherein the viscoelastic surfactant has a structure according to formula III o r ₂ II I Rx C N-R ₃ -Y Formula III wherein R ₁ is a hydrocarbon group which may be branched or straight chain, aromatic, aliphatic or olefinic and contains from 17 to 26 carbon atoms, -