MX2008007057A - Well treatment with dissolvable polymer - Google Patents

Abstract

Well treatment is disclosed that includes injecting a well treatment fluid with insoluble polyol polymer such as polyvinyl alcohol (PVOH) dispersed therein, depositing the insoluble polymer in the wellbore or an adjacent formation, and thereafter dissolving the polymer by reducing salinity and/or increasing temperature conditions in the environment of the polymer deposit. The method is disclosed for filter cake formation, fluid loss control, drilling, hydraulic fracturing and fiber assisted transport, where removal of the polyol at the end of treatment or after treatment is desired. The method is also disclosed for providing dissolved polyol as a delayed breaker in crosslinked polymer viscosified systems and viscoelastic surfactant systems. Also disclosed are well treatment fluids containing insoluble amorphous or at least partially crystalline polyol, and a PVOH fiber composition wherein the fibers are stabilized from dissolution by salinity.

Description

WELL TREATMENT WITH DISOLUBLE POLYMER Field of the invention The invention relates to the treatment of oil and gas wells, more particularly with treatment methods and fluids that use a polymer that is at least partially insoluble in the treatment fluid during injection into the well and can be solubilized at the bottom of the well. Well by activation, inactivation or other functional modulation in the treatment of wells.

BACKGROUND OF THE INVENTION In a wide range of well treatment and formation methods it may be desirable to use various materials such as solids for downhole operations or procedures, and subsequently remove or dispose of the materials, after they have fulfilled their function, restore the properties to the drill hole or subsurface formations, or both, such as permeability for oil and gas production, to activate materials that fulfill a function such as a viscosity separator or decomposition aide. An example can be fluid loss control agents. When fluids are placed in oilfield applications, one of the main concerns is the loss of fluid into the formation. The loss of fluid reduces the efficiency of fluid placement with respect to time, fluid volume and equipment. Therefore, the control of fluid loss is a point of great importance in these applications. In a good percentage of oilfield applications, filtration cakes are necessary in the drilling hole, in the region close to it or in one or more strata of the formation. Such applications are those in which, without a filter cake, the fluid would escape through the porous rock at an undesirable rate during the treatment of the well. Such treatments include drilling operations, penetration of oil formation, completion, stimulation (for example, hydraulic fracture, or dissolution of the matrix), sand control (for example, gravel filling, fracturing and filling of sand formation and consolidation), diversion, scale control, water control and others. When the filter cake is inside the formation, it is usually called "internal" filter cake; in any other way it is called "external" filter cake. In general, after these treatments have been carried out, it is undesirable or unacceptable for the filter cake to remain there. For example, conventional aqueous drilling and completion fluids are often polymer-based to provide viscosity and fluid loss control. This option requires acid, oxidant or enzyme to remove the polymeric residue and the structure of the filter cake, to reduce the extent of the hazard in the formation. For example, it is common practice for a cementing agent such as calcium carbonate size to be used within the drilling fluid, in which case an acid plus a corrosion inhibiting package is then required to remove the filter cake. The drilling and general completion strategy based on polymeric fluids is often quite complicated from the operations point of view, it may lack long-term stability, it may employ corrosive chemicals and it may represent potential danger for the formation.

Hydraulic fracturing, gravel filling or fracturing and gravel filling in an operation (called, for example, fracture and filling treatment (frac and pack, frac-n-pack or frac-pack in English), are widely used to stimulate the production of hydrocarbons, water and other fluids from the subsurface formations, involving the pumping of a suspension of "suspending agent" (natural or synthetic materials that keep a fracture open after it is created) in a hydraulic fracture or "gravel" in gravel fill In low permeability formations, the objective of hydraulic fracture in general is to form fractures of high, extensive surface area that greatly increase the magnitude of the fluid flow path from the formation to the hollow of drilling. high permeability, the aim of the hydraulic fracture treatment in general is to form a very conductive, wide and short fracture, to deflect the damage near the perforation hole created in the drilling or completion operation, to ensure a good fluid connectivity between the stratum and drill hole and also to increase the available surface area for fluids to flow into the drill hole. Gravel is also a natural or synthetic material, which may be identical to, or different from, the support agent. The gravel filling is used for the control of "sands". Sand is the name given to any particulate material, such as clays, from the formation that could be transported within the production equipment. Gravel filling is a method of sand control used to prevent sand production from forming, in which, for example, a steel sieve is placed in the drill hole and the surrounding ring is filled with a gravel prepared of a specific size designed to avoid the passage of sand from the formation that could soil the subsoil or surface equipment and reduce the flow. The primary objective of gravel fill is to stabilize the formation while minimizing spoilage by well production. Sometimes the gravel filling is formed without a sieve. The high permeability formations often consolidate very little, so that control of the sands is needed. Consequently, hydraulic fracture treatments in which short and wide fractures are desired are often combined in a single continuous operation ("fracture and filling") with the gravel filling. For simplicity, reference can be made below to any one of hydraulic fracture, fracture and gravel filling in one operation (fracture and filling), or gravel fill, and includes them all; the term "support agent" may also refer to and include gravel and the term "gravel" support agent. Solid, substantially insoluble, sparse or slowly soluble materials (which can be termed fluid loss additives and filter cake components) are usually added to the fluids used in these treatments to form filter cakes, although sometimes components soluble (or at least highly dispersed) fluids (such as polymers or cross-linked polymers) can form some or all of the filter cakes. Removal of the filter cake is usually carried out by mechanical means (scraping, pressure jet or similar mechanisms), by subsequent addition of a fluid containing an agent (such as an acid, a base, an oxidant). or an enzyme) that dissolves at least a part of the filter cake, or by manipulation of the physical state of the filter cake (for example, by inversion of the emulsion). These disposal methods usually require a tool or the addition of another fluid (for example, to change the pH or add a chemical compound). Sometimes this can be done in the drill hole but usually it can not be done in a support or gravel filling agent. Sometimes the operator can rely on the flow of the produced fluids (which will be in the opposite direction of the flow of the fluid when the filter cake was established) to release the filter cake or dissolve at least a part of it (for example, if it is a soluble salt). However, these methods require fluid flow and often end in slow or incomplete removal of the filter cake. Sometimes a separation agent may be incorporated in the filter cake but these should normally be delayed (eg, by esterification or encapsulation) and are often expensive or difficult to place and difficult to activate. In hydraulic fracturing, a first viscous fluid called a "filler" is first injected into the formation to initiate and propagate the fracture and often contributes to the control of fluid loss. The choice of filling fluid depends on the nature of the fluid subsequently injected, the nature of the training and the desired results and the attributes of the stimulation operation. This is usually followed by a second fluid designed primarily to carry the sustaining agent that keeps the fracture open after the pumping pressure is released. Sometimes, the hydraulic fracture is elaborated with a second fluid that does not have a very high viscosity; This selection is mainly made to save costs of the chemical compounds and to reduce the damaging effect of the polymers described later. This technique, sometimes called a "water fracture" involves the use of extremely low polymer concentrations, so low that they can not be effectively cross-linked during the operation. This alternative has a great disadvantage: since it does not have enough viscosity to withstand much suspending agent, high pumping rates must be used and only very small concentrations of suspending agent can be used (pounds of mass of added support agent per gallon of fluid ("PPA"). After the pumping stops, very little supportive agent will be placed in the fracture to keep it open. Normally the viscosity of fillers and fracture or gravel filler fluids is normally increased in one of three ways. If the fluid injected is oil, it is gelled with certain additives designed for that purpose, such as certain aluminum and phosphate compounds. If the fluid is water or brine, for hydraulic fracture or acid, it is gelled with a polymer (usually a polysaccharide such as guar, regularly crosslinked with a boron, zirconium or titanium compound), or with a surfactant fluid system viscoelastic (ATVE) that can be formed using certain surfactants that form micelles of appropriate size and shapes. ATVEs are popular because they leave a lift agent or very clean gravel packs, but they do not form a filter cake by themselves. Polymers, in particular crosslinked polymers, often tend to form a "filter cake" on the filtering face, ie they cover the filtering face to prevent some leakage of fluid, when the rock pores are too small to allow the entrance of the crosslinked polymer or polymer. In general, some filter cake is desired for the control of fluid loss. This process of forming the filter cake is also called wall formation. ATVE fluids without additives against fluid loss do not make filter cakes as a result of leakage. The leak control by ATVE, in the absence of fluid loss additives, is the controlled viscosity, that is, the resistance due to the flow of the fluid.

ATVE fluid viscous through the porosity of the formation limits the speed of leakage. The viscosity controlled leak rate can be high in certain formation permeabilities because the high shear thinning fluid has a low apparent viscosity in the high flow velocity areas. The reduction of the flow velocity (with the corresponding reduction of the pressure gradient or simply as a result of the same injected volumetric flow rate that escapes into the formation through a larger surface area as the length and height of the fracture grows) will allow that resembles a micellar structure and will result in viscosity regeneration and fluid loss control. The control of fluid loss may not always be optimal with ATVE systems, particularly in high permeability formations. On the other hand, polymers have two main deficiencies: a) the filter cake, if left in place, may impede the subsequent flow of the hydrocarbons into the fracture and then into the drill hole, and b) the polymer or Cross-linked polymer will stay in the fracture, preventing or cutting the flow, by physically blocking the flow path through the filling of the support agent or by leaving the high viscosity fluid in the fracture. ATVE fluids do not form a filter cake or leave solids in the fracture. Consequently, the ATVE fluids leave a more conductive fracture, cleaner, therefore, of more production than polymer-based fluids. They are used more easily by requiring fewer components and less equipment on the surface, but may be less effective (in terms of fluid loss) than polymers, depending on the permeability of the formation and the specific ATVE system. It would be desirable to employ more efficient ATVE fluid systems in terms of fluid loss. To solve the high loss of fluid in polymeric and ATVE-based fluids (particularly in hydraulic fracture fluids, gravel carrier fluids and pill solutions for fluid loss control), various control additives have been proposed for the loss of fluid. fluid. Substances for reducing fluid loss are silica, mica and calcite, alone, in combination, or in combination with starch, in polymeric base fracture fluids, forming a filter cake relatively impermeable to water in the formation face, as described in U.S. Patent No. 5,948,733. However, it has been observed that the use of these fluid loss control additives alone in an ATVE-based fluid, which generates only very few decreases in fluid loss, as described in U.S. Pat. 5,929,002. The poor performance of these conventional fluid loss additives is generally attributed to the high leakage period (initial loss) before a filter cake is formed and the formation of an ATVE-based fluid-permeable filter cake. Instead of the conventional fluid loss additives and the formation of the filter cake, the treatment of a subsurface formation is known by pumping a colloidal suspension of small particles in a viscoelastic surfactant fluid system; see U.S. Patent Application Publication No. 2005-0107265, assigned to the assignee of the present application. The colloidal suspension and the viscoelastic surfactant interact to form structures that effectively cements and blocks the porous channels. Colloidal suspensions are usually dispersions of very small discrete particles, spherical or elongated, charged in such a way that repulsion between particles with the same charge stabilizes the dispersion. The disturbance of the charge equilibrium, due, for example, to the elimination of water, changing the pH or adding salt or water-miscible organic solvent, causes the colloidal particles to aggregate, which ends in the formation of a gel. These particles usually have a size less than 1 miera, and usually in the range of about 10 to about 100 nanometers. The dispersion is pre-filled with a liquid, transparent in the case of particles of relatively low concentrations, which becomes opalescent or milky at higher concentrations. In any case, the dispersion can be handled as a liquid, which greatly simplifies the dosage.

It has been proposed to use a hydrolysable polyester material to be used as a fluid loss additive for fluid loss control for fluids which are increased in viscosity with a polymer. After treatment, the additive loss of fluid degrades and thus contributes little to damage. In addition, degradation products of such materials have been shown to cause delayed separation of fracture fluids with viscosity increase by polymer. US Patent No. 4 715 967 discloses the use of polyglycolic acid ("PGA") for its acronym in English) as a fluid loss additive to temporarily reduce the permeability of a formation SPE 18211 discloses the use of PGA as a fluid loss additive and a gel separation agent for cross-linked hydroxypropyl guar fluids US Pat. No. 6,509,301 describes the use of acid forming compounds such as PGA as delayed decomposition agents of surfactant-based vesicle fluids, such as those formed from zwitteponic lecithin material. preferred of these materials is above 6.5, more preferably between 7.5 and 9.5 Since the ATVE fluid systems cause very little damage, it would be desirable to use a fluid loss additive that is compatible with the ATVE system and that causes very little damage. The use of polyglycolic acid and similar materials as a fluid loss additive for the ATVE fluid systems is described in U.S. Patent Application No. 11 / 159,023, filed on June 22, 2005 In summary, polyglycolic acid and similar materials are most frequently degraded by a hydrolysis mechanism, catalyzed by an acid or a base However, these fluid loss additive materials, as commercially obtained, often contain small amounts of acid or begin to hydrolyze to form acids when the fluids are first mixed or injected. To avoid the damaging effects of these factors, a base was included. or buffer solution in the fluid In some cases viscous fluids are used in the treatments in which some or all of the fluids are allowed to invade the formation, in which case one of the components is required to be a separating agent but not necessarily a fluid loss additive. In the placement of "end dewatering" fracture treatment, it is desirable to include a fluid loss agent that places a temporary filtration cake on the fracture faces in the early part of the treatment, for example, during the filling. Ideally, this filter cake would then be destroyed in the later stages of the treatment in such a manner that the increased fluid loss during the stages of the support agent will allow end-level desander to occur. The final result is a short but wide fracture with a high concentration of suspending agent. The fluid loss agent is usually injected into the fracture with an initial fill volume used to initiate the hydraulic fracture. After injection of the filler, the suspending agent suspension, which may also contain a fluid loss agent, is pu into the fracture at various stages depending on the design of the operation. The lift agent is designed to keep the fracture open and allow the reservoir fluid to flow through the lift agent fill. The suspension of the suspending agent generally includes a viscous carrier fluid which prevents the suspending agent from precipitating prematurely from the suspension. After the support agent has been placed in the fracture, the pressure is released and the fracture is closed over the support agent. However, it is necessary to remove or break both the viscosifier in the carrier fluid and the filter cake (which may contain concentrated polymer) in such a way that the reservoir fluids can then flow towards the fracture and through the backfill filling the drill hole and the production string. Conventional fracture design is well known in the art. See, for example, U.S. Patent No. 5,103,905, "Method of Optimizing the Conductivity of a Propped Fractured Formation". the conductivity of a fractured formation with a support agent) awarded to Schlumberger. The problems of cleaning a fracture are clearly recognized in the literature. Although other systems are used such as viscoelastic surfactants, gelled oil, oily film water, etc., most of the fluids to form fractures and contain the suspending agents are polymer based. In most reservoirs with lower permeability, the polymer is concentrated when the fluid escapes during the fracture process. The concentrated polymer interrupts the flow of fluid in the fracture and frequently causes the inefficiency of the fractures. Typical solutions include the use of separation agents, including encapsulated separation agents that allow a significant increase in the charge of the separation agent. The separation agent is added to the fluid / suspension and is intended to reduce the viscosity of the polymer-based carrier fluid and facilitates the cleaning of the fracture. Despite a high charge of separation agent, the retained permeability of the support agent package is still only a fracture of the initial permeability and this has been an accepted industry situation. U.S. Patents Nos. 4,848,467 and 4,961,466 discuss the use of hydroxyacetic acid and similar condensation products that naturally degrade at the reservoir teature to release acid which may be a separation agent for some. Polymers under some conditions and that offers control of fluid loss. U.S. Patent No. 3,960,736 (Oree) discusses the use of esters to provide a delayed acid, which will break the fluid by attacking both the polymer and the borate crosslinks. Also, U.S. Patent Nos. 4,387,769 and 4,526,695 (Erbstoesser) use acid generating mechanisms, which suggest the use of an ester polymer. U.S. Patent No. 3,868,998 (Lybarger) also mentions acid generation. These references are based on acids, which in general have a relatively low activity as separation agents, but the separation agents Oxidizers are much more effective and have become the industrial standard for eliminating polymer hazards. In addition, although a low pH can break down the crosslinking bonds of the borate, it is less effective for the separation of the commonly used zirconium and titanium crosslinked gels. In fact, some gel systems that use zirconium or titanium are designed to be effective viscosifiers at low pH. As used herein, the term "separation agent" refers to a part or set of chemical parts whose primary function is to "break" or reduce the viscosity of the fluid containing the suspending agent. Generally in the prior art, although not always, this occurs by oxidation. In addition, "separating aides" are often used in conjunction with separation agents that promote the activity of the separator. The spacing assistants are disclosed in, for example, U.S. Patent No. 4,969,526, "Non-Interfering Breaker System for Delayed Crosslinked Fracturing Fluids at Low Temperature" (Interference-free separator system for delayed cross-linking of fluid fractures). at low temperature), awarded to Schlumberger (which reveals and claims triethanolamine); and U.S. Patent No. 4,250,044. Also, "retarding agent" (or materials designed to inhibit crosslinking) may function in conjunction with the present invention. See, for example, U.S. Patent No. 4,702,848, "Control of Crosslinking Reaction Rate Using Organozirconate Chelate Crosslinking Agent and Aldehyde Retarding Agent" (Crosslinking reaction rate control using an organochromaconate chelate crosslinking agent and agent aldehyde retarder) awarded to Schlumberger (which reveals and claims the aldehydes). The copper and silver ions are also known to function as catalysts in conjunction with a chemical separator, dissolved oxygen or other oxidizing source, accelerating the activity of the separation agent. In addition, various matrices containing suspending agent can be used with different types of separating agents, for example, injection in a first stage of a less viscous or less dense fluid, or both, followed by fluids of less mobility. See, for example, the Patent US Pat. No. 5,036,919"Fracturing with Multiple Fluids to Improve Fracture Conductivity" awarded to Schlumberger. U.S. Patent No. 5,036,919 discloses, for example, pumping fluid with zirconium crosslinks followed by a fluid of borate crosslinks. Therefore, it is known to use different fluids in different stages of treatment. SPE documents 68854 and SPE 91434 disclose that the fibers included in the suspending agent suspension in the carrier fluid can serve as an aid in the transport of suspending agent at low viscosities and lower suspension flow rates, provided the fibers in length , appropriate diameter and rigidity are chosen and used at the correct concentration. For years the fibers have been used for different purposes in oil field treatment operations. More recently, fiber-assisted transport technology has been used to improve particle transport in fracture and hole-hole cleaning operations while reducing the amount of other fluid viscosifiers required. Recent efforts to improve this technique have shown better ways to remove more completely the fibers that can be left in the hole of perforation or fracture. In the U.S. Patent Applications Serial No. 1 1 / 156,966, assigned on June 20, 2005 and 1 1 / 059.123, with priority date of July 2, 2004, materials of polyester such as fibers and particles for transport supported on supporting agent fibers in a fracture method, and for fluid loss control, respectively. The polyesters can be selected from lactide, glycolide, polylactic acid, polyglycolic acid, a copolymer of polylactic acid and polyglycolic acid, a copolymer of glycolic acid with other hydroxy-containing parts, carboxylic acid or hydrocarboxylic acid, a copolymer of lactic acid with other hydroxy, carboxylic acid or hydrocarboxylic acid, substituted or unsubstituted, or mixture of these materials. The Polyester materials naturally degrade usually 4 hours to 100 days after treatment to facilitate the restoration of permeability. Other references that may be pertinent to the present invention include U.S. Patent Nos. US2004 / 0216876; US2005 / 0034865; and US6394185. There remains a need for improved methods of placing a fluid loss control agent and removal of said agent to recover the permeability of the production formation, in particular where removal of the fluid loss control agent does not require a change pH or depends on a chemical reaction to initiate the elimination. Likewise, there is a need for improved methods of viscosity separation of well treatment fluids with increased viscosity, in particular by employing a separating agent or separating aid that does not require pH change or chemical reaction to activate the viscosity agent. separation or assistant separator. There also remains a need for improved methods employing a fluid loss control agent or separation agent that can be placed downhole in insoluble form and solubilized by changes in salinity and / or by exposure of the fluid loss agent. at a temperature above an activation temperature of the solution. In addition, there is a need for improved methods wherein a well treatment fluid additive can be used in an insoluble form as a fluid loss control agent, support agent transfer fiber supported by fibers, or similar materials, and then it can be solubilized by changing the salinity conditions or by exceeding an activation temperature for elimination and thus recovering the permeability, by separating a well treatment fluid with increase in viscosity, or similar materials.

SUMMARY OF THE INVENTION This invention overcomes many of the limitations of prior fluid systems.

In the present invention, a dissolvable polymer is used in a well treatment fluid in solid form under conditions where the polymer is not dissolved, and after the polymer has fulfilled its function in solid form, it is subsequently dissolved by altering the conditions such as the temperature or salinity to activate the polymer and that fulfills its function in a soluble state or for the removal of the polymer. An example of a polymer having said capacity is a polyol such as polyvinyl alcohol (PVOH). PVOH is a synthetic polymer soluble in water, which is available in many forms such as powder, granules, beads and fibers. The solubility of an amorphous or partially crystalline PVOH in aqueous solution is a function of temperature and salinity. The control of these parameters allows the use of PVOH as, for example, fluid loss control agent and as a seal of temporary formation. The PVOH at some concentrations forms a thick paste, very viscous at high salinity, while at low salinity it dissolves completely. Therefore, placing the fluid in a high salinity site provides the amorphous consistency of PVOH to temporarily seal and control fluid losses. The seal cleaning mechanisms of the formation are based on the solubilization of the PVOH in a low salinity environment, for example, fresh water, 2% KCl or similar conditions. The present invention also discloses a non-damaging piercing fluid composition based on surfactants and a polyol-based fluid loss control agent, which provides ease and flexibility for subsequent completion processes. As another example, PVOH is also available as a newly developed fiber material for the textile industry. PVOH fibers are used in fiber-supported transport technology in hydraulic fracturing to place the support agent in the fracture, and PVOH fibers are easily removed from the support agent package as they become soluble in aqueous fluids of low salinity at characteristic formation temperatures. This technology is also applied in gravel fill to create more airtight and cleaner fillings.

As used herein, the term "particles" is used to refer to PVOH or other polyols in their different insoluble physical forms, whether crystalline or amorphous, including powder, granules, beads, pulp, fibers or similar materials. More generally, in one configuration, the invention provides a method of treating wells including: injection into a well of a treatment fluid comprising insoluble polyol particles dispersed therein; maintenance of insoluble conditions for polyol particles during downhole placement; and a selected step of heating, desalting and combinations of these, and then substantially dissolving the polyol particles. The polyol can be solubilized by heating, desalination (note that desalination does not necessarily mean a complete removal of salt but rather a sufficient decrease in salinity) or a combination of these, and consists essentially of carbon atoms substituted with hydroxyl, in a polymer chain, separated from adjacent hydroxyl-substituted carbon atoms in at least one atom in the polymer chain, typically a carbon atom. In one configuration, the polyol comprises a polymer having repeating units according to the following formulas: 1 wherein R1 and R1 'may be the same or different alkyl, saturated or unsaturated, linear or branched chains having from 1 to 5 carbon atoms, and yn' may be the same or different integers from 1 to 5, and R2 is a hydrogen or an alkyl chain, saturated or unsaturated, aliphatic or aromatic, linear or branched having 1 to 12 carbon atoms. As used here, the term "desalination" is used to refer to any reduction in salt concentration in the local environment of the effective polyol to solubilize said polyol, usually by dilution or washing of more or less immobilized polyol with less saline water, even where the salt content total in the system can not really be diminished. In another configuration, the polyol is a polyvinyl alcohol prepared by at least partial hydrolysis of a precursor vinyl polymer with ester substituents. When the polyol comprises polyvinyl alcohol (PVOH) made by at least partial hydrolysis of polyvinyl acetate, the well treatment fluid is injected under conditions, for example, at a particular temperature and salinity, at which the PVOH is not substantially dissolved . In one configuration, the polyol has a weight average molecular weight greater than 5000. The polyol can, if desired, be modified in hydrophobic form. The well treatment fluid can be a fluid loss control pill solution, a water control treatment fluid, a scale inhibition treatment fluid, a fracture fluid, a gravel filler fluid, a fluid of drilling and a fluid of penetration of oil formation or similar fluids. In one configuration, the treatment fluid has an effective salinity to inhibit the dissolution of the polyol at the formation temperature and the polyol is desalted in the dissolution step. For some polyols, the salinity of the treatment fluid is at least about 2 weight percent to inhibit the dissolution, and at least about 5, 6 or 10 weight percent for other polyols; For some polyols, the desalting step reduces salinity to less than about 5% by weight to dissolve the polyol, and less than 2 percent by weight in another configuration. If desired, the downhole placement of the polyol particles is on a permeable formation surface to inhibit the loss of fluid towards formation. The step of dissolving the polyol can be used to, at least partially, recover the permeability of the surface of the formation.

In another configuration, the polyol solution is within a fluid with increased viscosity in an amount effective to separate a viscosifier in the fluid with increased viscosity. The fluid with viscosity increase may be the well treatment fluid in which the polyol is injected, or it may be another fluid injected, mixed or otherwise placed adjacent to the polyol before or after the placement of the polyol at the bottom of the polyol. water well. The viscosifier may be a crosslinked polymer such as, for example, a polysaccharide, and the crosslinking agent may be borate, zirconate, titanate, aluminate or similar ions or combinations thereof. In another configuration, the viscosifying agent comprises a viscoelastic surfactant system, for example, betaines, amidoamine oxides or the like. In another configuration of the well treatment method, the polyol particles are, at least partially, like crystalline fibers soluble in fresh water above an activation temperature. The fibers may have a length of about 2 to about 25 mm, and a denier of about 0.1 to about 20. In one configuration, the treatment fluid during injection has a temperature below the activation temperature and the downhole placement is in a formation that is at a temperature above the activation temperature. The treatment fluid may have an effective salinity to inhibit the dissolution of the polyol at the formation temperature and the dissolution step may include desalination. In a configuration employing the polyol fibers, the treatment fluid is a suspension of the fibers and suspending agent in a viscous carrier fluid. The method may include transport of support agent with the aid of fibers. The carrier fluid may include a viscosifying agent and in one configuration the dissolved polyol is a separating agent for the viscosifier. The carrier fluid may be a saline solution in an effective amount that inhibits the solubility of the polyol above the activation temperature, and the method may include maintaining the salinity conditions to retard the dissolution of the polyol during the closure of the fracture.

In another configuration, the polyol, in the injection may be finely divided amorphous particles, the insoluble conditions may include salinity, for example, at least about 2, 5, 6, or 10 weight percent in different configurations, and the The dissolution step may include desalting, for example, less than about 5 or less than about 2 weight percent in different configurations. The amorphous polyol may be present in the well treatment fluid as a supervisory phase. In one configuration, the injection may include injecting the treatment fluid containing the amorphous polyol particles into a formation adjacent to the well at a pressure sufficient to create a fracture in the formation, said fracture having opposite faces, and forming a filter cake. comprising the polyol particles on one face of the fracture. The injection of the treatment fluid may be after the injection of a fluid containing support agent having reduced salinity, or after injection of a fluid containing support agent, high salinity and then by a fluid without support agent which has reduced salinity. Alternatively, the injected treatment fluid includes suspending agent, and the injection of a fluid containing suspending agent is followed by the injection of a fluid without suspending agent having reduced salinity. In another configuration, desalination is effected or supported by the initiation of fluid flow from the formation through a filling of the supporting agent in the fracture. Desirably, the fracture has opposite faces, a viscosifying agent is concentrated adjacent to the filter cake, and a thickness of the filter cake and concentrated viscosifying agent on each face of the fracture is less than half the width of the fracture. . In another configuration of the method employing the amorphous polyol particles in the perforation, the well treatment method includes: the circulation of the treatment fluid in the well while drilling: the formation of a filter cake comprising polyol particles over the bottomhole surface; the contact of the filter cake in a production zone with a low salinity fluid to recover the permeability; and the production of fluid from a formation in the production area. In this method, the well treatment fluid may be a drilling fluid, for example, an otherwise clean drilling fluid substantially free of particles (other than polyol particles) that a viscoelastic surfactant system may employ for increase the viscosity of the fluid. In another aspect, the invention provides a composition in the form of a well treatment fluid. The fluid may include an aqueous base fluid, a viscosifier system for the base fluid, and (1) a fluid loss control agent comprising finely divided particles of amorphous polyol dispersed in the base fluid, wherein the polyol is soluble in fresh water and insoluble in saline, and salinity to inhibit the dissolution of the polyol particles, and / or (2) at least partially crystalline polyol fibers in fresh water above an activation temperature, and having approximately to about 25 mm and a denier of about 0.1 to about 20. The viscosifier in the composition can be a crosslinked polymer such as, for example, a polysaccharide, and the crosslinking agent can be borate, zirconate, titanate , aluminate or similar ions or combinations of these. In another configuration, the viscosifier in the composition comprises a system of viscoelastic surfactant, for example, betaines, amidoamine oxides or similar compounds. Either crystalline or amorphous, the polyol in the composition may consist essentially of hydroxyl-substituted carbon atoms, in a polymer chain, separated from adjacent hydroxyl-substituted carbon atoms in at least one atom in the polymer chain, for example, at minus one carbon atom. In one configuration, the polyol comprises a polymer having repeating units according to the following formulas: 1 wherein R1 and R1 'may be the same or different alkyl, saturated or unsaturated, linear or branched chains having from 1 to 5 carbon atoms, and yn' may be the same or different integers from 1 to 5, and R2 is a hydrogen or an alkyl chain, saturated or unsaturated, aliphatic or aromatic, linear or branched having 1 to 12 carbon atoms. In another configuration, the polyol is a polyvinyl alcohol prepared by at least partial hydrolysis of a precursor vinyl polymer with ester substituents. When the polyol comprises polyvinyl alcohol (PVOH) made by at least partial hydrolysis of polyvinyl acetate, the well treatment fluid is injected under conditions, for example, at a particular temperature and salinity, at which the PVOH is not substantially dissolved . In one configuration, the polyol has a weight average molecular weight greater than 5000. The polyol can, if desired, be modified in hydrophobic form. The treatment fluid of the composition can be a fluid loss control pill solution, a water control treatment fluid, a scale inhibition treatment fluid, a fracture fluid, a gravel filler fluid, a drilling fluid and a fluid penetrating the oil formation or similar fluids. The composition may have an effective salinity to inhibit the dissolution of the polyol at room temperature, for example, at least about 2, at least about 5, at least about 6 and at least about 10 weight percent salinity. The composition may also have suspending agent suspended therein. The polyol may also be able to separate the agent system viscosifier in the solution, but is stabilized from the separation of the viscosifying system by the initial insolubility of the polyol. In a configuration of the composition including the polyol fiber, the polyol is insoluble in saline and the well treatment fluid has an effective salinity to inhibit the dissolution of the polyol at the activation temperature, for example, at the levels of salinity mentioned before. In another configuration of the composition including the polyol fiber, the carrier viscosity in the absence of fibers is insufficient to prevent sedimentation of the support agent during transport, wherein the fibers in the carrier inhibit or prevent settling of the carrier agent. lift during transport. In a further aspect, the present invention provides at least partially crystalline polyol fibers in contact with an aqueous medium wherein the fibers are stabilized by the salinity of the aqueous medium against the solution.

BRIEF DESCRIPTION OF THE DRAWINGS Figure 1 is a graph of fluid loss showing the fluid loss control through the salt concentration using polyvinyl alcohol (PVOH) with a core of 3.5 mD according to a configuration of the invention . Figure 2 is a graph of fluid loss showing the fluid loss control through the salt concentration using polyvinyl alcohol (PVOH) with a core of 38.55 mD according to a configuration of the invention. Figure 3 is a graph of retained permeability comparing the conductivity of a linear gel in a package of simulated support agent with a separate crosslinked fluid with PVOH according to a configuration of the invention. Figure 4 is a graph of retained permeability of the conductivity with respect to the temperature of a package of simulated support agent containing PVOH fibers according to a configuration of the invention.

Figure 5 is a rheological graph showing the separation effect of the PVOH fibers in a well treatment fluid according to the configurations of the invention. Figure 6 is a rheological graph showing the effect of separation with respect to the temperature of the PVOH fibers in a well treatment fluid according to a configuration of the invention. Figure 7 is a rheological graph showing the effect of separating different grades of PVOH in another well treatment fluid according to the configurations of the invention. Fig. 8 is a rheological graph showing the separation effect of the PVOH granules and the powder in a well treatment fluid according to a configuration of the invention. Figure 9 is a rheological graph showing the separation effect of the PVOH with the temperature in an ATVE base well treatment fluid according to a configuration of the invention. Figure 10 is a rheological graph showing the compatibility of a viscoelastic surfactant in fresh water and salt solutions according to a configuration of the invention. Figure 11 is a rheological graph showing the shear profile of a viscoelastic surfactant (ATVE) of betaine according to a configuration of the invention. Figure 12 is a rheological graph showing the shear thinning profile of the ATVE of Figure 11 according to a configuration of the invention.

Figure 13 is a rheological graph showing the effect of 5% diesel on the viscoelasticity of viscoelastic surfactant of base betaine and of another base according to a configuration of the invention. Detailed description of the configurations of the invention Polyols A polyol is a polyhydric alcohol, that is, one containing three or more hydroxyl groups. A configuration of polyols useful in the present invention is a polymeric polyol can be solubilized by heating, desalination or a a combination of these, and consisting essentially of hydroxyl-substituted carbon atoms, in a polymer chain, separated from adjacent hydroxyl-substituted carbon atoms in at least one atom in the polymer chain. In other words, the useful polyols are preferably essentially free of adjacent hydroxyl substituents. In one configuration, the polyol has a weight average molecular weight greater than 5,000 to 500,000 or more, and 10,000 to 200,000 in another configuration. The polyol can, if desired, be modified in hydrophobic form to further inhibit or retard solubilization, for example, including hydrocarbyl substituents such as alkyl, aryl, alkaryl or aralkyl or side chains having from 2 to 20 carbon atoms. The polyol can also be modified to include carboxylic acid, thiol, paraffin, silane, sulfuric acid, acetoacetylate, polyethylene oxide or quaternary amine or other cationic monomers. Such modifications have various effects on the properties of the polyol; of greatest interest for the present invention are the effects on solubility, salinity sensitivity, pH, and crosslinking functionalities (eg, hydroxyl groups and silanol groups which are chelates that can be cross-linked with common crosslinking agents). All such modifications are commercially available products. In one configuration, the polyol is a polyvinyl alcohol that can be made by at least partial hydrolysis of a precursor polyvinyl compound having ester substituents, such as, for example, polyvinyl acetate, polyvinyl propanoate, polyvinyl butanoate, polyvinyl pentanoate. , polyvinyl hexanoate, polyvinyl 2-methyl butanoate, polyvinyl 3-ethylpentanoate, polyvinyl 3-ethylhexanoate and similar compounds and combinations thereof. When the polyol comprises polyvinyl alcohol made by at least partial hydrolysis of polyvinyl acetate (PVOH), the polyol is generally not soluble in saline water, as mentioned in more detail below, and in addition, the polyol is commercially available in the form of partially crystalline fibers that have a relatively concise activation temperature per below which the fibers are not soluble in water and above which they dissolve easily, they are also discussed in more detail below. Suitable repeating units in the polyols can have the following formulas: The polymers may contain units 1 and 2 in varying proportions, where R1 and R1 'may be the same or different but are usually the same. In the structures, R1 or R1 'is an alkyl, saturated or unsaturated, linear or branched chain containing from 1 to 5 carbon atoms, and n and n' = 1 to 5, and where n and n 'may be the same or different, but preferably the same. R2 is an alkyl chain which can be saturated or unsaturated, aliphatic or aromatic, linear or branched from 0 (ie, hydrogen) to 12 carbon atoms. In the above formulas, m = 0 to 5,000 and m '= 100 to 10,000. Units 1 and 2 can have an alternate, random or block configuration. From the above general description, polymers can be defined by change parameters. For example, the polyhydric alcohol of 99.99% with a molecular weight of about 5000 would be: m = 0, R1 '= CH2, n' = 1, m '= 100. Polyvinyl alcohol with 90% hydrolysis and molecular weight of about 5000 and polyvinyl acetate derivative would be: m = -10, n = n "= 1, R1 = R1 '= CH2, R2 = CH3, m" = ~ 90 Example of polyol-PVOH For the purpose of illustration only, the invention is described below with reference to polyvinyl alcohol (PVOH) as an example of a suitable polyol. Those skilled in the art will appreciate that the present invention is not limited to PVOH and can equally be applied to polyols that meet with the previously established requirement of alterable solubility modes in the fluid context and well treatment methodologies. A particular advantage of PVOH is that it is non-toxic and biodegradable. For example, PVOH is commonly found in the medical industry and is usually in the form of fibers in clothes or fabrics that are destined to dissolve when washed in warm or hot water. PVOH is a solid material that is manufactured in many forms, such as, for example, fibers, sheets, granules, beads, powder and the like. PVOH is a synthetic polymer that is soluble in water and generally does not affect hydrocarbons. The polymer comprises a central carbon chain structure with hydroxyl and acetate groups. According to Kirk et al., Encyclopedia of Chemical Technology, 3rd Edition, Vol. 23, John Wiley and Sons, p. 848-865 (1983), PVOH can be produced by hydrolysis of polyvinyl acetate in methanol catalyzed by a base according to the following equation: NaOH -CHChV -CHCH2- -CHCH2-CH3OH 0CCH3"OH x 0CCH3 and II II oo The PVOH in Generally, it can exist in three different states of aggregation, which are controlled by the solution conditions: In its solid state, the PVOH is semi-crystalline.The degree of crystallinity varies from one mode to another of manufacture and with the degree of hydrolysis and degree of PVOH In aqueous solution, PVOH may lose its crystallinity and swell to form an amorphous structure, which is flexible and malleable, but not yet solubilized.According to the solution conditions, PVOH can be completely solubilized and exist as a polymer in solution. invention can use the PVOH in insoluble form to create a filter cake or otherwise place the PVOH in the bottom of the well in a drilling or forming hole. Salinity or temperature conditions, or both, adjacent to the PVOH deposits, the PVOH can be solubilized with what the PVOH deposits would come out or activate the PVOH for use as separation agent or other downhole function, or both. Any such PVOH filter cake can be destroyed, as desired. The PVOH fibers used in transport with the aid of fibers, for example, are removed to improve permeability. The solubilized PVOH can be used as, for example, a delayed separation agent for the crosslinked polymer or the viscoelastic surfactant (ATVE fluid systems). The invention takes advantage of the fact that the solubility of PVOH and similar polyols in aqueous media can be controlled by the salt content. In a brine of sufficiently high salt concentration, the polyol is insoluble but will become a sticky, flexible material that easily bonds to itself and to solid surfaces. However, when the brine concentration falls below a critical salt level, the sticky solids of PVOH can become soluble and dissolve rapidly in the solution. The PVOH solution is controlled by the degree of hydrolysis, molecular weight, crystallinity, particle size and similar characteristics of the PVOH. The degree of hydrolysis is defined as the molar percentage of hydroxyl groups in the polymer chain relative to the non-hydrolyzed acetate groups. For example, PVOH with a degree of hydrolysis of 88 would have 88 mole percent hydroxyl groups and 12 mole percent acetate groups along the central structure of the polymer. The hydroxyl and acetate groups can be distributed randomly or in blocks. Most PVOH grades dissolve around 80 ° C (176 ° F). A degree of hydrolysis of about 88% is optimal for solubility, that is, the solubility of PVOH decreases when the degree of hydrolysis is more or less about 88%. When the degree of hydrolysis increases above 88%, the solubility decreases due to a more compact alignment of the hydroxyl parts that is estimated to produce a hydrogen bridge shape. Below 88% hydrolysis, the solubility decreases due to the increase in the number of acetate groups; Polyvinyl acetate is usually insoluble in Water. Other factors that affect the solubility of PVOH may include polymer concentration and salt concentration; the amount of non-solubilized PVOH, for example, amorphous PVOH, may increase with increasing salt or polymer well concentrations. The crystallinity of the PVOH can also be used to control the temperature at which the PVOH will dissolve. For example, PVOH that are partially crystalline in varying degrees can be soluble in water at temperatures ranging from 20 ° C to 90 ° C. As part of the dissolution process, the PVOH passes through a "sticky" state or amorphous state. The solubility and stickiness of the PVOH polymer can also be controlled through the salt concentration. For example, a PVOH fiber that is completely dissolved in 2% by weight of KCl brine at 80 ° C (176 ° F), may not be completely dissolved at 93 ° C (200 ° F) in 6% KCl brine. can only be deformed and coagulated at 93 ° C (200 ° F) in 10% KCl brine, and may not be affected at all at 93 ° C (200 ° F) in 12% KCl brine. the conditions and dissolution rate of the PVOH, which has a particular chemical and physical conformation, including crystallinity, degree of hydrolysis, molecular weight and distribution, a coating if present, at a particular temperature and in contact with a liquid or liquids of Particular salinity is easily determined by a simple experiment: exposure of PVOH to fluid or fluids under treatment conditions and monitoring of solubilization. PVOH can be manufactured and used in various solid forms, including, but not limited to, fibers, powders, granules, and the like. The system comprising a well treatment fluid and PVOH (and any other additive) can be batch mixed or mixed on the fly using otherwise treatment fluid mixing equipment and conventional mixing techniques. If the PVOH is in the form of crystalline fiber that is used mainly below its activation temperature for its placement and does not expand or become amorphous until a little before the downhole solubilization, then they are used usually straight fibers; nevertheless, the forms in Curves, curls, spiral and other three-dimensional fiber geometries are also useful. Also, the fibers can be in bundles or hooked from one end to the other. In one configuration, the length of the fiber is at least about 2 millimeters, and the diameter of the fiber ranges from about 3 to about 200 microns. From the point of view of its usefulness, there does not seem to be an upper limit of fiber length. The handling, mixing and pumping equipment will indicate the practical upper limit for the length of the fibers. Suitable PVOH fibers in one configuration have a length of about 2-25 mm, preferably about 3-18 mm, more preferably about 6 mm; they have a denier of about 0.1-20, preferably about 0.15-6. Such fibers are optimal for the transport of particles. If the PVOH is amorphous or changes from crystalline to amorphous form in the well treatment fluid, the particular physical form is less critical since the PVOH will form a sticky phase that will disperse as small particles in the treatment fluid. If the PVOH is to be used as a fluid loss additive, the particle size of the PVOH particles is chosen based primarily on the desired fluid loss properties (e.g., initial loss and wall formation coefficient). Typical particle sizes are beads or powders in the submicron range, for example, about 0.2 microns, to about 200 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 skilled in the art. Amorphous or partially crystalline PVOH fibers in these size ranges are also suitable. If the PVOH is to be used as a separation agent, the particles can be of a wide size range, for example, from nanoparticles (for the separation of an ATVE within a matrix) to the size of suspending agents for the reduction of the viscosity of the carrier fluid. PVOH and its properties, such as molecular weight and crystallinity, are chosen based primarily on the desired dissolution rates in the carrier fluid to be used at the temperature and salinity at which they will be used. These choices may also be influenced by the desired time before the delayed separation, which would depend on the size of the work, whether the operation is hydraulic fracture or gravel fill, and other factors known to those skilled in the art, including concentrations and nature of the ATVE or crosslinked polymer and any other additive, and temperature. In addition, there may be changes in the parameters during a treatment that are taken into account for the selection of a particular PVOH solid, which include the chemistry and crystallinity, its size and shape, and its concentration, among other factors, according to the form that is used. will use All these parameters can be affected by the nature of the operation, for example, whether fluid loss control is needed or not, the temperature, the nature of the formation, and the desired time before the reduction in viscosity occurs. or the desired time by which the separation has occurred, or all together. For example, fluid loss control may not be needed when making the gravel fill in a low permeability formation and the choices are made according to the separation properties. Suitable selections can be made with the aid of simple experiments such as those described above, or in the examples that follow, optionally with the help of simulation software. For example, when the PVOH fibers are used, they can have a solubility in water activated by temperature, for example above 90 ° C. The activation temperature must be higher than the injection temperature, but be lower than the temperature of the formation. In this manner the PVOH fibers are injected into the treatment fluid as a solid, but become soluble at the bottom of the well when the temperature increases above the activation temperature. Solubilization can be delayed by using PVOH fibers with an activation temperature a little below the formation temperature and continuous injection of low temperature fluids to keep the fibers below the activation temperature until dissolution is desired. Where the solubility of the fibers is controlled By maintaining a temperature below the activation, aqueous fluids with low salinity can be used. Also, the solubilization of the fibers can be controlled or further delayed using high salinity fluid such that if the activation temperature is exceeded, solubilization does not occur until the salinity is reduced. Care should be taken to avoid deterioration of fluid flow to a condition where the fibers are not completely soluble but become "sticky" so that they coagulate and block the interstitial spaces. It is recognized that fibers are used for various purposes in oil field treatment operations. The transport technology with the help of fibers has been used to improve the transport of particles in the operations of fracturing and cleaning wells while reducing the required amount of other liquid viscosifying agents. The present invention employs at least partially crystalline PVOH fibers to expand this technique to a greater degree since the fibers can be made to dissolve after the treatment so that no residues of permanent fibers remain in the perforation or fracture gap. This invention can also improve the gravel fill to create more airtight and cleaner fillings. PVOH fibers having temperature activators at the previously determined temperatures are commercially available, for example, under the commercial designation KURALON K-ll (Kuraray America, Incorporated). PVOH fiber has significant advantages over polyester fiber materials and other fibers currently in use. These PVOH fibers dissolve completely in water when brought to a defined activation temperature, but they are practically insoluble at a lower temperature over a wide range of pH and chemical conditions. These PVOH fibers are made to have temperature activation points determined for aqueous solution at desired temperatures between 20 ° C and 90 ° C, in increments of 10 ° C. When the PVOH fiber does not dissolve in an aqueous treatment or reservoir fluid, it releases the polyvinyl alcohol in solution. This can reduce the viscosity effectively of ATVE fluids. The dissolved fiber can also separate some of viscosity-increasing fluids based on cross-linked guar or another polymer since the addition of the dissolved polyvinyl alcohol effectively acts to separate the borate, titanate, zirconate and the like ions from the guar molecules, thereby reducing the viscosity of the polymer crosslinked to the linear gel. fibers and other forms of particles are also available in non-crystalline or semicrystalline / amorphous forms. When an amorphous PVOH is employed, the dissolution of PVOH can be controlled by salinity alone. The well treatment fluid in which the PVOH particles are introduced must have a high salinity to prevent premature dissolution. When it is desired to dissolve the PVOH solids, the salinity conditions are reduced by introducing low salinity after treatment fluid, for example, fresh water or 2% KCl solution, or where the formation water has a low salinity, allowing the interstitial water to flow to the surroundings of the PVOH solids. The PVOH solids can optionally be coated to retard dissolution. Suitable coatings include polycaprolate (a copolymer of glycolide and epsilon-caporlactone) and calcium stearate, both being hydrophobic. Polycaprolate only hydrolyses slowly. Generating a hydrophobic layer on the surface of the PVOH solids by any means of retarding the dissolution. It must be taken into account that coating can refer to encapsulation or basically to a change in the surface by chemical reaction or formation or addition of a thin film of another material. Another suitable method of retarding the dissolution of the PVOH solids is to suspend the solid, optionally with a hydrophobic coating, in an oil or in the oily phase of an emulsion. The dissolution does not occur until the low salinity water makes contact with the solid PVOH above any solubility activation temperature. Crossed polymers The PVOH can be used for fluid loss control or as a separating agent in well treatment fluids including viscosifying agents, especially metal crosslinked polymers. Suitable polymers for the preparation of viscosifying agents of metal crosslinked polymers include, for example, polysaccharides such as substituted galactomannans, such as guar gums, high molecular weight polysacátides composed of sugars and galactose sugars, or guar derivatives such as hydroxypropyl guar ( HPG), carboxymethylhydroxypropyl guar (CMHPG) and carboxymethyl guar (CMG), hydrophobically modified guar compounds, guar-containing compounds and synthetic polymers. Crosslinking agents based on complexes of boron, titanium, zirconium or aluminum are generally used to increase the effective molecular weight of the polymer and make them more suitable for use in high temperature wells. Other suitable classes of water soluble polymers effective as viscosifiers (provided the specific examples are compatible with the insoluble PVOH or other polyol) include polyvinyl polymers, polymethacrylamides, cellulose ethers, lignosulfonates and ammonium, alkali metal salts and alkaline earth metal of these. More specific examples of other characteristic water-soluble polymers are the copolymers of acrylic acid-acrylamide, acrylic acid-methacrylamide copolymers, polyacrylamides, partially hydrolyzed polyacrylamides, partially hydrolyzed polymethacrylamides, polyvinyl alcohol, polyalkylene oxides, other galactomannans, heteropolysaccharides obtained by the fermentation of sugar derived from starch and salts of alkali metal and alkaline earth metal of these. Cellulose derivatives are used to a lesser degree, such as hydroxyethylcellulose (HEC) or hydroxypropylcellulose (HPC), carboxymethylhydroxyethylcellulose (CMHEC) and carboxymethylcellulose (CMC), with or without crosslinking agents. It has been shown that xanthan, diuthane and scleroglucan, three biopolymers, have excellent suspending agent suspension capacity, although they are more expensive than guar derivatives and therefore they have been used less frequently, unless they can be used at lower concentrations. Polymeric (non-crosslinked) systems can be used, but generally they will not achieve the full benefit of the invention because they may require more polymer and may require a separation agent for the additional effect of PVOH. All crosslinked polymeric systems can be used, including, for example, optimized and delayed systems for high temperature, optimized in use with seawater, buffered at various pH, and optimized at low temperature. Any crosslinking agent can be used, for example, boron, titanium, zirconium, aluminum and the like. Suitable cross-linked boron polymer systems include, but are not limited to, substituted guar and guar cross-linked with boric acid, sodium tetraborate and capped borates; borate crosslinking agents can be used with buffer solutions and pH control agents such as sodium hydroxide, magnesium oxide, sodium dicarbonate and sodium carbonate, amines (such as hydroxyalkyl amines, anilines, pyridines, pyrimidines, quinolines and pyrrolidines, and carboxylates such as acetates and oxalates) and with retarding agents such as sorbitol, aldehydes and sodium gluconate. Suitable zirconium crosslinked polymer systems include, but are not limited to, those cross-linked by zirconium lactates (e.g., sodium zirconium lactate), triethanolamines, 2,2'-iminodiethanol, and with mixtures of these ligands, which include when they adjust with bicarbonate. Suitable titanates include, but are not limited to, lactates and triethanolamines, and mixtures, for example, retarded with hydroxyacetic acid. Any other chemical additive may be used or included with it to be evaluated with respect to compatibility with PVOH fibers or particles (the PVOH or chemicals in the fluids should not interfere with the effectiveness of one or the other or with the fluids that could encountered during the operation, such as interstitial water or washes). For example, some of the crosslinking agents or standard polymers as concentrates normally contain materials such as isopropanol, n-propanol, methanol or diesel oil.

Viscoelastic Surfactants A fluid system of viscoelastic surfactant (ATVE) is a fluid with increased viscosity with a viscoelastic surfactant and some additional material, such as, but not limited to, salts, surfactant coagents, rheology enhancers, stabilizers and Shear recovery enhancers that improve or modify the performance of the viscoelastic surfactant. PVOH can be used for fluid loss control or as a separation agent for ATVE systems. When the fluid loss control is not needed, the PVOH can still be used as a delaying separation agent, preferably in smaller particle sizes, which separate the fluid whether it is within a matrix of the formation or that PVOH fibers can be used. Useful ATVEs include cationic, anionic, nonionic, mixed, zwitterionic and amphoteric surfactants, in particular fluid systems, betaine zwitterionic viscoelastic surfactants or fluid systems, viscoelastic surfactant agents of amidoamine oxide. Some examples of viscoelastic surfactant systems include those described in U.S. Patent Applications Nos. 5,551,516 5,964,295; 5,979,555; 5,979,557; 6,140,277; 6,258,859 and 6,509,301. The PVOH in this invention is also useful when used with various types of zwitecanoic surfactants. In general, suitable zwitterionic surfactants have the formula: RCONH- (CH2) a (CH2CH2O) m (CH2) b-N + (CH3) 2- (CH2) a '(CH2CH2O) m' (CH2) b'COO-en where R is an alkyl group containing about 14 to about 23 carbon atoms which may be branched or straight chain and which may be saturated or unsaturated; a, b, a 'and b' 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 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 14; and the OR in either or both of CH2CH2O groups or chains, if present, may also be located at the end that approaches or moves away from the quaternary nitrogen. The preferred surfactants are the betaines. Two commercialized examples of the betaine concentrates are, respectively, BET-O-30 and BET-E-40. The surfactant agent ATVE in BET-O-30 is oleylamidopropylbetaine. BET-O-30 was designated because it is obtained from the supplier (Rhodia, Inc. Cranbury, New Jersey, United States) and is designated Mirataine BET-O-30; it contains an amide group of oleyl acid (which includes a group of alkene glue C17H33) and is supplied as an active surfactant of about 30%; the rest is practically water, sodium chloride, glycerol and propane-1,2-diol. A suitable analogous material, BET-E-40, is used in the experiments described below; it contains an erucylamidopropyl group (which includes a group of alkene tail C21 H41) and is approximately 40% active ingredient, where the remainder is practically water, sodium chloride and isopropanol. (Prior to use, about 1% of DAXAD 17, a low molecular weight sodium polyfnaphthalene sulphonate available from Hampshire Chemical Corporation, Nashua, NH, United States, is added to the betaine surfactant BET-E-40 in the form received. ). This ATVE fluid system can be prepared with 6% surfactant BET-E-40. BET surfactants, and others that are suitable, are described in U.S. Patent No. 6,258,859.

The determined surfactant coagents can be used in the extension of the brine tolerance, and to increase the gel strength and reduce the sensitivity of the ATVE fluid shear, in particular for the surfactants of the BET-O type. An example that is presented in US Pat. No. 6,258,859 is sodium dodecylbenzene sulfonate (SDBS). The ATVE systems can be used with or without this type of surfactant coagent, for example, those having an SDBS structure having a saturated or unsaturated, straight or branched chain of C6 to C16; Additional examples of surfactant coagent of this type are those having saturated or unsaturated, straight or branched chain of C8 to C16. Other examples of suitable surfactant coagents of this type, in particular for BET-O-30, they are certain chelating agents such as trisodium hydroxyethyl ethylene diamine triacetate. The use of PVOH fibers or amorphous solids in a well treatment methods while maintaining the stability of an ATVE system, and then dissolving the PVOH to separate the ATVE, can be used with any ATVE system regardless of the stability pH, that is, at high or low pH, provided that the fluid system with ATVE is compatible with the formation, formation fluids, and other fluids with which it comes into contact, for example, a filling fluid, and its components and additives. Although the invention has been described using the term "ATVE" or "viscoelastic surfactant" to describe non-polymeric well treatment fluids with increased viscosity, other non-polymeric materials can also be used to increase the viscosity of the fluid as long as the requirements described here are met, for example, the viscosity, stability, compatibility, and absence of danger for the drill hole, formation or each of the fracture. Examples, regardless of whether they form, or are described as forming, vesicles or viscoelastic fluids, include, but are not limited to, the viscosifying agents disclosed in U.S. Patent Nos. 6,035,936 and 6,509,301. ATVE fluid systems are most commonly used in treatments in which filter cakes are desired during treatment but are harmful after treatment, especially in hydraulic fracturing and gravel filling. The ATVE fluid systems can also be used when basically it is desired to separate the viscous fluids, whether a filter cake is formed or not; in some cases the fluid can invade the formation. Such viscous fluids may be, without limitation, hydraulic fracture fluids and gravel fill in fillings or formations, drilling fluids, drilling hole cleaning fluids, fluid loss control fluids, dominant fluids, spacers, Washes, pushers and vehicles for materials such as inhibitors of scale, paraffin and asphaltenes.

ATVEs can be destroyed alone on site, that is, at the location where they are placed. The location may be in part of a suspension in a treatment fluid in the drill hole, in perforations, in a gravel fill, or in a fracture, or as a component of a filter cake on the walls of a drill hole. or a fracture, or in the pores of the formation itself. The ATVE fluid system can be used in formations of any lithology but are used more frequently in carbonates or sandstones. As for the polymeric systems crosslinked with metal, any viscoelastic surfactant agent (ATVE) fluids system can also be used as long as they are evaluated with respect to their compatibility with PVOH fibers. Suitable non-limiting examples include those described in U.S. Patent Nos. 5,551,516; 5,964,295; 5,979,555; 5,979,557; 6,140,277; 6,258,859 and 6,509,301. PH controller We have found that insoluble PVOH (at treatment temperature and salinity), examples of which are crystalline fibers and amorphous particles, can be used as additives, for example, as a fluid loss additive or for another purpose, that produces a separation agent for a cross-linked polymer fluid system or viscoelastic surfactant. Since PVOH does not affect the pH and prevents premature separation by maintaining salinity and temperature conditions, a pH control agent would not be needed to ensure proper function of the PVOH, although they may be needed and can be used if desired, for example, to ensure that the crosslinked polymer or ATVE fluid system maintains the viscosity before separating. ATVE fluid micelles are normally broken by the natural influx of hydrocarbons and water or brine, although separation agents such as certain salts or alcohols are sometimes used. Some viscoelastic surfactants are known to form micelle / vesicle structure that can be damaged or destroyed by changes in pH, or In some cases, the surfactants themselves are damaged or destroyed. Some ATVE systems, for example, some cationic systems, are not very sensitive to pH, and some ATVE systems, for example, some anion systems, are usually buffered at a pH above 12 in normal use, and solids of PVOH of this invention can be used beneficially in any such system. However, since the PVOH solution functions as a separating agent which is not very sensitive to pH, ie it can be dissolved at ATVE fluid pHs by salinity reduction, it is possible to use an ATVE fluid at the desired pH with the suitable buffer solutions, if desired, such as, for example, acidic pHs in the range of 2-6, neutral pH in the range of 6-8 or basic pH in the range of 8 to 12. On the other hand, the PVOH it can be used in conjunction with, or in addition to, other separation agents such as acids or bases, and separating aids such as activators, retarding agents or stabilizers. Suitable pH control agents, if employed in the well treatment fluid, include, but are not limited to, sesquicarbonates, oxalates, carbonates, hydroxides, bicarbonates and organic carboxylates of sodium, potassium and ammonium, such as acetates and polyacetates . Examples are sodium sesquicarbonate, sodium carbonate and sodium hydroxide. Soluble oxides, which include slowly soluble oxides such as MgO, can also be used. Oligomeric amides and amines, such as alkylamines, hydroxyalkylamines, anilines, pyridines, pyrimidines, quinolines and pyrrolidines, for example, triethanolamine and tetraethylenepentamine can also be used. The choice of the pH control agent depends in part on the polymer system and ATVE used. For example, MgO usually precipitates anionic ATVE but is suitable for cationic and zwitterionic ATVEs. Some pH control agents based on inorganic compounds in salts, such as carbonates, can adversely affect the rheology of some ATVEs that are sensitive to the electrolyte concentration, so in the case of organic pH control agents such as amines would be a good selection Other additives When PVOH is used in fluids in treatments such as drilling, penetrating oil formation, completion, stimulation (eg, hydraulic fracture, or matrix dissolution), sand control (eg, gravel filling, fracturing and filling) the formation and consolidation of sands), deviation and others, the insoluble PVOH is generally inert to the other components of the fluids, thus the other fluids can be elaborated differently in the normal way, being careful to avoid conditions that would tend to solubilize prematurely the PVOH particles. Normally, such fluids would usually contain a fluid loss additive and a filter cake forming agent, thus the PVOH replaces some or the fluid loss additive and the filter cake forming agent that would otherwise It would have to be used. In many cases if the fluid contains a component that would affect or be affected by the PVOH, the amount or nature of the PVOH or the amount or nature of the interfering or interfering component can be adjusted to compensate for the interaction. This can easily be determined by simple laboratory experiments. Any additive normally used in such treatments may be included, again provided they are compatible with the other components and the desired results of the treatment. Such additives may include, but are not limited to, antioxidants, crosslinking agents, corrosion inhibitors, retarding agents, biocides, buffer solutions, fluid loss additives, etc. The treated drill holes can be vertical, deflected or horizontal. They can be completed with respect to the coating and perforations or open gap. Fluid loss control Using a well treatment fluid to provide a high salt environment, PVOH can be used in its sticky state to, for example, control fluid loss. The salt concentration in the fluid containing the PVOH may be 2 weight percent or more, preferably 5 weight percent or more, more preferably 6 weight percent or more, even more preferably 10 weight percent or more. greater, and the higher preference 12 percent by weight or greater. The choice of the salt is not particularly critical and the salt can be any salt that inhibits the solubilization of the PVOH and is otherwise suitable for use in a well treatment fluid. The PVOH can be used in the well treatment fluid at a concentration or loading of 0.6 to 24 g / l (from 5 to 200 ppt), preferably from 1.2 to 18 g / l (from 10 to 150 ppt) , and especially from 2.4 to 9.6 g / L (from 20 to 80 ppt). Then, the salt concentration of the environment can be lowered to dissolve the PVOH and clean the surface of the formation or the filter cake, at a salt concentration at which the PVOH is soluble, preferably a salt concentration of less than 5% by weight, more preferably 2 percent by weight or less, of fresh water. In the present invention, the PVOH can be used as, for example, a fluid loss control agent in a drilling fluid or fluid loss control pill in another conventional manner. As indicated above, the solubility of a PVOH in aqueous solution is a function of temperature and salinity, among other variables. By controlling these parameters, PVOH can be used as a fluid loss control agent and as a temporary seal of the formation. At a sufficient concentration the PVOH forms a thick paste, very viscous at high salinity, while at low salinity it dissolves completely. Therefore, by placing the fluid at high salinity, fluid loss particles with the consistency of amorphous PVOH are provided to seal the formation and control fluid losses temporarily by deposition on the surfaces as a film. The film on the face of the formation forms an external filter cake and the paste, which is capable of being introduced into the porous medium, forms an internal filter cake. Cake formation is an effective way to control fluid loss. The seal cleaning mechanisms of the formation are based on the solubilization of the PVOH in a low salinity environment, for example, fresh water, 2% KCl or similar conditions. Although there is no general consensus on the precise relationship of particle size, pore size and cementing formation, the following guidelines are used here. The particles that have larger diameters of About a third (although some researchers say half) of a pore channel diameter is expected to form cementation at or near the face of the formation. Smaller particles that are larger than one seventh of the diameter of a pore channel are expected to enter the formation and become trapped and form the internal filter cake. Smaller particles than a seventh of the diameter of a pore channel are expected to traverse the formation without significantly affecting the flow. It is understood that there are other important factors such as the particle distribution and pore sizes, flow rate, particle concentration, and particle shape. When a function of the fluid system of the PVOH is to control the leakage, the optimal concentrations of the PVOH in the particular fluid system are determined by the choice of the desired leakage parameters and the leakage measurement with fluid samples and the Certain formation or a rock similar to the formation. The leak is defined in three terms: "Initial loss" which is the initial rapid leakage of fluid before an initial filter cake barrier forms on the face of the fracture and is measured in liters / square meter (or gallons / 100 square feet), and for the subsequent leakage that occurs even after a filter cake is formed and governed by the viscosity and progress of wall formation: Cw, the coefficient of fluid loss by wall formation, and Cv, the coefficient of fluid loss by controlled viscosity. Cw can not be applied when there is no existing wall formation material. Cv can not be applied when there is a finite, low Cw. Cw and Cv are measured in mm / min1 / 2 (feet / min1 / 2). The following are the preferred, most preferred and most preferred values of the initial loss, Cw and Cv: The values of these parameters (and the actual behavior they represent) can vary significantly as long as a suitable filter cake is produced at an appropriate time. An evaluation method to determine these values is presented by Navarrete and others in "Dynamic Fluid Loss in Hydraulic Fracturing Under Realistic Shear Conditions in High-Permeability Rocks," SPE Production and Facilities, pp. 138-143 (August 1996). Separation agent, viscosity reduction PVOH can be used as a retarding agent reducing viscosity retarder in ATVE and crosslinked polymer systems. In dilution, the PVOH fiber or particles can function as a viscosity reducing agent. This will distribute the viscosity reduction in time for the delayed dissolution of PVOH to occur. Alcohol is known as a separation agent for ATVE, we have found that dissolved PVOH will separate well in ATVE systems. The dissolved PVOH also separates from viscosity-increasing fluids based on cross-linked guar or other polymer since the addition of the dissolved polyvinyl alcohol effectively acts to separate the borate, titanate, zirconate and the like ions from the guar molecules, with which reduces the viscosity of the cross-linked polymer to the linear gel. Although no connection with a particular theory is desired, it is estimated that the PVOH can separate the crosslinking ions from the polymer. When a cross-linked polymer is used, there is a tendency for the concentration of the polymer to form in the formation interface where the PVOH filter cake is deposited. This allows the PVOH to be solubilized where the concentration of the crosslinked polymer is the tiniest and therefore where more PVOH is needed to separate the polymer. Drilling Fluid PVOH can also be used for the control of fluid loss and as a separating agent in an inert drilling fluid composition. it can be based on surfactants, which provides ease and flexibility for subsequent completion processes. The composition overcomes the limitations with some previous fluid systems. The use of ATVE fluid systems based on surfactant are well known for use in gravel fill treatment for sand control, and such fluids have been proposed for use as drilling fluids. The present invention retains non-damaging properties, seawater resistance and high (brine) brine tolerance, but at the same time, introduces better oil compatibility, and the PVOH fluid loss control additive can be removed after , for example, by a simple change in salinity. The drilling fluid may include a surfactant-based fluid system that is compatible with high-density brines, including monovalent, divalent, and polyvalent ion brines, for use in drilling and drilling systems of petroleum, at any density desired, for example, a fluid density of up to 2.2 g / ml (18 ppg) or more. The surfactant agent fluid system exhibits a high yield point for shear transport and a low plastic viscosity for drag reduction. The drilling fluid has rheological properties similar to commercially used ATVE systems for fracture and gravel filling. The surfactant agent fluid systems of the invention provide acceptable tolerance to contaminants commonly encountered in drilling, such as, for example, cement, reactive scale, oil, etc. In the treatments of subsurface formations, particularly in hydraulic fracture and gravel fill treatments, the total volume of fluid pumped to complete the treatment is a function that depends markedly on the amount of fluid that is lost in the surrounding matrix. In conventional fluids having crosslinked polymers or polymers as the viscosifying agents, during the initial phase of the treatment, crosslinked polymers or polymers are filtered through the face of the rock to form a polymeric filter cake which subsequently avoids further losses. However, ATVE fluids are free of polymers, which in itself is a major advantage because the polymers, which remain in the matrix (or in the filling agent filling or gravel filling) once it is finished the treatment, are the main source of damage, and consequently the process of fluid loss is not governed by the formation of the filtering cake of the viscosifying agent. Fracture In the fracture process, the filling and the fracture fluid increase their viscosity because an increase in this causes the formation of a wider fracture, therefore in a larger flow path, and a minimum viscosity is required for transport adequate amounts of support agent; The actual viscosity required depends mainly on the flow rate of the fluid and the density of the suspending agent. In a characteristic fracture process, such as hydraulic fracture, the fracture is first initiated by pumping an aqueous fluid of high viscosity, with good to moderate leakage properties, and usually without supporting agent, to the formation . This filling is usually followed by a carrier fluid of similar viscosity which contains an initially low concentration and then gradually and stepwise increases the concentrations of Support in the extended fractures. The filling initiates and propagates the fracture but does not need to transport the support agent. All fluids tend to "escape" to the formation from the fracture that is created. Typically, at the end of the operation the full volume of the fill will have escaped from the formation. This leak is determined and controlled by the properties of the fluid (and 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 in the rock to change the properties of the rock or the counterflow in the fracture during closure, or b) if the intention is to deliberately provoke what is termed "end drift" (TSO), a condition in which the lift agent forms a bridge at the end of the fracture, stopping the extension of the fracture. the fracture and resulting in a subsequent increase in the width of the fracture. On the other hand, excessive leakage is not desirable because valuable fluid can be lost and result in reduced operation efficiency. Consequently, proper leakage control is critical to the success of the operation. In configurations of hydraulic fracture, fracture and gravel filling, gravel fill, an ATVE or polymer crosslinked in the filling can be added, throughout the entire treatment or only in some of the stages of the support agent or gravel. The PVOH can be a fiber in any of these uses and will retard backflow and settling of the supporting agent or gravel, and fines, if present, until the PVOH dissolves. In the hydraulic fracture, fracture and filling of gravel, filling of gravel are particularly useful a fluid loss additive and filter cake that are removed by themselves, because the mechanical methods of elimination are impossible and the methods involving the contact of the fluid loss additive and the filter cake with another fluid to react with the filter cake and the fluid loss additive are not practical . For example, calcite is known as an excellent fluid loss additive, but calcite is not soluble in water, even at 150 ° C. Calcite has been used for years in the fluids of perforation to form the filtration cakes that subsequently be removed with acid. In addition, the amorphous PVOH solids are soft and deformed and have adhesive properties at high salinity and high temperature conditions, while the particles of many other materials conventionally used as fluid loss additives are hard. The deformation and tenacity of the PVOH makes it an even better fluid loss additive and filter cake forming agent. The use of ATVE and solid PVOH fluid systems is particularly suitable for high permeability formations. High permeability formations are defined herein as those having permeabilities of more than about 2 mD, especially more than about 10 mD, and especially those having more than about 20 mD. For example, in addition to the gravel filling, the hydraulic fracture followed by the gravel filling in a single operation, sometimes called fracture-filling (frac-pac, frac-pack, fracpac, frac pac, frac and pac, or StimPac, etc., mainly by its acronym in English), sometimes with a desbanded end deliberate to generate a short and wide fracture (in which the support agent forms a cementing at the end of the fracture far from the drill hole, stopping the lengthening of the fracture and resulting in a subsequent increase in the width of the fracture) is usually done in relatively high permeability formations in order to control the sands. However, such operations are some of those performed for other reasons, for example, to deflect the permeability damage near the drill hole, caused by inlays or to improve poor communication between the drill hole and the formation or a fracture previous, or in formations in which the perforation creates harmful fines and other reasons. Such operations designed to generate short and wide fractures can also be performed without the subsequent operation of gravel filling when sand control is not a problem. The methods of the present invention can be used in any of these cases (gravel filling, fracture followed by gravel filling and fracture operation to get short and wide fractures). The concentration of the PVOH can range from about 0.6 g / l (about 5 ppt) to about 9.6 g / l (about 80 ppt), preferably about 2.4 g / l (about 20 ppt). ppt) to about 7.2 g / l (about 60 ppt), but if the concentration is too low for the treatment to be performed, then the fluid loss may be too high. If the concentration is above 4.8 g / l (about 40 ppt), then in most formations there is little or no loss of fluid. A characteristic formulation of a PVOH-ATVE system suitable for hydraulic fracturing over a wide range of temperature and formation-permeability conditions contains about 4.8 g / l (about 40 ppt) to about 6 g / l (about 50 ppt) of PVOH. This composition has a salinity for the desired density, but should be above 6 weight percent salt, preferably at least 8 weight%, more preferably 12 weight%, up to a fluid density of 2.2 g / ml (18 Ib / gal). At salinities less than 6% by weight, the dissolution of some PVOH may occur. At salinities of 2% by weight or in fresh water, some PVOH can dissolve very quickly. A preferred viscoelastic surfactant fluid system, for example by fracture and gravel filling, contains about 1 to 10 (eg, about 5 to 6) percent by volume of BET-E-40 (see above) ) (which in the concentration as supplied may contain about 1% sodium polynaphthalene sulfonate). For fluid loss control pills, the concentration of ATVE can be much higher, for example, up to 50%, to avoid that the drilling fluids invade the deposit. However, any viscoelastic surfactant system that is chemically compatible with other components of the fluid, with other fluids in which it can come into contact and with formation can be used, and can be used at any concentration to which it provides adequate rheology for the intended use. In the gravel fill, or combination of fracture and gravel fill, it is within the scope of the invention to apply the fluids and methods to the treatments that they are made with or without a physical filter. Although we have described the invention with respect to 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 injector wells. Although we have described the invention in terms of the production of non-foaming fluids, gasified or energized fluids (for example, with nitrogen or carbon dioxide or mixtures of these gases) can be used. It would be necessary to adjust the appropriate concentrations due to any change in fluid properties or concentration of the suspending agent as a result of foaming. Any supporting agent (gravel) can be used, provided it is compatible with the PVOH, the formation, the fluid and the desired results of the treatment. Such support agents (gravels) may be natural or synthetic (include, but not limited to, glass beads, ceramic beads, sand and bauxite), coated or containing chemical components; more than one can be used in sequence or in mixtures of different sizes or different materials. The suspending agent may be coated resin, provided the resin and any other chemical component in the coating are compatible with the other chemical compounds of the invention, particularly the components of the viscoelastic surfactant fluid system. The supporting agents and gravels in the same or different wells or treatments may be of the same material or the same size, or both, as another, and the term "support agent" is intended to include gravel in this disclosure. In general, the support agent used will have an average particle size of approximately materials sized from 0.15 mm to about 2.39 mm (about 8 to about US 100 mesh), more particularly, but not limited to, , 25 to 0.43 mm (40/60 mesh), 0.43 to 0.84 mm (20/40 mesh), 0.84 to 1.19 mm (16/20), 0.84 to 1.68 mm (12/20 mesh) and 0.84 to 2.39 mm (8/20 mesh). Normally the suspending agent will be present in the suspension at a concentration of about 0.12 to about 3 kg / l, preferably about 0.12 to about of 1.44 kg / l (about 1 PPA to about 25 PPA, preferably from about 1 to about 12 PPA, PPA is "pounds of added support agent" per gallon of liquid) ). Also, optionally, the fracture fluid may contain materials designed to limit the counterflow of the suspending agent after completing the fracture operation by forming a porous filler in the fracture zone. Such materials may be any one known in the art, such as those available from Schlumberger under the trademark PropNET ™ (for example, see U.S. Patent No. 5,501,275). Examples of the support agent counterflow inhibitors include novoloid polymeric novoloid fibers or plates (U.S. Patent No. 5,782,300). As mentioned, dissolved PVOH is also a natural separation agent for viscosifying agents, especially for cross-linked boron, zirconate and titanate polymers and for ATVE systems, and this may be especially important at higher polymer loads. . Transport with the aid of fibers Suitable PVOH fibers can aid in transport, suspension and placement of the support agent in hydraulic fracturing and gravel filling, for example, and can then be dissolved to minimize or eliminate the presence of fibers in the filling. of suspending agent without releasing degraded products that will impede fluid flow, prematurely decreasing the ability of crosslinked polymers or ATVE systems with metal otherwise suitable for increasing the viscosity of the carrier fluid. As used herein, a system in which the appropriate PVOH fibers are used to the suspension and the transport support agent is referred to as a "fiber transport". Where the system also includes a viscosity-increasing fluid with an ATVE system or polymer cross-linked with suitable metal, it will be referred to as a "viscosity viscoelastic or polymer / fiber surfactant viscosifier system" or "FPV" system (for its acronym in English ). Such systems are have disclosed in the United States Patent Application No. 11 / 156,966 granted to the assignee of the present application. The FPV system is described here mainly in terms of hydraulic fracturing, but it is also suitable for gravel filling, hydraulic fracturing and gravel filling in a single operation (called, for example, fracture-filling, frac-pac, frac-pack, fracpac, frac pac, frac and pac (for its acronym in English), or StimPac or other names), which are also widely used to stimulate the production of hydrocarbons, water and other fluids from underground formations. These operations involve pumping a suspension of "suspending agent" (natural or synthetic materials that keep a fracture open after it is created) in a hydraulic fracture or gravel in gravel fill. In low permeability formations, the objective of hydraulic fracturing in general is to form fractures of high, extensive surface area that greatly increase the magnitude of the fluid flow path from the formation to the drill hole. In high permeability formations, the objective of hydraulic fracture treatment in general is to form a very conductive, wide and short fracture, to deflect the damage near the perforation hole created in the drilling or completion operation, to ensure good connectivity of fluid between the stratum and the drill hole and also to increase the available surface area for the fluids to flow into the drill hole. The FPV system is particularly suitable for fracturing compact gas wells, which are generally low permeability environments with extensive fracture closure times; in such cases the fracture can remain open for hours after the injection ceases, and the carrier fluid can separate and no longer suspend the support agent. The FPV system allows lower polymer or ATVE loads, reduced fracture height growth (due to the lower viscosity that can be used), reduced support agent settling and increased permeability retained (improved dimensionless fracture conductivity), all which result in improved production rates. The FPV system is also particularly suitable for gravel filling when dense brines are used that contain high concentrations of calcium or other ions that would precipitate with the degradation products of some degradable fibers (eg, up to 12,000 ppm calcium). Salinity in such systems can help delay the dissolution of the PVOH fibers because the PVOH is insoluble at high salinity conditions. FPV systems with PVOH fibers are also particularly suitable for situations in which the interstitial water that will flow into the fracture after treatment has a low salinity, will help to solubilize and remove the PVOH from the support or gravel filler. Some fibers previously used for transport, suspension and placement of the support agent, such as polyethylene terephthalate, can degrade into byproducts that can precipitate salts in the presence of excessive amounts of calcium or magnesium in the interstitial water. Accordingly preventive measures can be taken with other fibers, such as, but not limited to, pumping a pre-fill and pumping an acid or a chelating dissolving agent, adsorbing or absorbing a chelating agent on or into a filter , or the incorporation of precipitation inhibitors or metal purifying ions in the fluid that prevents precipitation. With the PVOH fibers of the FPV system, the classification of these cations in the interstitial water and the application of these preventive or correction measures are not necessary. Transport treatments with the help of PVOH fibers can also include water treatments with oil film (also called fracture water), with minimum suspending agent and a fluid viscosity, for example, of only about 3 cp), as opposed to conventional treatments with cross-linked polymer carrier fluids that generally have viscosities of at least 100 cp, and usually much plus. Treatments with PVOH fibers in the fluid can be improved if low concentration crosslinked polymer carrier fluids or ATVE fluids are used, for example, having a viscosity of at least about 50 cp, preferably at least about 75 cp (at 100 sec-1) at the temperature at which the fluid is used, especially in stiffer rocks commonly found in compact gas fields, in which the higher viscosity provides an increase of the width of the fracture. The FPV system with the PVOH fibers decouples the transport characteristics of the fluid support agent from the viscosity of the fluid. This allows a VES or very low polymer load to be used to obtain a support agent placement without sacrifice of the support agent coverage; this means less opportunity for undesirable height growth of the fracture and generates less fracture damage due to the polymer or crosslinked polymer. The viscosity needs to depend on factors such as the rigidity of the rock; the amount, identity, size and stiffness of the fibers; the pumping rate and its duration; and only to some extent the size, concentration and density of the support agent. The necessary viscosity can be determined by a mathematical model by experiments, such as those known as slot flow experiments, known in the industry. Oilfield service companies and evaluation contractors can make such determinations. If desired, the FPV system may optionally also include, in addition to the PVOH, other fibers that degrade to downhole conditions, such as, for example, lactide, glycolide, polylactic acid, polyglycolic acid, a polylactic acid copolymer and polyglycolic acid, a copolymer of glycolic acid with other hydroxy-containing parts, carboxylic acid or hydrocarboxylic acid, a copolymer of lactic acid with other hydroxy-containing parts, carboxylic acid or hydrocarboxylic acid, substituted or unsubstituted, and fibers described in the applications U.S. Patent No. 10 / 707,022 and 11 / 159,023, both assigned to the assignee of the present application; polymers of hydroxyacetic acid (glycolic acid) alone or with other hydroxy carboxylic acid or hydrocarboxylic acid-containing parts described in U.S. Patent Nos. 4,848,467; 4,957,165; and 4,986,355; fibers disclosed in the United States Patent Application Publication Nos. 2003/0134751 and 2004/0152601, both granted to the assignee of the present application. The preferred concentration of the PVOH fiber in the FPV configuration is 2.40 g / l (20 ppt) for the support agent loads from 0.12 to 0.36 kg / l (1 to 3 PPA); 3.59 g / L (30 ppt) for loads of 0.36 to 0.6 kg / l (3 to 5 PPA); and 4.80 g / l (40 ppt) for the loads on 0.6 kg / l (5 PPA). The concentrations of fibers generally increase according to the concentrations of suspending agent. With these concentrations of support agent, polymer and fibers, the stability of the fluid is sufficiently high and the settlement of the suspending agent is sufficiently slow to provide excellent fracture conductivity. Usually the fiber of the PVOH and any other fiber are mixed with a suspension of support agent in polymer fluid crosslinked in the same way with the same equipment as that used for the fibers used for the control of sands and for the prevention of counterflow of the support agent, for example, but not limited to, the method described in U.S. Patent No. 5,667,012. In the fracture, for the transport, suspension and placement of the support agent, the fibers are normally used with latent support or gravel fluids, not normally with fillers, washes or the like. EXAMPLES In the examples presented below, the following formulations of fluid, PVOH and other materials were used: AP # 1 fluid formulations - Concentrate surfactant: Chemical composition - - Propane-1 weight, 2-diol 13,4 Propan-2-ol 20,4 Water 5.1 ammonium chloride from (Z) -13 Docosenil-N-N-bis 61, 1 (2-hydroxyethyl) methyl AP # 2 - Salt Tolerant Fracture Fluid: Salt tolerant fracture fluid specially modified to be made with fresh water and to work with low concentrations of water and low concentrations of crosslinking agent. It contains 3 g / l (25 ppt) guar, 20 g / L (167 ppt) of potassium chloride, and 2.5 mL / L (2.5 gpt) of borate crosslinking agent. The borate crosslinking agent is a 85:15 mixture containing 85% of a 20-30% glycerol solution, 10-20% sodium tetraborate decahydrate and 60-70% water, and 15% of a solution of 30% aqueous sodium hydroxide. AP # 3 - surfactant concentrate concentrate: Chemical composition% by weight Urea 2-3 Propane-1, 2-diol 8 Isopropanol 11 -12 Ammonium nitrate 3 Water 29 Quaternary ammonium compound 10-30 Quaternary ammonium compound 10-30 Alkylaryl sulphonate 10-30 AP # 4 - concentrate of surfactant 0 // o in Chemical composition weight Isopropanol 21, 5-23,5 Sodium chloroacetate < 0.5 Sodium chloride 5.3 Water 31-33 Sodium polynaphthalenesulfonate salt 1-1.2 Amidopropyl dimethylBetaine erucic 37.6-39.4 AP # 5 - surfactant concentrate: Chemical composition% by weight Glycerol 1, 3-2,3 Propane-1,2, diol 14,8-16,5 Sodium chloride 3,6-4,1 Water 41, 5 -51 Oleoylamidopropylmethylbetaine 26.2-29.5 Sodium dodecylbenzenesulfonate 2.7 (2-methoxy, methylethoxy) -propanol (ether DPM glycol) AP # 6 - Concentrate of surfactant: Chemical composition% by weight Isopropanol 21, 5-23,5 Sodium chloroacetate < 0.5 Sodium Chloride < 6.1 Water 31-33 Amidopropyl dimethylBetaine erucic 38.6 AP # 7 - borate cross-linking fracture fluid - guar fluid fracture of borate-guar crosslinking composed of 2.4 grams of guar per liter, 20 grams of potassium chloride per liter, 0.5 ml of a 30-solution % by weight of sodium hydroxide per liter, and 1.25 ml / l of a crosslinking agent mixture prepared from 15 to 25% sodium tetraborate, 5 to 10% ethenyl benzene polymer with 2-methyl, 1,3-butadiene, and 70 to 80% hydrogenated light petroleum distillates.

AP # 8 - Borate Crosslinking Fracture Fluid - Guar Borate Crude Crosslinking Fracture Fluid Composed of 4.2 grams of guar per liter, 20 grams of potassium chloride per liter, 1.25 ml / liter a cross-linking agent mixture prepared from 15 to 25% sodium tetraborate, 5 to 10% ethenyl benzene polymer with 2-methyl, 1,3-butadiene, and 70 to 80% hydrogenated light petroleum distillates .

AP # 9 - linear guar fracture fluid: guar fluid containing 20 grams of potassium chloride per liter of water and guar polymer. For example, as shown in FIGS. 3, the concentration of guar polymer ranges from 0.6 g / l to 4.2 g / l (5 ppt to 35 ppt).

AP # 10 - salt tolerant fracture fluid: Salt tolerant fracture fluid specially designed to be processed with fresh water and to work with low concentrations of water and low concentrations of crosslinking agent. It contains 3 g / l (25 ppt) guar, 20 g / L (167 ppt) of potassium chloride, and 2.5 mL / L (2.5 gpt) of borate crosslinking agent. The borate crosslinking agent contains a solution of 20-30% glycerol, 10-20% sodium tetraborate decahydrate and 60-70% water. PVOH PVOH fibers were obtained with a solution activation temperature under the trademark KURALON K-ll (Kuraray). Amorphous PVOH solids were obtained under the trademark CELVOL from Celanese Chemicals. PVOH # 1 - KURARAY WN5 fibers (2.2 dTex or denier, 1.5 mm), dissolution temperature 50 ° C (122 ° F) PV0H # 2 - KURARAY WN8 fibers (2.2 dTex or denier, 1.5 mm), dissolution temperature 80 ° C (176 ° F) PVOH # 3 - KURARAY WN4 fibers (2.2 dTex or denier, 1.5 mm), 40 ° dissolution temperature C (104 ° F) PVOH # 4 - KURARAY WQ9 fibers (2.2 dTex or denier, 1.5 mm), dissolution temperature 95 ° C (203 ° F) PVOH # 5 - CELVOL 523S (87-89% hydrolyzed, medium molecular weight ) PVOH # 6 - CELVOL 502 (87-89% hydrolyzed, low molecular weight, granules) PVOH # 7 - CELVOL 205S (87-89% hydrolyzed, low / medium molecular weight, - granules) PVOH # 8 - CELVOL 513 (87-89% hydrolyzed, low / medium molecular weight, granules) PVOH # 9 - CELVOL 523 ( 87-89% hydrolyzed, medium molecular weight, granules) PVOH # 10 - CELVOL 418 (91-93% hydrolyzed, low / medium molecular weight, granules) PVOH # 11 - CELVOL 165 (99-100% hydrolysed, high molecular weight, granules) PVOH # 12 - CELVOL 203 (87-89% hydrolyzed, low / medium molecular weight, granules) Fluid loss control (ATVE fluid) - In an environment of high salt content, PVOH is in its sticky state and can be used for fluid loss control. Then, the salt concentration of the environment can be lowered to dissolve the PVOH and clean the surface of the formation or filter cake. Figure 1 presents the fluid loss data obtained using a Baroid HPHT fluid loss cell (high pressure, high temperature) with a head pressure of 3.45 MPa (500 psi), and a low permeability of 3.5 mD of the core, for 6 g / L PVOH # 5 (50 Ib PVOH / 1000 gal (ppt)) in 1% by weight of AP # 1 with 6% by weight of KCl, followed by a fluid exchange of 2% in KCl weight in deionized water. The test resulted in low fluid loss in the presence of 6% by weight of KCl. Then, in the descent of the salt concentration, the PVOH was dissolved, the flow was recovered through the core and increased fluid loss. The same fluid except that it did not contain PVOH basically has no control of fluid loss. Fluid loss control (ATVE-based fluid) - Figure 2 presents the fluid loss data made with an AP # 6 of 3% by weight containing 10% by weight KCl and 5 g / l (0.5 % or 41.5 lbs / 1000 gal) PVOH # 9 at 79 ° C (175 ° F). The permeability of the nucleus was 38 mD. The dissolution temperature of PVOH # 9 in water was 80 ° C (176 ° F). However, the high salt concentration prevented the PVOH from completely dissolving at 80 ° C (176 ° F). The fluid loss was 14.5 ml in 2.5 minutes with 6.9 MPa (1000 psi) head pressure after which the core remained clogged during the 30 minute test duration. Conductivity (Simulated fracture conditions, ATVE-based fluid and PVOH fibers) - Fracture conductivity tests were carried out to verify dissolution of PVOH fibers under simulated fracture conditions. Test with AP # 4 of 3% containing 5 g / L PVOH fibers (0.5%) cleaned at 507 Darcy at 116 ° C (240 ° F) with CarboHSP 20/40 mesh lift agent. This was compared to a "sand blank" at the same conditions with a measured permeability of 539 Darcy. As a result, the retained permeability of the fluid with the dissolved fibers was greater than 90%. Conductivity (Simulated fracture conditions, guar and PVOH fibers) - Conductivity tests of the fracture with guar demonstrated a comparable cleaning performance of fluids with crosslinked bonds with PVOH and linear gels. Figure 3 presents the data for the five linear guar fluids (marked with an "x") that varies in a concentration of guar polymer (see the formulation for AP # 9), and two fluids with cross-linked borate ( AP # 7 and AP # 8) containing 9.6 g / l (80 Ib per 1000 gallons) of PVOH # 2. These tests were carried out at 93 ° C (200 ° F), which is above the 80 ° C (176 ° F) dissolution temperature of the PVOH # 2 fibers in the water. The retained permeability for the guar polymer of 2.4 grams per liter of linear gel was 61% compared to 58% of the cross linked fluid (AP # 7) that contained the PVOH # 2 at the same polymer concentration. At a polymer concentration of 4.2 g / l, the permeability retained for the crosslinking system (AP # 8) with PVOH # 2 was 36% almost identical to 37% of the retained permeability of the linear gel. Conductivity (simulated fracture conditions, ATVE and PVOH fibers) - Figure 4 presents the conductivity data for PVOH # 2 at 1% AP # 1. The dissolution temperature of PVOH # 2 fibers in water is 80 ° C (176 ° F). Conductivity was reduced to 77 ° C (170 ° F) due to the sticky state of PVOH at this temperature. However, the conductivity improved in two temperature regimes: above 82 ° C (180 ° F) where the PVOH fibers dissolve completely, and below 71 ° C (160 ° F) where the fibers remained undissolved. The temperature range of the low conductivity between 71 to 82 ° C (160 to 180 ° F) was expected to move upward with the increase in fluid salinity. The introduction of a low salinity solution will dissolve the PVOH and simultaneously separate the crosslinking linkage from the polymer or ATVE carrier fluid, thereby increasing the conductivity of the support agent filler. Rheology (PVOH fiber separation agent, crosslinked polymer systems) - AP # 1 does not by itself form a filter cake, although polymeric fluids form filter cakes. PVOH is an excellent separation agent for fluids with crosslinked borate. The hydroxyl groups of PVOH appear to separate the boron ions from the crosslinked polymer, whereby the crosslinking of the polymer chains is eliminated and the viscosity is reduced to that of the linear guar solutions. Figure 5 shows rheology data from the evaluation of the different PVOH fibers and their separation effect on a borate crosslinked fracture fluid, AP # 2. Figure 6 shows the effect of PVOH # 1 fibers on the rheology of a cross-linked guar fluid (AP # 10). In this case the dissolution point of the PVOH fiber was 50 ° C (122 ° F). Below this critical temperature the fibers increased the viscosity of the fluid. Above this temperature the dissolved fiber reduced the viscosity of the fluid. The effect of PVOH on the crosslinked fluids of zirconate and titanate is similar. Rheology (pre-dissolved PVOH fiber separation agent, ATVE fluids) -The PVOH can also separate some ATVE fluids. The speed at which the PVOH separates the carrier fluid depends on the dissolution temperature and the degree of hydrolysis. Several grades of PVOH granules were evaluated with respect to their separation effect on AP # 1 and AP # 4. In these tests, the PVOH dissolved in the water before gelling with the ATVE additive. Figure 7 shows that all except one degree of PVOH reduced the viscosity of AP # 1 3% at room temperature and all grades caused AP # 1 to separate when the fluid was heated to 38 ° C (100 ° F). The effect of the different degrees of PVOH predisposed on AP # 4 is presented in Figure 8; most of the PVOH grades evaluated reduced the fluid viscosity by reaching 93 ° C (200 ° F). Rheology (PVOH granule / powder separation agent, ATVE fluids) - Rheology experiments were performed with AP # 6 3% as the carrier fluid in 10% KCl. The addition of PVOH # 9 granules and PVOH # 5 powder at concentrations of 5 g / l reduced the viscosity of AP # 6 at all temperatures evaluated. However, good suspension behavior was maintained. At low PVOH concentrations the ATVE fluid separation occurred independently of the PVOH form, ie, granules or powder, at temperatures slightly above 38 ° C (100 ° F), as shown in Figure 9. The observations visuals of the highest concentrations of PVOH in ATVE fluids show loss in viscosity at room temperature.

Fluid density (aqueous betaine surfactant agent gel) - the aqueous gel of betaine surfactants works well in water at densities up to 2.16 g / ml (18 Ib / gal) and the density can be easily adjusted. Four representative Fann50 viscosity measurements obtained for different concentrations of AP # 4 in water and different densities of brine were plotted in Figure 10.

Fluid rheology (transport and shear friction - aqueous betaine surfactant agent gel) - betaine fluids have a shear thinning profile, low plastic viscosity, high yield point, high viscosity at low shear and are not sensitive to Shear stress, as shown in figures 11 and 12 with AP # 4 6% in fresh water. These are the beneficial rheological characteristics of drilling fluids. Tolerance to contaminants (aqueous betaine surfactant agent gel) -some aqueous surfactant gels can lose viscosity quickly when contaminated with oil. Notwithstanding the betaine fluid, it may exhibit some compatibility with the oil. For example, AP # 4 7.5% and AP # 5 10% have viscosity comparable to 104 ° C (220 ° F). The rheological evaluation presented in Figure 134, however, shows that with the addition of 5% diesel, AP # 4 maintains approximately 80% of its viscosity while the AP # 5 characteristic surfactant fluid experiences a total loss of viscosity. The oil concentrations characteristic in the penetration fluids of the oil formations are around 2 to 3% by weight. FPV system with PVOH fibers and borate crosslinked guar - Example of a polymer system crosslinked with metal in the FPV system with PVOH fibers is a guar crosslinked with boron designed for delayed crosslinking and optimized for low guar concentrations. It is prepared, for example, with guar or a suspension of guar, boric acid, solid or concentrated sodium hydroxide, and sorbitol as a stabilizing / retarding agent; it may contain clay stabilizers such as potassium chloride or tetramethylammonium chloride, additional stabilizers such as sodium thiosulfate (usually obtained as a pentahydrate) and triethanolamine, bactericides, separating agents and separating aids. An example of this fluid was prepared, used for the example at temperatures below about 110 ° C (about 230 ° F), with about 2.16 g / l (18 ppt or pounds per thousand gallons) of guar; 2 1/1000 I (2 gpt) of a 50% tetramethylammonium chloride solution in water; 1 1/1000 I (1 gpt) of a non-emulsifying agent which contained about 30 to 50% of a mixture of alkoxylated polyols, resins, and hydrocarbon solvents in methanol, propan-2-ol and xylene; 2 1/1000 I (2 gpt) of a surfactant containing a mixture of about linear and branched alcohols C11 to C15 ethoxylated 15% in water, isopropanol, ethylene glycol monobutyl ether; 0.74 g / l (6.21 ppt) of boric acid; 1.74 g / l (14.52 ppt) of caustic soda; 2 L / 1000 L (2 gpt) of an 85% solution of triethanolamine in water; and 2 L / 1000 L (2 gpt) of a 48% solution of d-sorbitol (retarding agent) in water. The fluid optionally may also contain a conventional separation agent (in addition to the PVOH) such as, without limitation, ammonium persulfate or sodium bromate. This formulation was used, for example, at a guar concentration of about 1.92 g / l (about 16 ppt) to about 3.6 g / L (about 30 ppt), for example, concentrations up to about 2.88 g / L (about 24 ppt) with 1 to 2 1/1000 I (1 to 2 gpt) of the 50% solution of tetramethyl ammonium chloride in water; 0-1 L / 1000 L (0-1 gpt) of the surfactant described above; 1-2 L / 1000 L (1-2 gpt) of the non-emulsifying agent described above; 0.74 g / L (6.21 ppt) of boric acid; 1.74 g / L (14.52 ppt) caustic soda; 0-2 L / 1000 L (0-2 gpt) of an 85% solution of triethanolamine in water; and 1-3 L / 1000 L (1-3 gpt) of a 48% solution of d-sorbitol in water. A characteristic PVOH fiber concentration would be about 2.4 g / L (about 20 ppt) to about 4.8 g / L (about 40 ppt) of PVOH. FPV System with PVOH fibers and guar crosslinked with zirconate - Another example of a metal crosslinked polymer system is a guar of carboxymethylhydroxypropyl zirconium (CMHPG) which is a suitable example for temperatures ranging from around 79 ° C (close to 175 ° F) at about 121 ° C (about 250 ° F), particularly above around 110 ° C (about 230 ° F). This fluid was prepared from 2.64 g / L (about 22 ppt) of carboxymethylhydroxypropyl guar and about 20 g / L (167 ppt) of KCl; 4 L / 1000 L (4 gpt) of at 30% sodium thiosulfate solution in water (gel stabillizer); 0.1 L / 1000 L (0.1 gpt) of a 75% acetic acid and 14% propan-2-ol solution in water; and 0.52 L / 1000 L (0.52 gpt) of 23% solution of zirconium lactate (agent of crosslinking) in a methanol (14%) -water solution. This formulation is for the example used at a carboxymethylhydroxypropyl guar concentration of about 2.64 g / L (about 22 ppt) to about 3.6 g / L (about 30 ppt) with, for example, close to 20 to 50 g / L (about 167-417 ppt) of KCl; about 2-7 L / 1000 L (2-7 gpt) of a 30% solution of sodium thiosulfate in water; about 0.1 to 0.12 L / 1000 L (0.1 to 0.12 gpt) of a 75% solution of acetic acid and a 14% solution of propan-2-ol in water; and 0.45 to 0.65 L / 1000 L (0.45 to 0.65 gpt) of a 23% solution of zirconium lactate in a solution of methanol (14%) - water; preferably at about 3.00 g / L (about 25 ppt) with 20 g / L (167 ppt) of KCl; 4 L / 1000 L (4 gpt) of a 30% solution of sodium thiosulfate in water; 0.12 L / 1000 L (0.12 gpt) of a 75% acetic acid and 14% propan-2-ol solution in water; and 0.52 L / 1000 L (0.52 gpt) of 23% solution of zirconium lactate and a solution of methanol (14%) - water. A concentration of characteristic PVOH fiber would be 2.4 g / L (about 20 ppt) to about 4.8 g / L (about 40 ppt) of PVOH. FPV system with PVOH fibers and PVOH viscosifying agent - Solutions at 1% by weight and 10% by weight of PVOH in deionized water will be evaluated with respect to its use as a carrier with partial increase in viscosity in the FPV system, which could include PVOH fibers or other fibers. These solutions were mixed with solutions of 25, 30 and -40% by weight of CaCl2. The PVOH did not precipitate; however, the solutions produced bubbles and foam during agitation. It produced a dense foam, sim to a gel in the upper part of the mixture with 10% PVOH in 40% by weight of CaCl2 after settling for 5 days in a sealed container. At the same time the PVOH 10% by weight indicated by the manufacturer of the PVOH presented an incipient turbidity in 30% MgCl2, no precipitate was observed in said solution. This means that the PVOH solutions can be used as the viscous carrier fluid in a method of treating a perforation gap and a formation penetrated by the perforation comprising the step of injecting a suspension of fibers and suspending agent into the carrier fluid viscous, where the viscosity of the carrier fluid in the absence of fibers is insufficient to prevent sedimentation of the support agent during transport, and also where the fibers are degraded after treatment in products that do not precipitate in the presence of calcium or magnesium ions.

Claims (15)

1. CLAIMS: 1. A well treatment fluid is claimed, comprising: an aqueous fluid; a viscosifying system for the aqueous fluid; and at least partially crystalline polyol fibers soluble in fresh water above an activation temperature, and with a length of about 2 to about 25 mm and a denier of about 0.1 to about 20.
2. 2. A fluid Well treatment, comprising: a water-based fluid; a viscosifying system for the base fluid; a fluid loss control agent comprising finely divided particles of amorphous polyol dispersed in the base fluid, wherein the polyol is soluble in fresh water and insoluble in saline, and salinity to inhibit the dissolution of the polyol particles. The well treatment fluid of Claim 1 or Claim 2, wherein the polyol consists essentially of hydroxyl-substituted carbon atoms, in a polymer chain, separated from adjacent hydroxyl-substituted carbon atoms in at least one atom in the polymer chain, preferably wherein the polyol comprises polyvinyl alcohol made by at least partial hydrolysis of a precursor polyvinyl compound having ester substituents, more preferably wherein the polyol comprises a polymer having repeat units according to one of the following formulas: (Rl ") n- wherein R1 and R1 'may be the same or different alkyl, saturated or unsaturated, linear or branched chains having from 1 to 5 carbon atoms, and yn' may be the same or different integers from 1 to 5, and R2 is a hydrogen or an alkyl chain, saturated or unsaturated, aliphatic or aromatic, linear or branched having 1 to 12 carbon atoms 4. The well treatment fluid of any one of the preceding Claims wherein the pohol has an average molecular weight in weight greater than 5000 5. The well treatment fluid of any one of the preceding claims wherein the pohol is modified in hydrophobic form 6. A well treatment method, comprising injecting into a well a treatment fluid comprising insoluble polyol particles dispersed therein, wherein the polyol can be solubilized by heating, de-sanitation or a combination thereof, and consisting essentially of carbon atoms. carbon-substituted hydroxyl, in a polymepcha chain, separated from adjacent hydroxyl-substituted carbon atoms in at least one atom in the polymecha chain maintaining insoluble conditions for the pore particles during downhole placement, and a selected step of heating, misalignment and combinations thereof, to then substantially dissolve the polyol particles. The method of treatment of the well of Claim 6 wherein the treatment fluid has an effective salinity to inhibit the dissolution of the polyol at the temperature of the formation, and wherein the polyol is desalted in the dissolution stage 8. The Well treatment method of Claim 6 or 7, wherein the polyol solution is within a fluid with increased viscosity in an amount effective to separate a viscosifier in the fluid with viscosity increase. any one of Claims 6 to 8, wherein the pohol particles are, at least partially, as crystalline fibers soluble in fresh water above an activation temperature. The well treatment method of any one of Claims 6 to 9, wherein the treatment fluid during injection has a temperature below the activation temperature and the downhole placement is in a formation that is at a temperature above the activation temperature. 11. The well treatment method of any one of Claims 6 to 10, wherein the treatment fluid comprises a suspension of fibers and suspending agent in a viscous carrier fluid. The method of the well treatment of any one of Claims 6 to 10, wherein the polyol in the well treatment fluid comprises finely divided amorphous particles, the insoluble conditions comprise salinity, and the dissolution step comprises desalination. The method of treating the well of any one of Claims 6 to 12, wherein the injection comprises injecting the treatment fluid, optionally containing suspending agent, into a formation adjacent to the well at a pressure sufficient to create a fracture. in the formation, said fracture having opposite faces, and forming a filter cake comprising the particles on one face of the fracture. The method of the treatment of the well of Claim 13 wherein the carrier fluid comprises a saline solution in an amount effective to inhibit the solubility of the polyol above the dissolution temperature, and further comprises maintenance of the salt conditions to retard the dissolution of the polyol during the closure of the fracture. The method of the treatment of the well of Claim 13 or 14 wherein the injection of the treatment fluid is followed by a step selected from (1) injection of a fluid containing suspending agent having reduced salinity; (2) injection of a high-salinity support-containing fluid and subsequently a fluid without a suspending agent having reduced salinity; (3) injection of a fluid containing agent of reduced salinity; (3) injection of a fluid containing support agent, of high salinity and subsequently a fluid containing support agent, of low salinity.