MXPA06014861A - Degradable additive for viscoelastic surfactant based fluid system - Google Patents

Abstract

A method is given for treating a subterranean formation penetrated by a wellbore with a viscosified fluid. The fluid contains a solid hydrolysable polyacid that upon dissolution and hydrolysis releases an acid thatis a breaker for the viscosifying system. Suitable solid hydrolysable polyacids include polylactic acid and polyglycolic acid. The fluid also contains a pH control agent, present in an amount sufficient to neutralize any acid present in the solid hydrolysable polyacid before the injection and to neutralize any acid generated by the solid hydrolysable polyacid during the injection, so that the acid breaker is not available to break the fluid during the injection. In one embodiment the viscosifier is a viscoelastic surfactant fluid system and the solid hydrolysable polyacid is of a size selected to be a fluid loss additive, for example in fracturing or gravel packing. In another embodiment, the solid hydrolysable polyacid is used in particles sufficiently small that they ente r the pores of the formation. In either case, the viscosifier is broken after the solid releases more acid than can be neutralized by the pH control agent.

Description

DEGRADABLE ADDITIVE FOR FLUID SYSTEMS BASED ON A VISCOELASTIC SURFACTANT Background of the Invention This invention relates to the recovery of oil and gas from wells, more particularly to hydraulic fracturing and packaging with gravel and, more particularly, to the reduction of loss of fluid and damage due to flow loss additives when viscoelastic surfactant fluid systems are used as carrier fluids. There are many applications of oil fields in which filtering cakes are necessary in well drilling, in the region near the well drilling or in one or more layers of the formation. Those applications are those in which, without a filter cake, the fluid would leak out into the porous rock at an undesirable rate during a well treatment. Such treatments include perforation, penetration, termination, stimulation (for example, hydraulic fracturing or matrix solution), sand control (eg, gravel packaging, "frac" packaging, and sand consolidation), deviation, flake control. , water control, and others. When the filter cake is within the formation, it is typically called an "internal" filter cake; otherwise it is called an "external" filter cake. Typically, after such treatments have been completed, the continued presence of the filter cake is undesirable or unacceptable. Hydraulic fracturing, packing with gravel, or fracturing and packaging with gravel in an operation (called, for example, "frac" and "pack" or "frac-n-pack", or "frac-pack" treatments), are used Widely to stimulate the production of hydrocarbons, water or other fluids from the underground formations. These operations involve the pumping of a pasty mixture of "proppant" (natural or synthetic materials that push the opening of a fracture after it is created) in the hydraulic fracturing or the "gravel" in the packaging with gravel. In low permeability formations, the objective of hydraulic fracturing is to generally form long, high surface area fractures, which greatly increases the magnitude of the fluid flow path from the formation to the wellbore. In high permeability formations, the objective of a hydraulic fracturing treatment is to create a short, wide, highly conductive fracture, in order to deviate from the damage done to the well drilling in the drilling and / or completion, to ensure Good fluid communication between the rock and well drilling and, also, increase the available surface area for fluids to flow into the well drilling. Gravel is also a natural or synthetic material, which may be identical to, or different from, the proppant. Gravel packaging is used for the control of "sand". Sand is the same name given to any particulate material, such as clays, from the formation that could be carried out within the production equipment. Gravel packaging is a method of sand control used to prevent sand production from forming, in which, for example, a steel screen is placed in the well bore and the surrounding ring is packed with gravel prepared from a specific size to avoid the passage of sand from the formation that could damage the underground equipment or surface t reduce flows. The main objective of the packaging with gravel is to stabilize the formation while a minimum impediment to the productivity of the well. Sometimes the packaging with gravel is done without a screen. High permeability formations are often poorly bonded, such that sand control is necessary. Therefore, hydraulic fracturing treatments in which short and wide fractures are required are often combined in a continuous and simple operation ("frac and pack") with packaging with gravel. For simplicity, then we can refer to any of a hydraulic fracturing, fracturing and packaging with gravel in one operation (frac and pack) or packaged with gravel, and averaging them all. The solid materials, substantially insoluble, or sparingly or slowly soluble, (which can be called additives for the loss of fluid and / or components of the filter cake) are typically added to the fluids used in these treatments to form the filter cakes , although sometimes the soluble (or at least highly dispersed) components of the fluids (such as polymers or crosslinked polymers) may be part or all of the filter cakes. The removal of the filter cake is typically achieved either by mechanical means (scraping, jet blasting, or the like), by the subsequent addition of a fluid containing an agent (such as an acid, a base, an oxidant, or an enzyme) that dissolves at least a portion of the filter cake, or by manipulating the physical state of the filter cake (by inverting the emulsion, for example). These removal methods usually require a tool or the addition of another fluid (for example, to change the pH or to add a chemical). This can sometimes be accomplished in well drilling, but normally it can not be done with a propeller or gravel pack. Sometimes the operator may depend on the flow of the produced fluids (which will be in the opposite direction to the flow of fluid when the filter cake was laid) to loosen the filter cake or to dissolve at least a part of the cake filtering (for example, if this is a soluble salt). However, these methods require fluid flow and often result in slow or incomplete removal of the filter cake. Sometimes a fractionator may be incorporated in the filter cake but these must be delayed normally (eg, by esterification or encapsulation) and are often expensive and / or difficult to place and / or difficult to fire. In hydraulic fracturing, a first viscous fluid called a "pad" is typically injected into the formation to initiate and propagate the fracture and often contributes to the control of fluid loss. The selection of the fluid pad depends on the nature of the fluid subsequently injected and the formation and the desired results and attributes of the stimulation work. This is typically followed by a second fluid designed primarily to transport the propellant that keeps the fracture open after the pumping pressure is released. Occasionally, hydraulic fracturing is done with a second fluid that is not highly viscous; This selection is made primarily to save chemical costs and / or as a way to reduce the harmful effect of polymers described below. This technique, sometimes called "water-frac" ("water fracturing") that involves the use of low polymer concentrations, so low that they can not be cross-linked, through all the work. This alternative has a major disadvantage: since there is inadequate viscosity to transport too much propellant, high-speed pumps must be used and only small concentrations of propellant (pounds of aggregate propellant mass per gallon of fluid), called "PPA", can be used. , for its acronym in English. Very little propellant will be placed in the fracture to keep it open after the pump is stopped. The pads and fluids for fracture or gravel packings are usually made viscous in one of three ways. If the fluid is injected it is an oil, it is gelled with certain additives designed for the purpose, such as certain aluminum phosphate compounds; the same will not be the object of further discussion here. If the fluid is water or brine, for hydraulic or acid fracturing, it is gelled with polymers (usually polysaccharides such as guar, normally crosslinked with boron, zirconium or titanium compound), or with viscoelastic fluid systems ("VES", by its acronyms in English) that can be formed using certain surfactants that form micelles appropriately sized and shaped. The VES are popular because they leave the packaged propellers or gravel very clean, but do not form a filter cake by themselves. Polymers, especially crosslinked polymers, often tend to form a "filter cake" on the face of the fracture, as they would coat the fracture face as some fluid leaks, provided the The pores of the rock are small enough to allow entry of the polymer or crosslinked polymer. Some filter cake is generally desirable to control fluid loss. This process of forming the filter cake is also called wall construction. VES fluids without fluid loss additives do not form filter cakes as a result of leakage. The VES leakage control, in the absence of fluid loss additives, it is controlled by the viscosity, i.e., the resistance due to the flow of viscous fluid VES through the porosity of the formation limits the leakage regime. The viscosity controlled leakage regime can be high in certain formation permeabilities because the high shear thinning fluid has a low apparent viscosity of the high flow velocity areas. Decreasing the flow rate (by correspondingly reducing the pressure gradient or simply as a result of the same injected volumetric flow rate that leaks into the formation through a larger surface area as the fracture grows long and height) will allow the micelle structure to be reassembled and result in viscosity regeneration and fluid loss control. Fluid loss control may not always be optimal with VES systems, especially in the higher permeability formations. On the other hand, polymers have two main deficiencies: a) the filter cake, if left in place, can impede the subsequent flow of the hydrocarbons into the fracture and, then, into the wellbore, and b) the polymer or crosslinked polymer will be left in the same fracture, preventing or cutting the flow, either by means of physical impediment of the flow path through the packaging of propellant or by leaving the high viscosity fluid in the fracture. The VES fluids therefore leave a cleaner, more conductive and, consequently, more productive fracture. They are easier to use because they require fewer components and less surface equipment, but they can be less efficient than polymers, depending on the permeability of the formation and the specific VES system. It would be desirable to make the use of VES fluid systems more efficient. In place of the conventional fluid cake and filter loss additives, it is known to treat an underground formation by pumping a colloidal suspension of small particles in a viscoelastic surfactant fluid system: see for example the Application for US Patent No. 10 / 707.01 1, filed on November 13, 2003, and assigned to the concessionaire of this application. Colloidal suspension and viscoelastic surfactant interact to form structures that poke and block the pore grooves Colloidal suspensions are typically very small, spherical or elongated dispersions of separated particles, charged in such a way that the repulsion between the charge particles similar stabilizes the dispersion. The imbalance of the load balance, due to, for example, the removal of water, the change of pH or the addition of salt or miscible organic solvent in water, cause the colloidal particles to aggregate, resulting in the formation of a gel. These particles are generally less than 1 micron in size, and typically in the scale from 10 to about 100 nanometers. The dispersion is pre-packaged as a liquid, transparent in the case of relatively low concentrations of particles, becoming opaque or beds higher concentrations. In any case, the dispersion can be handled as a liquid, which greatly simplifies the dosage.

The use of a hydrolysable polyester material for use as a fluid loss additive for fluid loss control has previously been proposed for viscous polymer fracturing fluids. After treatment, the fluid loss control additive degrades and thus contributes very little damage. In addition, it is known that the degradation products of these materials have been shown to cause a delayed rupture of the viscous polymer fracturing fluids. The Patent E.U.A. No. 4,175,967 discloses the use of polyglycolic acid (PGA) as a fluid loss additive to temporarily reduce the permeability of a formation. SPE 1821 1 discloses the use of PGA as a fluid loss additive and gel fractionator for crosslinked guar hydroxypropyl fluids. The Patent E.U.A. No. 6,509,310 discloses the use of acid forming compounds such as PGA as delayed fractionators or fluid vehicles based on surfactant, such as those formed from the zwitterionic material lecithin. The preferred pH of these materials is about 6.5, more preferably between 7.5 and 9.5. Since VES fluid systems cause negligible damage, it would be desirable to use a fluid loss additive that is compatible with the VES system and also causes negligible damage. It would be desirable to use polyglycolic acid and similar materials as a fluid loss additive for VES fluid systems, but this creates a problem because these materials often contain small amounts of acid as commercially obtained and also these materials typically begin to hydrolyze to form acids as they are used. The acid contained or generated by the material decreases the pH of the VES fluid system; this typically decreases the viscosity, because of the viscosity of many fluid systems VES is quite sensitive to pH. Therefore, simply adding the PGA or material similar to the VES fluid system would not be an acceptable solution to the problem. The monomeric acid inherently present or the early dissolution of the PGA or similar material would adversely affect the viscosity of the system. In some chaos, viscous fluids are used in treatments in which some or all of the fluid may be allowed to invade the formation, in which case a component that is a fractionator but not a fluid loss additive is necessary. [0013] The aim of the present invention is to provide a fluid loss additive and / or a fractionator for the VES fluid systems which retards the loss of fluid towards formation, but which does not affect the viscosity during the work, but rather allow the complete cleaning of the formation or the propeller or packaging with gravel. SUMMARY OF THE INVENTION One embodiment is a method for the treatment of an underground formation penetrated by a well borehole that involves the injection into the formation of an aqueous fluid containing water, a thickener amount of a viscoelastic surfactant system, or pH control agent, and a solid material selected from an acid-containing solid and which hydrolyzes to release an acid, a solid that is hydrolysed to release an acid, and mixtures of those materials; the particles of the solid material form a filter cake on the face of the formation, and the pH control agent is present in an amount sufficient to neutralize any acid present in the solid material before injection and to neutralize any acid generated by the solid material during the injection. Optionally, the fluid is a fluid pad or a fluid carrier (containing propellant or gravel) or both. The filter cake is allowed to hydrolyze after the treatment and the fluid is allowed to flow through the face of the formation. Hydrolysis releases acid after treatment and the released acid reduces the viscosity of the viscoelastic surfactant system. Optionally, the injection is made by over the fracture pressure. In another embodiment, the solid material is selected from substituted and unsubstituted lactide, glycolide, polylactic acid, polyglycolic acid, copolymers of glycolic acid with other halides containing hydroxy-, carboxylic-, or hydroxycarboxylic acid, and mixtures thereof. materials. A preferred example is polyglycolic acid. In other embodiments, the solid material is in the form of fibers, beads, shaves, films, tapes, and platelets, for example beads having an average diameter of about 0.2 microns to about 200 microns, for example a diameter average of less than about 20 microns. The concentration of the solid material is typically from 0.6 g / L (about 5 ppt) to about 9.6 (about 80 ppt). Optionally, the fluid also contains another additive that forms a part of the filter cake.

In yet other embodiments, the pH control agent is selected from amines and alkaline earth, ammonia and the alkali metal salts of sesquicarbonates, carbonates, oxalates, hydroxides, oxides, bicarbonates, and organic carboxylates, for example sodium sesquicarbonate. , triethanolamine, or tetraethylenepentamine. Another embodiment is a method for treating an underground formation penetrated by a well borehole that involves injection into the formation of a fluid containing a viscosity agent, a solid material precursor of an acidic fractionator for the agent of selected viscosity of a solid containing an acid and which is hydrolysed to release an acid, a solid that hydrolyzes to release an acid, and mixtures of those materials. The solid is present in particles small enough that they enter the pores of the formation, and the fluid also contains a pH control agent present in an amount sufficient to neutralize any acid present in the solid material before injection and to neutralize any acid generated by the solid material during injection, such that the acidic fractionator is not available to break the fluid during injection. The injection is stopped and the solid is allowed to release acid in excess of the amount that can be neutralized by the pH control agent, so as to depart from the viscous fluid. Optionally, the viscosity agent in this embodiment is a viscoelastic surfactant system. Optionally, the solid material is of a size that forms an internal filter cake in the pores of the formation. Optionally, the solid material is of such size that it does not block the flow of fluid in the pores of the formation.

The solid material is selected from substituted and unsubstituted lactide, glycolide, polylactic acid, polyglycolic acid, copolymers of glycolic acid with other halides containing hydroxy-, carboxylic- or hydroxycarboxylic acid, and mixtures of those materials. A preferred example is polyglycolic acid. The pH control agent is selected from amines and alkaline earth, ammonia and the alkali metal salts of sesquicarbonate, carbonates, oxalates, hydroxides, oxides, bicarbonates, and organic carboxylates, for example sodium sesquicarbonate, triethanolamine, or tetraethylenepentamine. Yet another embodiment is a method for treating a well bore involving the injection of an aqueous fluid containing water, a thickening amount of a viscoelastic surfactant system, or pH control agent, and a solid material selected from a solid that contains an acid and that hydrolyzes to release an acid, a solid that hydrolyzes to release an acid, and mixtures of those materials; the particles of the solid material form a filter cake on the face of the formation, and the pH control agent is present in an amount sufficient to neutralize any acid present in the solid material before injection and to neutralize any acid generated by the solid material during the injection. The solid material is of such a size that it does not enter the pores of the formation. The solid material is selected from substituted and unsubstituted lactide, glycolide, polylactic acid, polyglycolic acid, copolymers of glycolic acid with other halides containing hydroxy-, carboxylic- or hydroxycarboxylic acid, and mixtures of those materials. A preferred example is polyglycolic acid. The pH control agent is selected from amines and alkaline earth, ammonia and the alkali metal salts of sesquicarbonates, carbonates, oxalates, hydroxides, oxides, bicarbonates, and organic carboxylates. Brief Description of the Drawings Figure 1 shows the effect of a solid acid and its decomposition product as a function of pH on viscosity as a function of the cutting rate. Figure 2 shows the effect of a solid acid, with and without pH control agent, on the viscosity as a function of temperature. Detailed Description of the Invention In the treatments of underground formations, in particular in hydraulic fracturing and gravel packing treatments, the total volume of fluids that need to be pumped to complete the treatment is strongly influenced by the amount of fluid lost to the surrounding matrix. In conventional fluids having crosslinked polymers or polymers as the viscosity agents, during the initial phase of the treatment, the crosslinked polymers or polymers are filtered on the face of the rock to form a polymeric filter cake which subsequently inhibits other losses. However, fluids based on VES are free of polymers - which in itself is a major advantage since polymers, which remain in the matrix (or propeller packaging or gravel packaging) once the treatment is finished , are a major source of damage - and, consequently, the process of fluid loss is not governed by the formation of the viscous filter cake. To overcome the tendency of high fluid loss in fluids of polymeric base or VES (in particular in hydraulic fracturing fluids, gravel carrier fluids, and fluid loss control pills), various fluid loss additives have been proposed. Silica, mica, and calcite, alone, or in combination with starch, are known to reduce fluid loss in polymer-based fracturing fluids, by forming a filter cake, on the face of the formation, which is relatively impervious to water, as described in the US Patent No. 5,948,733. The use of these fluid loss additives alone in a VES-based fluid, however, has been observed to only provide modest decreases in fluid loss, such as is described in US Pat. No. 5,929,002. The poor performance of these conventional fluid loss additives is typically attributed to the high leakage period (shoot) before the filter cake is formed and to the formation of a VES-based fluid-permeable filter cake. Here we define the high permeability formations as having permeabilities of more than about 2 mD, especially more than about 10 mD, and more especially more than about 20 mD. Although there is no universal agreement on the precise relationship of particle size, pore size, and pontoon, we will use the following guidelines here. Particles having diameters greater than about one third (although some researchers say up to a half) of the throat diameter of a pore is expected to bridge at or near the face of the formation. Particles smaller than, but larger than about one seventh of a pore throat diameter are expected to enter the formation and be trapped and form an internal filter cake. Smaller particles of about one-seventh of a pore throat diameter are expected to pass through the formation without substantially affecting the flow. It should be clear that there are other important factors such as the particle size and pore distributions, flow regime, particle concentration and particle shape. We have discovered that dimers, oligomer, or solid polymers of simple acids, or the copolymers of these materials with each other, examples of which are PGA (polyglycolic acid) and PLA (polylactic acid), can be used, in appropriately sized sizes, as a fluid loss additive that produces a fractionator for a fluid system based on viscoelastic surfactant. as long as it is used in combination with a suitable pH control agent that allows VES fluid systems to maintain their viscosity if some of the solid acid is hydrolyzed. A fluid system of viscoelastic surfactant is a viscous fluid with a viscoelastic surfactant and any additional materials (such as, but not limited to, salts, co-surfactants, rheology enhancers, stabilizers, and cutting recovery enhancers) that improve or modify the performance of the viscoelastic surfactant. When control of fluid loss is not necessary, these solids combined with the pH control agents can still be used as delayed fractionators, preferably in small particle sizes, which fractionate the fluid, even within a matrix formation. . These combinations of dimers, oligomers, or polymers of solid acids, in combination with A n, in viscoelastic surfactant systems will be called here fluid system "controlled by solid acid - viscoelastic surfactant", or fluid systems "CSA-VES, for its acronym in English." The pH control agent avoids the harmful effects of the small amount of free acid that is typically found in the solid acids as received, and also neutralizes any acid that can be generated by hydrolysis of the solid acid during a treatment, before fractionation is desired. At present pH, the fluid does not become acidic enough to destroy the viscosity of the system until the pH control agent has been emptied, then the additional acid, still in formation as the solid acid continues to hydrolyze and dissolve, fractionating the system On the other hand, the pH control agent imparts a pH to the fluid that accelerates the hydrolysis of the solid acid, which can It is necessary to take into account when designing a treatment if the hydrolysis regime is important. VES micelles are usually fractionated by the natural inward flow of hydrocarbons and water or brine, but fractionators such as certain salts or alcohols are sometimes used. It is known that acids damage or destroy either the micelle / vesicle structures formed by the viscoelastic surfactants or, in some chaos, the same surfactants. Acid fractionators such as activators, delaying agents or stabilizers can also be used specifically in conjunction with the fractionators. Suitable solid acids for use in CSA-VES fluid systems include a substituted and unsubstituted lactide, glycolide, polylactic acid, polyglycolic acid, a copolymer of glycolic acid with other halves containing hydroxy-, carboxylic-, or hydroxycarboxylic acid, a copolymer of lactic acid with other halides containing hydroxy-, carboxylic-, or hydroxycarboxylic acid, and mixtures of the foregoing. Other materials suitable for use in the CSA-VES fluid systems are all those polymers of hydroxyacetic acid (glycolic acid) with itself or other halides containing hydroxy-, carboxylic-, or hydroxycarboxylic acids described in U.S. Pat. Nos. 4,848,467; 4,957,165; and 4,986,355, all three incorporated herein by reference. Solid acids are also described in the Publication of Patent Application E.U.A. Nos. 2003/002195 and 2004/0152601, both incorporated herein by reference and assigned to the concessionaire of this application. Excellent solid acid components of the CSA-VES are the solid cyclic dimers, or solid poles, of certain organic acids, which are hydrolyzed under known and controllable conditions of temperature, time and pH to form organic acids. An example of a suitable solid acid is the solid cyclic dimer of lactic acid (known as "lactide"), which has a melting point of 95 to 125 ° C (depending on the optical activity). Another is a lactic acid polymer, (sometimes called a polylactic acid (or "PLA," for its acronym in English), or a polylactate, or a polylactide. Another example is the solid cyclic dimer of glycolic acid (known as "glycolide"), which has a melting point of about 86 ° C. Yet another example is a glycolic acid polymer (hydroxyacetic acid), also known as polyglycolic acid ("PGA"), or polyglycolide. Another example is a copolymer of lactic acid and glycolic acid. These polymers and copolymers they are polyesters. The materials as received may contain some free acid and some solvent, typically water. Cargill Dow, Minnetonka, MN, E.U.A., produces the dimer of solid cyclic lactic acid called "lactide" and from it produces polymers of lactic acid, or polylactates, with varying molecular weights and degrees of crystallinity, under the generic name of factory NATUREWO RKS ™ PLA. The PLAs currently available from Cargill Dow have molecular weights of up to about 100,000, although any polylactide (made by any process by any manufacturer) and any material of molecular weight of any degree and crystallinity can be used in the embodiments of the invention. Invention. PLA polymers are solid at room temperature and are hydrolyzed by water to form lactic acid. Those available from Cargill Dow typically have crystalline melting temperatures of from about 120 to about 170 ° C, but others can be obtained. Poly (d, l-lactide) is available from Bio-Invigor, Beijing and Taiwan, with molecular weights up to 500,000. Bio-Invigor also supplies polyglycolic acid, often called "polyglactin" or poly (lactide-co-glycolide). The regimes of the hydrolysis reactions of all these materials are governed, among other factors, by the molecular weight, the crystallinity (the proportion of crystalline material to the amorphous one), the physical form (size and shape of the solid), and, in the polylactide case) the amounts of the two optical isomers. (The 1-lactide of natural origin forms partially crystalline polymers; dl-lactide forms amorphous polymers.) Amorphous regions are more susceptible to hydrolysis than crystalline regions. The low molecular weight, the less crystallinity and greater proportion of surface to mass result in a more rapid hydrolysis. The hydrolysis is accelerated by the increase in temperature, by the addition of acid or base, or by the addition of a material that reacts with the product (s) of the hydrolysis. Homopolymers may be more crystalline; the copolymers tend to be amorphous unless they are block copolymers. The degree of crystallinity can be controlled by the manufacturing method for homopolymers and by the manufacturing method and the proportion and distribution of lactide and glycolide for the copolymers. The polyglycolide can be made in a porous form. Some of the polymers dissolve very slowly in water before they hydrolyze; it should be understood that the terms hydrolyze or hydrolysis, etc., are intended to include the solution. The solid acids can be coated to retard hydrolysis. Suitable coatings include polycaprolate (a copolymer of glycolide and epsilon-caprolactone), and calcium stearate, which are both hydrophobic. The polycaprolate by itself hydrolyzes slowly. The generation of a hydrophobic layer on the surface of the solid acids by any means delays the hydrolysis. Note that the coating here can refer to the encapsulation or simply to the change of the surface by means of the chemical reaction or by means of the formation or the addition of a thin film of another material. Another suitable method for delaying the hydrolysis of the solid acid, and the release of acid, is to suspend the solid acid, optionally with a hydrophobic coating, in an oil or in an oil phase of an emulsion. Hydrolysis and acid release do not occur until the water contacts the solid acid. The CSA-VES self-destroys in situ, that is, in the place that is placed. The site may be part of a suspension in a treatment fluid in well drilling, in drilling, in gravel packaging, or in a fracture; or as a component of a filter cake on the walls of a well bore or in a fracture; or in the pores of the same formation. The CSA-VES can be used in formations of any lithology, but can be used more commonly in carbonates or sandstone. A particular advantage of these materials is that the solid acids and acids generated are non-toxic and biodegradable. Solid acids are often used as self-dissolving sutures. [0035] It has been found that the solid acid / pH control agent combination of this invention is particularly useful when used with various types of zwitterionic surfactants. In general, suitable zwitterionic surfactants have the formula: RCONH- (CH2) a (CH2CH20) m (CH2) b-N + (CH3) 2- (CH2) a. (CH2CH20) m '(CH2) b € 00' in where R is an alkyl group containing from about 17 to about 123 carbon atoms which may be branched or straight chain and which may be saturated or unsaturated; a, b, a 'are each from 0 to 10 and m and m' are each from 0 to 13; a and b are each 1 or 2 if m is not 0 and (a + b) is from 2 to approximately 10 if m is 0; a 'and b' are each 1 or 2 when m is not 0 and (a '+ b') is from 1 to 5 if m is 0; (m + m ') is from 0 to about 14; and CH2CH20 can be oriented as OCH2CH2. The preferred surfactants are the betaines.

[0036] Two examples of commercially available betaine concentrates are, respectively, BET-O-30 and BET-E-40. The VES surfactant in BET-O-30 is oleylamidopropyl betaine. It is designated as BET-O-30 because as obtained from the supplier (Rhodia, Inc., Cranbury, New Jersey, USA) it is called Mirataina BET-O-30; it contains an oleyl amino acid group (including an alkene group C17H33) and is provided as about 305 active surfactant; the remainder is substantially water, sodium chloride, glycerol and propane, 2-diol. A suitable analogous material, BET-E-40, was used in the experiments described above; A chemical name is eruciloamidopropyl betaine. BET surfactants, and others that are suitable, are described in US Patent E.U.A. No. 6,258,859. Certain co-surfactants may be useful in the extension of brine tolerance, to increase gel strength, and to reduce the cutting sensitivity of VES fluids, in particular for BET-O- type surfactants. An example given in US Patent E.U.A. No. 6,258,859 is sodium dodecylbenzene sulfonate (SDBS). The VESs can be used with or without this type of co-surfactant, for example those having a structure type SDBS with a chain of Ce up to Ci6; saturated or unsaturated, branched or straight. Other examples of this type of co-surfactant are those that have a chain of Cs up to Ci 6; saturated or unsaturated, branched or straight. Other suitable examples of this type of co-surfactant, especially for BET-O-30, are certain chelating agents such as trisodium triacetate hydroxyethylene diamine. The combination of a pH control agent and a solid acid suitable is a method to maintain the stability of a VES system, and then fractionation can be used with any VES system that is more stable at a pH higher than the pH that results from the hydrolysis of the solid acid, provided the fluid system CSA-VES is compatible with the formation, the fluids of the formation, and any other fluids that may come in contact with, for example, a fluid pad, and its components and additives. Examples of VES systems include those described in US Patents. Nos. 5,551,516; 5,964,295; 5,949,555; 5,979,557; 6,140,277; 6,258,859 and 6,509,301, all incorporated herein by reference. Some VES systems, for example some cationic systems, are not very sensitive to pH, and some VES systems, for example some ammonium systems, are typically compensated at a pH greater than 12 in normal use, and the combination of solid acid / agent pH control of this invention will not always be beneficial with such systems. Although the Invention has been described in its entirety using the term "VES", or "viscoelastic surfactant" to describe the non-polymeric aqueous fluid in the second stage, any non-polymeric material may be used to make the aqueous fluid more viscous as long as the requirements described herein for such fluid are met, for example the viscosity, stability, compatibility, and lack of damage to the wellbore, face or fracture of the formation. Examples, regardless of whether they form, or are described as forming, vesicles or viscoelastic fluids, include, but are not limited to, those viscosity builders described in US Patents. Nos. 6,035,936 and 6,509,301.

The pH control agents include, but are not limited to, sodium, sesquicarbonates of potassium and ammonia, oxalates, carbonates, hydroxides, bicarbonates, and organic carboxylates such as acetates and polyacetates. Examples are sodium sesquicarbonate, sodium carbonate, and sodium hydroxide. Soluble oxides, including slowly soluble oxides such as MgO, can also be used. Amines and oligomeric amines, such as alkyl amines, hydroxyalkyl amines, anilines, pyridines, quinolines, and pyrrolidines, for example triethanolamine and tetraethylenepentamine, may also be used. The selection of the pH control agent depends in part on the VES system used. For example, MgO precipitates anionic VESs but is suitable for cationic and zwitterionic VESs. Some inorganic-based salt-type pH control agents, such as carbonates, can detrimentally affect the rheology of some VESs that are sensitive to electrolyte concentration, so in these cases organic-based pH control agents such how the amines would be the best selection. The pH control agents can be added as solids or as solutions, typically concentrated for ease of transport. The order of addition of the solid acid, the pH control agent, VES, and other components (such as salts) is not critical. The concentration of the appropriate pH control agent depends on the concentration of the solid acid, the treatment temperature and, mainly, the desired delay before the end of the fractionation. One factor that must be taken into account is that the excessive amounts of some control agents H can promote the hydrolysis of solid acid. CSA-VES fluid systems are most commonly used in treatments in which a filter cake is desired during treatment, but are harmful after treatment, especially in hydraulic fracturing and gravel packaging. The CSA-VES fluid systems can also be used where the fractionation of the viscous fluids is simply desirable, whether or not a filter cake is formed; in some cases the fluid can invade the formation. Such viscous fluids can be, for example non-limiting, hydraulic fracturing fluids and packaging with gravel in the packings or in the formations, drilling fluids, well drilling cleaning fluids, fluid loss control fluids, extermination fluids, spacers, flood, thrust, and carriers for materials such as scale inhibitors, paraffin, and asphaltenes. A pad fluid and fracturing fluid are made viscous because an increased viscosity results in the formation of a wider fracture, thus a larger flow path, and a minimum viscosity is required for the transport of adequate amounts of propellant.; The actual viscosity required depends mainly on the flow regime of the fluid and the density of the propellant. In a typical fracturing process, such as hydraulic fracturing with aqueous fluids, the fracture is initiated by first pumping a high viscosity aqueous fluid with good to moderate leakage properties and, typically, without propellant, into the formation . This pad is usually followed by a carrier fluid of similar viscosity transporting an initially low concentration and, then, a concentration of increasing propellant increase within the extended fractures. The pad initiates and propagates the fracture but does not need to transport propellant. All fluids tend to "leak" into the formation from the fracture in creation. Commonly, by the end of the job, the entire volume of the pad will have leaked into the formation. This leakage is determined and controlled by the properties of the fluid (and the additives it may contain) and the properties of the rock. A certain amount of leak greater than the minimum possible may be desirable, for example a) if the intention is to put some fluid to change the properties of the rock or to flow back into the fracture during closure, or b) if the intention is to deliberately cause what is called an "off-screen", or ("TSO", for its acronym in English), a condition in which the propeller forms a bridge at the end of the fracture, stopping the lengthening of the fracture and resulting in an undesirable increase in the width of the same. On the other hand, excessive leakage is undesirable because it can waste valuable fluid and result in a reduction in work efficiency. Proper control of the leak is therefore critical to the success of the job. In embodiments of hydraulic fracturing, frac packing, and gravel packaging, the CSA with pH control agent can be added to the pad, through the entire treatment or only part of the propellant or gravel stages. The solid acid can be a fiber in any of these applications and will retard the backflow of the propellant or gravel, and / or the fines are present, until the solid acid is hydrolyzed and the mezcal dissolves. An auto fluid loss additive Destructive and filtering cake are particularly useful in hydraulic fracturing, frac packing, and gravel packaging because mechanical removal methods are impossible and methods involving the contact of the fluid loss additive and the filter cake With an additional fluid they are not practical. For example, calcite is known as an excellent fluid loss additive, but it is not soluble in water, even at 150 ° C. Calcite has been used for years in drilling fluids to form filter cakes that are subsequently removed with acid. At higher abundance, solid acids such as polyglycolic acid soften and deform at high temperatures, while the particles of many other materials conventionally used as fluid loss additives are hard. The deformation of the solid acids makes it even a better additive for loss of fluid and filter cake. The use of CSA-VES fluid systems is particularly suitable in high permeability formations. For example, in addition to packaging with gravel, hydraulic fracturing followed by packaging with gravel in a simple operation, sometimes called a frac-pac (or frac-pack, etc.), fracpac, frac pac, frac and pac, StimPac, sometimes with a deliberate off-screen spike generates a short-width fracture (in which the propeller forms a bridge at the end of the fracture away from the wellbore, stopping the elongation of the fracture and resulting in a fracture). subsequent increase in the width of the fracture), is usually effected in the formations of a relatively high permeability for the purposes of sand control. However, such operations are sometimes carried out by other reasons, for example to divert the damage to the permeability caused by the flaking or to improve the poor communication between the well drilling and the formation or a previous fracture, or in the formations in which the drilling generates harmful fines, or by other reasons. Those work designed to generate wide fractures can also be performed if the subsequent packed with gravel when such control is not programmed. The methods of the present invention can be used in any of these cases (packaged with gravel, fracturing followed by packaging with gravel, and fracturing for short width fractures). The acid generation regime from a particular solid acid, having a particular chemical and physical make-up, including a coating, is present, at a particular temperature and in contact with a fluid or fluids of a particular composition (for example the pH and the concentration and nature of the other components, especially the electrolytes), is determined quickly by means of a simple experiment: exposing the solid acid to the fluid or fluids to the treatment conditions and monitoring the release of acid. Solid acids can be manufactured and used in various solid forms, including, but not limited to fibers, beads, films, shaves, tapes and platelets; the most commonly used form is that of accounts. If the CSA is in fiber form, then more commonly, straight fibers are used; although curved, wrinkled, spiral-shaped and other fibers of three-dimensional geometric shapes are useful. Also, the fibers can be grouped together, or hooked at one or both ends. Yes the CSA is used in In the form of fibers, then typically the length of the fiber is at least about 2 millimeters, and the diameter of the fiber varies from about 3 to about 200 microns. It seems that there are no upper limits on the length of the fibers used from the point of view of utility. The handling, mixing and pumping equipment dictates the practical upper limit for the length of the fibers. If the CSA is used in the form of films, shaves, tapes or platelets, then typically the longer dimension will be comparable to the dimensions given below for the diameters of the beads. If the CSA is to be used as a fluid loss additive, the particle size of the solid acid is selected based primarily on the desired fluid loss properties (e.g., shoot coefficient and wall formation). Typical sizes for the beads vary from the sub-micron, for example about 0.2 microns, to about 20 microns, for example from about 10 to about 50 microns, but the actual size depends especially on the properties of the formation and other factors known to those experts in the field. (Sub-micron particles can be made, for example, by the method described in U.S. Patent No. 7,713,807). If the CSA is to be used as a fractionator, the particles can be on a broader scale, for example from nanoparticles (for the fractionation of a VES within a matrix) to the size of propellants for the fractionation of the carrier fluid. The selection of the solid acid (and properties such as molecular weight and crystallinity) are selected based primarily on the desired hydrolysis and dissolution regimes in the carrier to be used at the temperature that it will be used. These selections may also be influenced by the desired time before the delayed fractionation, which could depend on the size of the work, whether the work is hydraulic fracturing or packaging with gravel, or other factors known to experts in the field. Similarly, the concentration of the pH control agent is based on many factors that will be clear to those skilled in the art, including the concentrations and nature of the VES, the solid acid, the pH control agent and any other additives, the temperature, and the desired time for fracturing. The appropriate concentration of the pH control agent can be determined by means of simple laboratory experiments, for example mixing all the components, heating to the working temperature, and monitoring the viscosity. The system consisting of a solid acid and a pH control agent also works with VES systems that contain co-surfactants or other additives included in the fracturing or gravel packaging fluids. We repeat, a requirement is the compatibility with the VES system. The carrier fluid (VES system plus solid acid plus pH control agent plus other additives) can be mixed in batches or mixed on the fly. When a function of the CSA-VES fluid system is to control the leak, the optimal considerations of the solid hydrolyzable acid polymer in a CSA-VES fluid system can be determined by means of the selection of the desired leak parameters and measuring the latter with samples of the fluids tried and of the formation or of a rock similar to the formation. The leak is defined by three terms: "sprout", which is the rapid initial leakage of fluid before a filter cake is formed on the face of the fracture and is measured in gallons / 100 square feet, and, for the subsequent leakage that occurs even after the filter cake is formed and is governed by the viscosity and tendency to wall formation: Cw, the coefficient of fluid loss, and Cv, the coefficient of fluid loss controlled by viscosity. Cw is not applicable when no material is present for wall formation, Cw finite. Cw and Cv are measured in feet / min1 / 2. The preferred values for the shoot, Cw and Cv, respectively, are 0 to about 5, about 0.0001 to about 0.05, and about 0.001 to about 0.05.; more preferred values are 0 to about 2, about 0.001 to about 0.008, and about 0.001 to about 0.008; more preferred values are 0 to about 1, about 0.001 to about 0.003, and about 0.001 to about 0.003. The values of these parameters (the actual behavior they represent) can vary significantly as long as a suitable filter cake is produced at an appropriate time. A test method for the determination of these values is given by Navarrete, R. C, Raweizel, KE, and Constien, VG: "Dynamic Fluid Loss in Hydraulic Fracturing Under Realistic Cutting Conditions in Rocks of High Permeability," Production and SPE Installations, pp. 138-143 (August, 1996). The selection of a solid acid (its chemistry), its size and shape, and its concentration, among other factors, depend on the way that the same will be used, and these parameters could change during a treatment. All these parameters can be affected by the nature of the work (for example, it is necessary or not a fluid loss control), the temperature, the nature of the formation, and the desired time before a fractioning and / or time occurs. desired by which a fractionation has occurred. (For example, fluid loss control may not be necessary when packaging with gravel is done in a low permeability formation, and selections can be made on the basis of fractionation properties.) The appropriate selections can be made with the help of simple experiments such as those described above, or in the examples that follow, optionally with the help of simulation software. A typical formulation of a CSA-VES suitable for hydraulic fracturing over a wide range of temperature and permeability conditions of the formation contains approximately 4.2 g / L (approximately 35 ppt) of sodium sesquicarbonate, and approximately 4.8 g / L (approximately 40 ppt) of polyglycolic acid (NATUREWORKS ™ PGA). PGA is typically manufactured to have particles that are approximately 90% smaller than 20 microns; it commonly contains up to 5% free acid as commercially obtained. The concentration of this PGA can range from about 0.6 g / L (about 5 ppt) to about 9.6 g / L (about 80 ppt), preferably from about 2.4 g / L (about 20 ppt) to about 4.9 g / L (approximately 40 ppt), but the If the concentration is too low for the treatment that is being carried out, then the fluid loss may be too great, and if the concentration is above about 4.8 g / 1 (approximately 40 ppt), then it is achieved in most cases. The formations have very little or no fluid loss. This composition has a pH of about 9.5; at a lower pH, the hydrolysis rate of this PGA is lower, down to about a pH of about 5 and, then, at a still lower pH but not as fast as at a pH of 9.5 even at a pH 2. At pHs greater than 9.5 the hydrolysis is faster. At a pH of about 9.5, this PGA will hydrolyze in about 2 to 3 days at 66 ° C (approximately 150 ° F), in about 12 hours at 93 ° C (approximately 200 ° F), and in about ½ hour at 121 ° C (approximately 250 ° F). The proper balance of fluid loss control and pH control are extre important. A fluid system of preferred viscoelastic surfactant, for example for fracturing and packaging with gravel, contains about 1 to 10 (for example about 5 to 6) percent volumes of BET-O-40 (see above) (which may contain about of sodium sulfonate polinaphthalene). For fluid loss control pills, the concentration of VES can be much higher, for example up to 50%, to prevent well drilling fluids from invading the reservoir. However, any viscoelastic surfactant system that is chemically compatible with the other components of the fluid, with other fluids with which it may come into contact and with formation, may be used, and may be used at any concentration to which it provides a rheology. suitable for the intended use. When solid acids are used in the fluids for treatments such as drilling, internal drilling, termination, stimulation (eg, hydraulic fracturing or matrix solution), sand control (eg, gravel packaging, frac packing, and consolidation), deviation, and others, the solid acid is initially inert to the other components of the fluids, so that the other fluids can be prepared and used in the usual manner. Normally, such fluids would contain a fluid loss additive and a filter cake former, so that the solid acid replaces some or all of the fluid loss additive and filter cake former that would otherwise have been used. In many cases, if the fluid contains a component that could affect or be affected by the solid acid (such as a compensator, another acid-reactive material, or a viscosity former that forms or is incorporated in the filter cakes), either which is the amount or nature of the solid acid or the amount or nature of the interference or interfered with the component can be adjusted to compensate for the interaction. This can be determined quickly by means of simple laboratory experiments. Any additives normally used in such treatments may be included, provided that, we repeat, they are compatible with the other components and the desired results of the treatment. Such additives may include, but are not limited to, antioxidants, crosslinkers, corrosion inhibitors, retarding agents, biocides, compensators, fluid loss additives, etc. The wellbores treated can be vertical, deviated or horizontal. The same can be finished with sheath and perforations or open hole. [0054] In the packaging with gravel, or fracturing and packaging with combined gravel, it is within the scope of the invention to apply the fluids and methods to the treatments that are made with or without a screen. Although we have described the invention in terms of the production of hydrocarbons, it is within the scope of the invention to use the fluids and methods in wells intended for the production of other fluids such as carbon dioxide, water or brine, or in the wells of injection. Although we have described the invention in terms of defoaming fluids, foamed or energized fluids (for example with nitrogen or carbon dioxide or mixtures of those gases) can be used. Adjustments would be made at the appropriate concentrations due to any changes in the properties of the fluid or in the concentration of the propellent consequent to foaming. Any propellant (gravel) can be used, as long as it is compatible with the degradation of the filter cake and the bridge-promoting materials if they are used, the formation, the fluid, and the desired results of the treatment. Such propellants (gravels) may be natural or synthetic (including without limitation glass beads, ceramic beads, sand, and bauxite), coated or containing chemicals; more than one can be used sequentially or in mixtures of different dimensions or different materials. The propellant may be coated with resin, provided that the same and the other chemicals in the coating are compatible with the other chemicals of the invention, particularly the components of the micelles of the viscoelastic surfactant fluid. The propellants and gravels in the same or in different wells or treatments they can be of the same material and / or of the same size with each other and the term "propulsor" is intended to include the gravel in this discussion. In general, the propellant used will have an average particle size sized materials of from about 0.15 mm to about 2.39 mm (about 8 to about 100 US mesh), more particularly, without being limited to, 0.25 to 0.00. , 43 mm (approximately 40/60 mesh), 0.43 to 0.84 mm (20/40 mesh), 0.84 to 1.19 mm (16/20 mesh), 0.84 to 1.68 mm ( 12/20 mesh) and 0.84 to 2.39 mm (8/20 mesh). Typically, the propellant will be present in the slurry in a concentration of from about 0.12 to about 3 kg / L, preferably from about 0.12 to about 1.44 kg / L (about 1 PPA to about 25 PPA, preferably from 1 to approximately 12 PPP). (PPA is "added propellant pounds" per gallon of liquid.) Also optionally, the fracturing fluid may contain materials designed to limit the return flow of the propellant after the fracturing operation is completed by forming a porous packager in the fracture zone. Such materials may be any of those known in the art, such as those available from Schlumberger under the trademark PropNET ™ (for example, see U.S. Patent No. 5,501,275.) Propellant retroflow inhibitors include the fibers or platelets of novoloid or novoloid type polymers (U.S. Patent No. 5,782,300).

EXAMPLES Example 1: Figure 1 shows the viscosity measurements of an example of a VES fluid system with different amounts of glycolic acid (GA) dissolved in the fluid. The measurements were conducted at 66 ° C (150 ° F). The pH control agent used in the experiments shown in Figure 1 was sodium sesquicarbonate, which was used at a concentration of 30 pounds per thousand gallons (3.6 g / L) in all experiments. The VES fluid system was made with 6% of a material called BET-E-40 obtained from Rhodia, Inc., Cranbury, New Jersey, E.U.A.; it contains a betaine VES surfactant which has an erucic acid amide group (including an alkene group of tail C21H41) and is approximately 40% of the active ingredient, the balance being substantially water, sodium chloride, and isopropanol. (Prior to use, approximately 1% of DAXAD 17, a low molecular weight sodium sulfonate polynaphthalene available from the Hampshire Chemical Corporation, Nashua, NH, USA, was added to betaine VES surfactant BET-E-40 as received. .) This experiment showed the results that would be seen as the PGA dissolves, and demonstrates the adverse effect on the viscosity of the fluid as the PGA hydrolyzes to form glycolic acid. In addition, the data in the figure also demonstrates that the desired viscosity can be maintained by the addition of a pH control agent to maintain the pH of the fluid at about 9.5. It can be seen that the viscosity of the surfactant system without pH or PGA control agent (top line, diamonds) was reduced by the addition of 0.5% PGA (42 pounds per thousand gallons, or 0.5 g / L) , and the pH already It had dropped to 4 when it was measured. The PGA used was DuPont TLF 6267, which may contain up to about 5% glycolic acid when it is received, and about 90% of which has a particle size of less than about 20 microns. This material is a crystalline PGA with a molecular weight of approximately 600. To simulate the hydrolysis and dissolution of the PGA, increasing amounts were added to portions of the baseline system; this resulted in further successive decreases in viscosity. The viscosity of the baseline material was not affected by the addition of sodium sesquicarbonate to control the system at a pH of about 9.5.

Example 2: Figure 2 shows the viscosity of the same 6% of the surfactant fluid system as the baseline of the system of the experiments shown in Figure 1, determined with a Fann 50 Viscometer over a range of temperatures, with the PGA added, with or without the pH control agent of pH 9.5. Without the pH control agent in place, the viscosity of the fluid was substantially reduced; therefore, the material would have been unsatisfactory as a viscous oil field treatment fluid, for example as a carrier fluid for a fracturing or gravel packaging system. With the pH control agent present, the viscosity of the fluid system containing the PGA was essentially identical to the viscosity of the baseline system. The total duration of each of these experiments was approximately 3 hours. At the end of the run with the pH control agent it can be seen that the viscosity fell below the baseline, suggesting that hydrolysis of the PGA at the highest temperature was beginning to fractionate the fluid when the temperature was above 121 ° C (250 ° F). (The pH control agent was being exceeded at this point.) The time this system was at approximately 121 ° C (250 ° F) of approximately 160 minutes. Therefore, this fluid system, containing PGA, is suitable for use in hydraulic fracturing and packaging with gravel. [0060] Field tests have demonstrated the effectiveness of the CSA-VES fluid systems.

Example 3: Before the fracturing of the lower zone of a well in the Gulf of Mexico, starting from a mini-fall measurement (a simple test in which a viscous fluid is injected, a fracture is created, and the fall of pressure is observed) it was estimated that the permeability of the area of lose sandstone, which was of a height of 16 feet, was 2.45 mD. The temperature of the formation was 195 ° F (91 ° C) and the injected volume was 2329 gallons E.U.A. (8.82 m3). The rate of measurement of the drop without a solid acid and a pH control agent in a VES gave a measured fluid loss coefficient, Ct, of 0.072 ft / min1 / 2. Then, when they were placed a solid acid and a pH control agent (4768 US gallons (18.05 m3) of a pasty mixture containing 5 volume percent of BET-E-40 (containing approximately 1% sodium sulfonate polynaphthalene) ), 4.8 g / L (40 ppt) of PGA beads, approximately 90% smaller than 20 microns, 4 percent by weight of KC1, and 4.2 g / L (35 ppt) of sodium sesquicarbonate) and a DataFRAC was performed, the measured Ct was halved to 0.035 feet / min1 / 2. (A FRAC Data is a multiple step test, more involved, in which a variety of parameters are measured and / or evaluated and which includes a closing test (or closing pressure) and a calibration test (including analysis of decrease in injection, shot and pressure.) The closing pressure was approximately 46.2 MPa (6700 psi).

Example 4. Similarly, for the upper sandstone zone of 20 feet height of the same well, the permeability was estimated at 1.5 mD from the mini-fall measurement and a rate of fall step gave a coefficient of loss of measured fluid, Ct, of 0.047 feet / min1 / 2. The temperature was 190 ° F (88 ° C) and the injected volume was 436 gallons E.U.A. (1, 65 m3). Then, when a solid acid and a pH control agent (8.93 m3 (2359 gallons) of the same fluid used in Example 3) were placed and a DataFRAC was performed, the measured Ct was reduced to 0.019 ft / min1 / 2. In each case, the fluid efficiency was greatly improved.

Claims (10)

1. A method for treating an underground formation penetrated by a well bore consisting of a step of injecting into the formation of an aqueous fluid consisting of water, a viscosity agent, a pH control agent, and a material solid selected from the group consisting of a solid containing an acid and hydrolyzed to release an acid, and mixtures thereof, wherein the pH control agent is present in an amount sufficient to neutralize any acid present in the solid material before injection and to neutralize any acid generated by the solid material during the injection.

2. The method of Claim 1 wherein the particles of the solid material form a filter cake on the face of the formation. The method of Claim 2 wherein the fluid is a fluid pad and / or a carrier fluid containing the propellant or gravel. 4. The method of Claim 2 or 3 wherein the injection step is effected over the fracture pressure of the formation. The method of Claim 1 wherein the particles of the solid material are small enough to enter the pores of the formation. 6. The method of Claim 5 wherein the particles of the solid material are sufficiently small that they do not block the flow of fluid in the pores of the formation. 7. The method according to any of the Claims precedents wherein the viscosity agent is a viscoelastic surfactant. 8. The method according to any of the preceding claims wherein further the solid material is allowed to hydrolyze after the treatment and the acid released reduces the viscosity. The method according to any of the preceding claims wherein the solid material is selected from the group of a substituted and unsubstituted lactide, glycolide, polylactic acid, polyglycolic acid, copolymers of glycolic acid with other halides containing hydroxy acid, acid carboxylic-, or hydroxycarboxylic, and mixtures thereof. The method according to any one of the preceding Claims wherein the solid material is in the form of beads having an average size of from about 0.2 microns to about 200 microns. The method according to any one of the preceding claims wherein the concentration of the solid material is from about 0.6 g / L (about 5 ppt) to about 9.6 (about 80 ppt). The method according to any of the preceding Claims wherein in addition the pH control agent is selected from the group consisting of amines and alkaline earth, ammonia and the alkali metal salts of sesquicarbonates, carbonates, oxalates, hydroxides, oxides , bicarbonates, and organic carboxylates.