EA041225B1 - INJECTION MIXING ACIDS AND DIFFERENT LIQUIDS WITH WATER-SOLUBLE RETAILER AGENTS - Google Patents

Description

Technical field

The present invention relates to the mixing of acids and diversion fluids containing water soluble acid retardants during injection.

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 pumping 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 formation. 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.

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.

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. The inventors of the present invention have also extended the water soluble retarding agents to deflection technologies. All-water systems provide mixing during injection of stimulation fluid components, which in turn provide real-time tunable systems and more efficient operations at the well location. The present inventors herein describe a system where acid and/or diverting fluid can be mixed with a water soluble retarding agent just prior to entering the wellbore during a stimulation 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, methods are provided for treating a subterranean formation comprising a) mixing at a well location an acid from an acid source with water from a water source and a water soluble acid retarding agent (RA) from an RA source to form a delayed acid treatment fluid, and b ) introducing a delayed acid treatment fluid into the subterranean formation through a wellbore in fluid communication with the subterranean formation. A viscoelastic surfactant (VES) from a source of VES can also be mixed with acid, water and RA in step a) to form a delayed acid treatment fluid.

- 1 041225

In another aspect of the present invention, systems for stimulating production from subterranean formations are provided, including: a subterranean formation having a wellbore in fluid communication with the subterranean formation; a treatment fluid supply line in fluid communication with the wellbore; an acid source in fluid communication with the treatment fluid supply line; a water source in fluid communication with the treatment fluid supply line; and a source of water soluble acid retardant (RA source) in fluid communication with the treatment fluid supply line. The system may also include a viscoelastic surfactant source (VES source) in fluid communication with the treatment fluid supply line.

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 illustrate various implementations described herein and are not intended to limit the scope of the various technologies described herein, nor are:

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;

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 VDAs 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 MgCl2, at a flow rate of 6 ml/min.

In FIG. 11 shows a computer simulated plot of MD (measured depth) versus channel radius (at a permeability contrast of 100 mD (millidarcy)/1 mD) at a total injection rate of 79.5 l (0.5 bbl)/min VDA containing a viscoelastic superficial -active substance and HCl, with and without MgCl ₂₂ .

In FIG. 12 shows a computer simulated plot of velocity per zone versus time (at a permeability contrast of 100 mD/1 mD) at a total injection rate of 79.5 L (0.5 bbl)/min VDA containing a viscoelastic surfactant and HCl, with and without MgCl ₂ .

In FIG. 13 shows a computer simulated plot of MD (wellbore length) versus channel radius (at a permeability contrast of 100 mD/1 mD) at a total injection rate of 159 L (1 bbl)/min VDA containing a viscoelastic surfactant and HCl, with and without MgCl ₂ .

In FIG. 14 shows a computer simulated plot of velocity per zone versus time (at a permeability contrast of 100 mD/1 mD) at a total injection rate of 159 L (1 bbl)/min VDA containing a viscoelastic surfactant and HCl, with MgCl ₂ and without him.

In FIG. 15 shows a computer simulated plot of MD (wellbore length) versus channel radius (at a permeability contrast of 100 mD/1 mD) at a total injection rate of 794.9 L (5 bbl)/min VDA containing a viscoelastic surfactant and HCl, with and without MgCl ₂ .

In FIG. 16 shows a computer simulated plot of velocity per zone versus time (at a permeability contrast of 100 mD/1 mD) at a total injection rate of 794.9 L

- 2 041225 (5 bbl)/min VDA containing viscoelastic surfactant and HCl, with and without MgCl ₂ .

In FIG. 17 shows a computer simulated plot of MD (wellbore length) versus channel radius (at a permeability contrast of 100 mD/1 mD) at a total injection rate of 1590 L (10 bbl)/min VDA containing a viscoelastic surfactant and HCl, with and without MgCl ₂ .

In FIG. 18 shows a computer simulated plot of velocity per zone versus time (at 100 mD/1 mD permeability contrast) at a total injection rate of 1590 L (10 bbl)/min VDA containing viscoelastic surfactant and HCl, with and without MgCl2 him.

In FIG. 19 shows a computer simulated plot of MD (wellbore length) versus channel radius (at a permeability contrast of 100 mD/10 mD) at a total injection rate of 79.5 l (0.5 bbl)/min VDA containing a viscoelastic surfactant substance and HCl, with and without MgCl2.

In FIG. 20 shows a computer simulated plot of velocity per zone versus time (at a permeability contrast of 100 mD (millidarcy)/10 mD) at a total injection rate of 79.5 L (0.5 bbl)/min VDA containing a 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 mD/10 mD permeability contrast) at a total injection rate of 159 L (1 bbl)/min VDA containing a viscoelastic surfactant and HCl, with and without MgCl2.

In FIG. 22 shows a computer simulated plot of velocity per zone versus time (at a permeability contrast of 100 mD (millidarcy)/10 mD) at a total injection rate of 159 L (1 bbl)/min VDA containing a viscoelastic surfactant and HCl, with MgCl ₂ and without it.

In FIG. 23 shows a computer simulated plot of MD (wellbore length) versus channel radius (at 100 mD/10 mD permeability contrast) at a total injection rate of 794.9 L (5 bbl)/min VDA containing a viscoelastic surfactant and HCl, with and without MgCl ₂ .

In FIG. 24 shows a computer simulated plot of velocity per zone versus time (at a permeability contrast of 100 mD (millidarcy)/10 mD) at a total injection rate of 794.9 L (5 bbl)/min VDA containing a 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 mD/10 mD permeability contrast) at a total injection rate of 1590 L (10 bbl)/min VDA containing a viscoelastic surfactant and HCl, with and without MgCl ₂ .

In FIG. 26 shows a computer simulated plot of velocity per zone versus time (at a permeability contrast of 100 mD (millidarcy)/10 mD) at a total injection rate of 1590 L (10 bbl)/min VDA containing a viscoelastic surfactant and HCl, with MgCl ₂ and without it.

In FIG. 27 shows a computer simulated plot of MD (wellbore length) versus channel radius (at 100 mD/20 mD permeability contrast) at a total injection rate of 79.5 L (0.5 bbl)/min VDA containing a viscoelastic surfactant substance and HCl, with and without MgCl2.

In FIG. 28 shows a computer simulated plot of velocity per zone versus time (at a permeability contrast of 100 mD (millidarcy)/20 mD) at a total injection rate of 79.5 L (0.5 bbl)/min VDA containing a 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 100 mD/20 mD permeability contrast) at a total injection rate of 159 L (1 bbl)/min VDA containing a viscoelastic surfactant and HCl, with and without MgCl ₂ .

In FIG. 30 shows a computer simulated plot of velocity per zone versus time (at a permeability contrast of 100 mD (millidarcy)/20 mD) at a total injection rate of 159 L (1 bbl)/min VDA containing a viscoelastic surfactant and HCl, with MgCl2 and without it.

In FIG. 31 shows a computer simulated plot of MD (wellbore length) versus channel radius (at 100 mD/20 mD permeability contrast) at a total injection rate of 794.9 L (5 bbl)/min VDA containing a viscoelastic surfactant and HCl, with and without MgCl ₂ .

- 3 041225

In FIG. 32 shows a computer simulated plot of velocity per zone versus time (at a permeability contrast of 100 mD (millidarcy)/20 mD) at a total injection rate of 794.9 L (5 bbl)/min VDA containing a viscoelastic surfactant and HCl , With

MgCl ₂ and without it.

In FIG. 33 shows a computer simulated plot of MD (wellbore length) versus channel radius (at 100 mD/20 mD permeability contrast) at a total injection rate of 1590 L (10 bbl)/min VDA containing a viscoelastic surfactant and HCl, with and without MgCl ₂ .

In FIG. 34 shows a computer simulated plot of velocity per zone versus time (at a permeability contrast of 100 mD (millidarcy)/20 mD) at a total injection rate of 1590 L (10 bbl)/min VDA containing a viscoelastic surfactant and HCl, with MgCl2 and without it.

In FIG. 35 shows a computer simulated plot of MD (wellbore length) versus channel radius (at a permeability contrast of 100 mD/50 mD) at a total injection rate of 79.5 L (0.5 bbl)/min VDA containing a viscoelastic surfactant substance and HCl, with and without MgCl ₂ .

In FIG. 36 shows a computer simulated plot of velocity per zone versus time (at a permeability contrast of 100 mD (millidarcy)/50 mD) at a total injection rate of 79.5 L (0.5 bbl)/min VDA containing a viscoelastic surfactant. and HCl, with and without MgCl ₂ .

In FIG. 37 shows a computer simulated plot of MD (wellbore length) versus channel radius (at 100 mD/50 mD permeability contrast) at a total injection rate of 159 L (1 bbl)/min VDA containing a viscoelastic surfactant and HCl, with and without MgCl2.

In FIG. 38 shows a computer simulated plot of velocity per zone versus time (at a permeability contrast of 100 mD (millidarcy)/50 mD) at a total injection rate of 159 L (1 bbl)/min VDA containing a viscoelastic surfactant and HCl, with MgCl ₂ and without it.

In FIG. 39 shows a computer simulated plot of MD (wellbore length) versus channel radius (at 100 mD/50 mD permeability contrast) at a total injection rate of 794.9 L (5 bbl)/min VDA containing a viscoelastic surfactant and HCl, with and without MgCl2.

In FIG. 40 shows a computer simulated plot of velocity per zone versus time (at a permeability contrast of 100 mD (millidarcy)/50 mD) at a total injection rate of 794.9 L (5 bbl)/min VDA containing a viscoelastic surfactant and HCl , with and without MgCl2.

In FIG. 41 shows a computer simulated plot of MD (wellbore length) versus channel radius (at 100 mD/50 mD permeability contrast) at a total injection rate of 1590 L (10 bbl)/min VDA containing a viscoelastic surfactant and HCl, with and without MgCl ₂ .

In FIG. 42 shows a computer simulated plot of velocity per zone versus time (at a permeability contrast of 100 mD (millidarcy)/50 mD) at a total injection rate of 1590 L (10 bbl)/min VDA containing a viscoelastic surfactant and HCl, with MgCl2 and without it.

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 from about 1 to about 10. Thus,

- 4 041225 even if certain values within the range, or none of the values within the range, are explicitly indicated or denoted by only a few specific values, it should be understood that the inventors mean and understand by this that any and all values within 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 done for convenience only, 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 include at least friction reducers, retarders, surfactants, and/or wetting agents. , liquid diverting agents, solid particles, 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 flowback regulators, 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 delivers a field-specific injection rate, such as at least 0.5 bpm (79.5 liters) per minute (bpm), although the specific the example is not restrictive. The high pressure pump includes a pump capable of pumping fluids at a pressure appropriate to the field, including at least 3.447 MPa (500 psi), at least 6.895 MPa (1000 psi), according to at least 13.79 MPa (2000 psi), at least 34.47 MPa (5000 psi), at least 68.95 MPa (10000 psi), not more than 103 .4 MPa (15,000 psi) 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 delayed acidizing fluids 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 acidizing. The delayed acidizing fluid may comprise, consist essentially of, or consist of: water; acid and a water-soluble, acid-retarding agent. The delayed acidizing fluid may further comprise a viscoelastic surfactant (VES). 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 acid, citric acid, tartaric acid or derivatives thereof and mixtures thereof. Typically, the acid is transported to the location of the well. In certain embodiments, the acid is present in the delayed acid treatment fluids in an amount of not more than about 36 wt.%, or from about 7.5 to about 36 wt.%, or from about 7.5 to about 28 wt. .%, 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 delayed acidizing fluids in an amount of at least about 37% by weight.

In certain embodiments, the acid that has shown some utility in a delayed acid treatment fluid according to the present invention is hydrochloric acid. In certain other embodiments, the delayed acid treatment fluid may include an 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 the delayed acidizing fluid of 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 presently obtained formulations. In yet another embodiment, HF is present in the delayed acidizing fluid 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 delayed acid treatment fluid components useful in accordance with the present invention are water soluble acid retardants (RA) that have utility in slowing down the rate at which the acid solution reacts with carbonate-mineral or other surfaces within the formation. . Thus, a water-soluble acid retarding agent can retard the reaction

- 6 041225 ability of acid in relation to 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 structure according to formula I or formula II below, and combinations thereof.

About _R2

R _x --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; 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:

Formula 11 wherein R 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; 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, 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 delayed acidizing fluid in an amount not exceeding its solubility limit in the delayed acidizing fluid. In accordance with certain embodiments, the water-soluble retarding agent is present in the delayed acid treatment fluid(s) in an amount of not more than about 40 wt.%, or from about 1 to about 40 wt.%, or from about 5 up to about 35 wt.%, or from about 5 to about 20 wt.%, and in terms of the total weight of the liquid for acidizing delayed action.

In certain embodiments, the delayed acid treatment fluid may include HCl as the acid at a weight fraction greater than 37%. The presence of a retarding agent in certain delayed acidizing fluids 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 weight fraction of HCl in the delayed acid treatment fluid can be up to 45.7 wt%.

In certain embodiments, the delayed acid treatment fluid may include HCl as the acid at a mass fraction greater than 37%. The presence of a retarding agent in certain delayed acidizing fluids 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 weight fraction of HCl in the delayed acid treatment fluid can be up to 45.7 wt%.

Without wishing to be bound by any particular theory, the present inventors have investigated the mechanisms by which the activity of acids is suppressed. The first is related to the disruption of the hydrogen bond network of 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 are characterized by higher pKa values compared to HCl, which makes protons from such acids less available for the 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 acid proton dissociation. 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 delayed acid treatment fluid is greater than or equal to the retardation factor of a second acid solution of the same concentration corresponding to the amount of acid contained in the delayed acid treatment fluid without retarding agent. For example, in various embodiments, a delayed acid treatment fluid may have an acid retardation factor greater than or equal to about 3, at least about 5, or at least about 11 at about 21°C (70°F). At about 200°F, a delayed acid treatment fluid may have an acid retardation factor 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 delayed acid treatment fluid in an amount sufficient to dissolve the acid and the retardant. In accordance with embodiments according to the present invention, the concentration of water included in the delayed acidizing fluid 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 wt.%, or less than 40 wt.%, 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 a combined 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 the 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

- 8 041225 baking RA as a solid in water and dissolving HCl in water while dissolving 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 delayed acid treatment fluid(s) described herein. The viscoelastic surfactant may be a zwitterionic surfactant having a structure according to formula III or formula 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; R3 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:

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 accordance with certain embodiments, the viscoelastic surfactant is present in the delayed acidizing fluid(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 based on total volume of delayed acidizing fluid.

Delayed Acid Treatment Fluid is available in the form of a gel. The delayed acid treatment fluid may have a lower viscosity at a pH below about 0 compared to the viscosity of an equivalent delayed acid treatment fluid that does not contain a water-soluble acid retarding agent. The delayed acidizing fluid may have a viscosity at temperatures from about 21°C (70°F) to about 93°C (200°F) and a pH greater than about 3, which is higher than the viscosity of an equivalent delayed acidizing fluid that does not contains a water-soluble acid retarding agent.

Additionally, it is also within the scope of the present invention that delayed acidizing fluids may be combined with one or more other additives known to those skilled in the art, such as, but not limited to, corrosion inhibitors, scale inhibitors, demulsifiers, foaming agents, hydrogen sulfide scavengers, reducing agents and/or chelating agents, and the like. 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.

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

- 9 041225 aliphatic or aromatic aldehyde, which includes alpha or beta unsaturated aldehydes, or a combination of these. 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 if present in the treatment fluid in an amount of from about 0.05% to about 10%, or from about 1 wt.% to about 5 wt.%, and in terms of percentage the total mass of liquid to be processed.

Deflecting fluids are described below and are applicable in accordance with the present invention. Deflecting fluids may contain, consist of, or essentially consist of water, VES as described herein, acid as described herein, and RA as also described herein.

In accordance with certain embodiments, VES is present in the diversion fluid(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 deflecting fluid. In certain embodiments, RA is present in the diverting fluid(s) in an amount of not more than about 40% by weight, or from about 1 to about 40% by weight, or from about 5 to about 35% by weight, or from about 5 to about 20 wt.%, and in terms of the total weight of the deflecting fluid.

Water is present in the deflection fluid(s) in an amount sufficient to dissolve the VES and RA. In accordance with embodiments according to the present invention, the concentration of water included in the deflection fluid 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 wt.%, or less than 40 wt.%, 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.%.

Certain embodiments in accordance with the present invention are methods of treating a formation through which a wellbore passes. The methods include separately mixing at the well location the acidizing fluid components, the delayed acidizing fluid, and the diverting fluid.

In accordance with embodiments of the present invention and with reference to FIG. 1 method of treating a subterranean formation includes, consists of, or essentially consists of:

a) mixing at well location 100 acid from acid source 102 with water from water source 104 and a water-soluble acid retarding agent (RA) from RA source 106 to form a delayed acid treatment fluid, and

b) introducing a delayed acid treatment fluid into the subterranean formation through a wellbore 108 in fluid communication with the subterranean formation (not shown). The subterranean formation may be any type of formation with a bottom hole temperature of no more than about 204°C (400°F). In various embodiments, the temperature is at least 38°C (100°F). The temperature may also be in the range from about 38°C to about 204°C.

In accordance with one embodiment, VES from VES source 110 may also be mixed with acid, water and RA in step a) to form a delayed acid treatment fluid.

In accordance with one embodiment, a solid diverter from a source of solid diverter may also be mixed with acid, water and RA in step a) to form a delayed acidizing fluid, the solid diverter being selected from the group consisting of fiber, solid particles and their combinations. The solid particles may contain polylactic acid.

In accordance with one embodiment, after the introduction of the delayed acid treatment fluid in step b) is followed by:

c) generating a diverting fluid by mixing at the well location VES from VES source 110 with water from water source 104 and RA from RA source 106, and

d) introducing a diverting fluid into the subterranean formation through the wellbore 108 .

According to one embodiment, prior to the introduction of the delayed acid treatment fluid, step b) is followed by:

c) forming a diverting fluid by mixing at the well site a viscoelastic surfactant (VES) from the VES source with water from the water source, acid from the acid source, and RA from the RA source, and

d) introducing a diverting fluid into the subterranean formation through the wellbore.

According to one embodiment, step e) may include repeating steps a) and b) after step d). According to one embodiment, steps a) to e) may be repeated at least once. In addition, the acidizing fluid may be formed by mixing the acid from the acid source 102 with water from the water source 104 and introducing the acidizing fluid into the subterranean formation through the wellbore 108 prior to the first introduction of the delayed acidizing fluid in step b).

In accordance with one embodiment, each of the acid, water, and RA may be separately introduced into a treatment fluid supply line 112 in which a delayed acid treatment fluid is formed, with the treatment fluid supply line 112 in fluid communication. environment with the wellbore 108.

In accordance with one embodiment, each of the VES, water, and RA is separately introduced into the processing fluid supply line 112, in which the diverting fluid is formed.

According to one embodiment, the acidizing fluid is formed by mixing the acid from the acid source 102 with water from the water source 104 and introducing the acidizing fluid into the subterranean formation through the wellbore 108 prior to introducing the delayed acidizing fluid in step b).

According to one embodiment, pumps 114 and associated valves (not shown) are in fluid communication between treatment fluid supply line 112 and each of i) acid source 102, ii) water source 104, iii) RA source 106, and iv ) source 110 VES.

In accordance with one embodiment, any one or more of the acidizing fluid, the delayed acidizing fluid, and the diverting fluid may be analyzed in the analyzer 116 prior to injection into the wellbore 108 for fluid composition and properties, wherein the composition of the fluid is compared to the fluid composition setpoint and the composition of one or more of the acidizing fluid, the delayed acidizing fluid, and the diverting fluid are controlled by adjusting the flow rates of one or more of the acid, water, RA, and VES through the pumps 114 and respective valves based on the comparison.

With additional reference to FIG. 1, the systems comprise, consist of, or essentially consist of: a subterranean formation (not shown) having a wellbore 108 in fluid communication with the subterranean formation; a line 112 for supplying a treatment fluid in fluid communication with the wellbore 108; an acid source 102 in fluid communication with the treatment fluid supply line 112; a water source 104 in fluid communication with the treatment fluid supply line 112; and a source 106 of a water soluble, acid retarding agent (RA source) in fluid communication with the treatment fluid supply line 112.

According to one embodiment, the system may further comprise a source 110 of a viscoelastic surfactant (a diversion fluid source or VES) in fluid communication with the treatment fluid supply line 112 .

According to one embodiment, the system may further comprise a solid diverter source 111 in fluid communication with the treatment fluid supply line 112.

According to one embodiment, pumps 114 and associated valves (not shown) are in fluid communication between treatment fluid supply line 112 and each of i) acid source 102, ii) water source 104, iii) RA source 106, and iv ) source 110 VES. In accordance with one embodiment, the solid diverter source 111 is in fluid communication with the solid diverter addition system 113, and the solid diverter addition system 113 is in fluid communication with the treatment fluid supply line 112.

In accordance with one embodiment, the system may further comprise an analyzer 116 in fluid communication with the treatment fluid supply line 112 and a controller 118 operably coupled to the analyzer 116 to receive a control signal and operably coupled to the system. 113 to add a solid diverter, and pumps 114 and associated valves to control the flow of one or more of acid, water, RA, VES, and a solid diverter.

The mode of operation of the pumps 114 may be in fluid communication with the high pressure pump 107 in fluid communication with the treatment fluid supply line 112 . The mode of operation of the high pressure pump 107 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 a pressure greater than the fracturing pressure is generated; (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.

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 20.68 MPa (3000 psi), using thermal energy transmitted through a bath of silicon oil. 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 25.4 mm (1 in) in diameter and 152.4 mm (6 in) long, were held at a rock pressure of ~19.31 MPa (2800 psi). ) to ensure that there were no liquids forming channels on the sides and heated to the desired temperature. Acid-based fluids were passed through the core at a rock back pressure of ~8.274 MPa (1200 psi), 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 (ui, FIGS. 2 and 3). The optimal injection rate (u _i-opt ) is that which 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 intrapore velocity curves were obtained and u _i-opt and RF were calculated for each acid-based composition (Table 1) at 21°C (70°F) (Fig. 2) and 93.3°C (200°F) (Fig. 3).

Table 1. Retarding factors for acid-based formulations

Entrance Temperature (°F) Concentration Delay agent Additive retarding agent (% by mass) Rated Deceleration Ratio (RF) 1 absent - - 2 70 urea 18.5 3.3 3 Ν, Ν'-dimethyl 27 5.8 urea (DMU) 4 MdS1 ₂ 19 10.9 5 absent - - 6 200 urea 18.5 1.3 7 MdS1 ₂ 19 h, 1

The design deceleration factor was calculated according to the following equation:

/ \2 \ W-ορί,χ /

For all aqueous liquids, a calculation was made in relation to the content of hydrochloric acid

- 12 041225 slots (15% w/v) and corrosion inhibitor (0.6% by volume). 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 93.3°C (200°F), while FIG. 4A-C are graphical representations of core exterior and low rate acid breakthrough performance at 93.3°C (200°F) (photographic representations are provided in U.S. Provisional Application No. 62/154,945 and are provided herein). document by including).

Table 2—External core surface images and low rate acid breakthrough performance at 93.3°C (200°F)

Liquid => 15% HC1 15% HC1+18.5% urea 15% HC1 + 19% MgS1 ₂ Speed injection 0.2 0.3 0.2 (ml/min) Time to breakthroughs > 3:30 > 1:30 0:34 (h:mm) Volume values time for > 3.4 > 3 0.53 breakthroughs

In tests conducted at 93.3°C (200°F) with the outer surfaces of the core treated with 15% HCl (FIG. 4A) and 15% HCl with urea (FIG. 4B), significant surface dissolution of 402 cores was demonstrated, and the formation of conical channels 404. However, in both cases, the rock pressure provided a punching of the sleeve holding the core, because 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 MgCl2 delayed acid was effective. In table. 3 shows the results of the same experiment conducted at 121.1°C (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.

- 13 041225

Table 3—Core Break Characteristics at Low Acid Rates at 121.1°C (250°F)

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

Upload speed

(ml/min) 0.4 0.4 Breakthrough time (h:mm) >2:05 0:13 Pore volume values for > 4 0.34

breakthroughs

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 a slower dissolution rate or lower Ca ²⁺ ion release rate 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 substantially 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 (with 39 wt.% active component). The VES used 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 MgCl ₂ 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 93.3°C (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 needed). 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 MgCl ₂ . The simulator used herein to obtain the following simulation results is described in the following reference document and in the 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 #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 mD/1 mD, 100 mD/10 mD, 100 mD/20 mD, to no more than 100 mD/50 mD. For each of these permeability contrast values, different injection rates were used ranging from 79.5 l (0.5 bbl)/min, 159 l (1 bbl)/min, 794.9 l (5 bbl)/min to no more than 1590 l (10 barrels) / min. With the same volume of 1893 L (500 gal) VDA or VDA/MgCl ₂ injected into the formation, the velocity per zone and channel length results were plotted to compare the VDA/MgCl ₂ with the original VDA. The input data for the example can be found in Table. 1. 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.

Table 1. Input data Thickness, m (ft) Zone 1 15.24 (50) Zone 2 15.24 (50) Pronin -, mD 100 1-50 Porosity 15 15 Zone pressure, MPa (psi) 22.1 (3206) 22.1 (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/MgCl2 shows a deeper penetration into the channel compared to the original VDA due to the improved retardation factor. In addition, if the permeability contrast is reduced to 10 or less, and the rate is increased to 159 l (1 bbl)/min and higher, the deviation begins to affect the flow distribution between the two zones. Based on the simulation results, VDA/MgCl2 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. Outlined many-

Claims (15)

numerical details, 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. A method for treating a subterranean formation, comprising: a) mixing at the well location acid from the acid source with water from the water source and a water-soluble acid retarding agent (RA) from the RA source at a concentration sufficient to obtain a retardation factor greater than 3 to form a delayed acid treatment fluid; And b) introducing a delayed acid treatment fluid into the subterranean formation through a wellbore in fluid communication with the subterranean formation, said water-soluble, acid retardant agent being a salt containing: i) a cation selected from the group consisting of lithium, rubidium, cesium, beryllium, magnesium, calcium, strontium, barium, scandium, yttrium, titanium, zirconium, 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, alkyl ammonium, 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; wherein the first acidizing fluid is obtained by mixing acid from the acid source with water from the water source, and introducing the first acidizing fluid into the subterranean formation through the wellbore before introducing the delayed acidizing fluid to step b); wherein the pumps and associated valves are in fluid communication between the treatment fluid supply line and each of i) an acid source, ii) a water source, iii) an RA source, and iv) a viscoelastic surfactant (VES) source; wherein one or more of the first acidizing fluid, the delayed acidizing fluid, and the diverting fluid are analyzed prior to injection into the wellbore for fluid composition and properties, wherein the fluid composition is compared to a target fluid composition value and the composition of one or more of the fluid for the acid treatment, the delayed acid treatment fluid, and the diversion fluid are adjusted by adjusting the flow rates of one or more of the acid, water, RA, and VES through the pumps and respective valves based on comparison. - 16 041225 2. The method of claim 1 wherein the viscoelastic surfactant (VES) from the VES source is also mixed with acid, water and RA in step a) to form a delayed acid treatment fluid. 3. The method of claim 1 wherein the solid diverter from a source of solid diverter is also mixed with acid, water and RA in step a) to form a delayed acid treatment fluid, wherein the solid diverter is selected from the group consisting of fiber, particulate matter and their combinations. 4. The method according to claim 3, in which the solid particles contain polylactic acid. 5. The method of claim 1, wherein after the introduction of the delayed acid treatment fluid in step b), the following are followed: c) generating a diverting fluid by mixing at the well site a viscoelastic surfactant (VES) from a VES source with water from a water source, acid from an acid source, and RA from an RA source; d) introducing a diverting fluid into the subterranean formation through the wellbore. 6. The method of claim 1, wherein before introducing the delayed acid treatment fluid in step b), the following is done: c) generating a diverting fluid by mixing at the well site a viscoelastic surfactant (VES) from a VES source with water from a water source, acid from an acid source, and RA from an RA source; d) introducing a diverting fluid into the subterranean formation through the wellbore. 7. The method of claim 5, further comprising: e) repeating steps a) and b) after step d). 8. The method according to claim 7, wherein steps a) to e) are repeated at least once. 9. The method of claim 8, wherein the acidizing fluid is formed by mixing the acid from the acid source with water from the water source and introducing the acidizing fluid into the subterranean formation through the wellbore prior to the first introduction of the delayed acidizing fluid in step b. ). 10. The method of claim 5, wherein the acid, water, and RA are each separately introduced into a treatment fluid supply line in which a delayed acid treatment fluid is formed, and wherein the treatment fluid supply line is in fluid communication. wellbore environment. 11. The method of claim 10, wherein each of the VES, water, and RA is separately introduced into a treatment fluid supply line in which a diverting fluid is formed. 12. The method of claim 1, wherein the acid is 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 acid, citric acid, tartaric acid or derivatives thereof and mixtures thereof. 13. The method according to claim 2, in which the VES has a structure in accordance with formula III: Shch-S—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; 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. 14. The method of claim 13 wherein the VES is erucic amidopropyl dimethyl betaine. 15. A system for stimulating production from subterranean formations, comprising a subterranean formation having a wellbore in fluid communication with the subterranean formation; a treatment fluid supply line in fluid communication with the wellbore; an acid source in fluid communication with the treatment fluid supply line; a water source in fluid communication with the treatment fluid supply line; and a source of water-soluble acid retardant (RA source) in fluid communication with the treatment fluid supply line, mixed with acid from