MXPA96004869A

MXPA96004869A - Control of reflux of particles in wells subterran

Info

Publication number: MXPA96004869A
Application number: MXPA/A/1996/004869A
Authority: MX
Inventors: Card Roger; Constien Vernon; Feraud Jeanpierre; Howard Paul
Original assignee: Sofitech Nv
Priority date: 1996-03-08
Filing date: 1996-10-16
Publication date: 1998-07-03

Abstract

The present invention relates to an addition of fibrous mixtures in intimate mixtures with particulate materials to fracture and filter with gravel to decrease or eliminate the undesirable reflux of the support material or formation fines while stabilizing the sand pack and decreasing the demand for high polymer loads in the placement fluids. The fibers are useful to form a porous plug pack in the underground formation. In some cases, the channels or fingers of hollow spaces with reduced concentrations of the impelling material can be introduced inside the obturator package of the material of apo.

Description

"CONTROL OF REFLUX OF PARTICLES IN UNDERGROUND WELLS" FIELD OF THE INVENTION This invention relates to the recovery of hydrocarbons from underground wells. In this invention, there is provided a method, fluid sealing porous package and system for controlling the transport of particulate solids again from the sounding. The fibers can be pumped to the bottom of the well with a support material to form a porous package that serves to inhibit the flow of solid particles from the well, while still allowing the flow of hydrocarbons at reasonable rates. Other methods allow selective formation of voids or channels within the porous plug pack, which facilitate the production of the well while filtering undesirable materials that will not be admitted to the borehole.

BACKGROUND OF THE INVENTION The transport of solids is particles during the production of oil or other fluids from a sounding, it is a serious problem in an oilfield.

The problem arises because when extracting the oil from the underground, it is necessary to provide a flow path so that the oil allows the oil to reach the borehole. The oil is then produced allowing it to march upwards from the borehole to the surface of the land. Transported particulate solids sometimes plug the borehole, thus limiting or completely stopping oil production. These solids represent a significant wear factor in well production equipment, including pumps and seals used in the recovery and pumping process. The particles present in the pumped fluid sometimes cause excessive friction and greatly increase wear on the sensitive portions of the fluid handling and production equipment. Finally, these particulate solids must be separated from the oil to make the oil commercially useful, adding even more expense and effort to the processing of the oil. The reflux materials of undesirable particles that are transported in fluids flowing to the borehole are particularly pronounced in unconsolidated formations. By the term "undesirable" is meant that the reflux of the particle is undesirable. In some cases, the particles flowed back from the support or shoring agent, which is desirable when they are in place in the formation (their function for which they are intended) but it is not desirable if it flows out of the formation and up the sounding. When that happens, the particle of the support material becomes an undesirable contaminant because in that case it acts to reduce and not to increase the production of oil from the well, in an efficient manner. In general, unconsolidated formations are those that are less structured and, therefore, facilitate more the uninhibited flow of fine particles. Also, the particles are sometimes placed in the area near the borehole due to reasons that are not simply based on the natural flow to these areas. In some cases, the presence of particles is attributed to well treatments carried out by the well operator who place the particulate solids in the formation or near the borehole area. Examples of these treatments are fracturing and gravel filter. Numerous different methods have been tried in an effort to find a solution to the undesirable particle flow problem. What has been needed in the industry, is a material method or procedure that acts to limit or eliminate the reflux of the particulate materials placed within the formation in a fracturing process. Up to the time of this invention there was no satisfactory method to reduce or eliminate reflux. A method used in the past is a method of gradually releasing the fracturing pressure once the fracturing operation is completed so that the closing pressure of the rock fracture of the formation acting against the support material increases gradually. In this way, the method allows support of the matrix for stabilization before the reflow of the fracturing fluid and the production of the well works to bring significant amounts of the support material out of the fractures and back into the borehole. Another method that has been extended in some cases to help reduce the reflux of the particles is the use of the so-called "resin-coated support material", that is, the particulate support materials having an adherent coating attached to the surface. of the support material so that the particles of the support material are joined to one another. This process also reduces the magnitude of the backflow of the support material in some cases. However, there are significant limitations regarding the use of the resin-coated support material. For example, the resin-coated support material is significantly more expensive than the other support materials, which significantly limits its application to less economically viable wells. Fracking treatments can use thousands or even millions of kilograms of support material in a single well or a series of wells. In this way, the use of expensive resin coated support materials is generally limited by the economics of well operation to only certain types of wells or sometimes limited use in only the final stages of a fracturing treatment, sometimes known as the "tail" end of the fracturing work, or simply the "recessed" of the support material near the end of the pumping work. In unconsolidated formations, it is common to place a gravel filtration bed in the area near the borehole to present a physical barrier to the transport of the fines from the unconsolidated formation with the production of drilling fluids. Typically, these so-called "gravel filter operations" involve pumping and placing a quantity of gravel and / or sand having a mesh size of between the US Normal Sieve Series of 10 and 60 within the training unconsolidated, adjacent to the survey. Sometimes it is desirable to bond the gravel particles together to form a porous matrix for the passage of formation fluids, while facilitating outward filtration and retention in the well of the volume of the sand and / or unconsolidated fines transported. to the area next to the sounding by the formation fluids. The gravel particles may constitute a gravel coated with resin that is either pre-cured or can be cured by overwashing a chemical bonding agent once the gravel is in place. In some cases different bonding agents have been applied to the gravel particles to join them together, forming a porous matrix. Unfortunately, the gravel filter is a costly and elaborate procedure that should be avoided if possible. In addition, some probes are not stable and, therefore, can not be filtered with gravel. In addition, the gravel filter does not completely eliminate the production of fine particles, and it is preferred to avoid the production of particles without employing a gravel filter operation if possible. The gravel filter will not work in all cases. Another recurring problem in the pumping of the probing fluid is the enormous amounts of energy required to pump fluids containing high concentrations of the support material at high rates for relatively long periods of time. Large amounts of energy are required to overcome the considerable frictional forces between the thick suspension of the support material and the interior of the tubular unit through which the slurry is being pumped. Above a certain threshold pressure, the fluid / support material mixture can not be pumped due to the large frictional forces present at the liquid / tubular interface on the inner surface of the tubular or bore. The industry needs a viable solution to the problem of excessive friction during the pumping of the support material. further, the industry needs a fluid method that inhibits the production of particles, support material and fines, without detrimentally affecting the recovery of oil from the borehole.

COMPENDIUM OF THE INVENTION The present invention provides a method, porous fluid packaging and system for treating an underground formation. In one embodiment, it provides means for the formation of a solid porous package which inhibits the flow of both the deposited support material and the particles and fines of the natural formation again through probing with the production of formation fluids. In the practice of this invention, it is possible to construct a porous package within the formation comprising of fibers and a support material in intimate admixture. This porous packing filters unwanted particles, support material and fines, while also allowing the production of oil. In some cases, the porous packing can be selectively supplied with holes or finger projections, sometimes called "channels". These channels are positioned within the porous packing structure and serve to provide a permeable barrier that retards the reflux of the particles, but still allows the production of the oil at sufficiently high rates. It has been found that by using fibers to produce a porous packing of fibers and support material within the formation, the energy consumption of the equipment is also reduced, and it makes it possible to fracture some wells that are not economically justified for fracturing without the additional benefit of reduced friction pressure. It has been found that the pumping fibers if with support material provide significant reductions in friction forces that otherwise limit the pumping of the fluids containing the support material. In addition, many well treatments that were otherwise prohibitive in cost due to high energy requirements, or because the pump could not continue a sufficiently high regime to make the procedure justifiable, are now possible. Using the present invention, the ability of the fiber mixture to reduce friction, thus allowing for faster pumping regimes facilitates work optimization. A well treatment fluid is shown comprising a fluid suspension including a simultaneous mixing of a particulate material and a fibrous material. The fibrous material can be selected from a group consisting of natural and synthetic organic fibers, glass fibers, ceramic fibers, carbon fibers, inorganic fibers and metal fibers and mixtures of these fibers. In one aspect of the invention, a means for inhibiting the transport of particles in underground wells comprises a porous package that includes a particulate material having a size ranging in United States mesh from about 10 to about 100, in intimate admixture with a fibrous material. Therefore, an object of this invention is to provide a means and method by which the reflow of particulate materials either pumped or probed with a well treatment fluid or present as a result of the fines of a Unconsolidated formation is prevented or inhibited by the presence of fibers, in an intimate mixture with a particulate material. In addition, this reflux can be prevented by a porous packing, the porous packing formed by refluxing the well at a relatively high rate, or possibly a chemical medium. The channels can be formed in the porous packaging in order to selectively prohibit the production of undesirable particles, while still allowing the production of the reservoir fluids such as oil. This invention can also be used with support materials coated with no-fiber resins to form channels in these support materials after they are deposited in an underground formation. This is especially the case in situations for which the cost of resin-coated materials is not a significantly limiting economic factor. In some cases, the resin-coated materials can only be used as a recess at the end of the fracturing work, due to the relatively high cost of these resin materials. Still another object of this invention is to provide a means for controlling the reflux of the particulate material. in the production of underground fluid without the use of complicated and expensive resin formulations. In most cases, it is believed that the use of a porous package without resin-supported support materials is less expensive.

DESCRIPTION OF THE PREFERRED MODALITIES In the treatment of underground formations, it is common to place the particulate materials as a filter medium in the area close to the sounding, or sometimes in fractures that extend outward from the sounding. In fracturing operations, the support material led to fractures created when hydraulic pressure is applied to these underground rock formations in quantities such that fractures develop in the formation. The support material suspended in a viscous fracturing fluid is then removed and moved away from the sounding within the fractures (as invoices are created) and extended with continuous pumping. Ideally, during the release of the pumping pressure the support materials remain in the fractures retaining the separated rock faces in an open position, forming a channel for the flow of the fluids from the formation back to the sounding.

The reflow of the support material is the transport of the support sand back to the borehole with the production of the formation fluids after fracturing. This undesirable result causes several undesirable problems: (1) undue wear on the production equipment, (2) the need for the separation of the solids from the produced fluids and (3) also occasionally decreases the efficiency of the fracturing operation, since that the support material does not remain within the fracture and may limit the size of the flow channel created. At present, the main means for treating the back-flow problem of the support material is to employ resin-coated support materials, the consolidation of the resin of the support material or forced closing techniques. The cost of the resin-coated support material is high and, therefore, is used only as a recess in the last five percent to twenty percent of the placement of the support sand. The resin-coated backing material is not always effective since there is some difficulty in placing the same uniformly within the fractures and, in addition, the resin coating can have a detrimental effect on the fracture conductivity. The resin-coated support material also undesirably interacts chemically with common fracture fluid crosslinking systems, such as hydroxypropyl guar or guar with organometallic materials or borate. This interaction results in altered cross-linking and interruption times for fluids, thus affecting placement. In addition, these chemical substances can dissolve the coating on the resin-coated support material rendering their use ineffective. The difficulties of using resin-coated support materials are overcome in many cases by means of the present invention. By incorporating a quantity of fibrous material in intimate admixture with conventional support materials, it solves many problems. The fibers act to make a connection through the hole restrictions in the support material package and serve to stabilize the support material package with no effect or with minimal effect on the conductivity of the support material. Although this invention should not be limited by any theory of operation, it seems that the fibers are dispersed within the sand and, at the initiation of sand production from the fracture, the fibers are concentrated in a mat or other three-dimensional framework that it retains sand in its place, thus limiting the reflux of the additional support material with the production of fluid.

As used in this specification, the term "intimate mixture" will be understood to mean an essentially uniform dispersion of the components in a mixture. Similarly, the term "simultaneous mixing" will be understood to imply that the components of the mixture are combined in the initial stages of the process, that is, before pumping. The length, thickness, density and concentration of the fiber are important variables for the success of preventing backflow of the support material. According to the invention, the length of the fiber varies upwardly from about 2 millimeters, the diameter of the fiber varies from about 3 to about 200 microns. It seems that there is no upper limit on the length of the fibers used from the stabilization point of view. However, the practical limitations of handling, mixing and pumping equipment currently limit the practical use length of the fibers to approximately 100 millimeters. The fibrillated fibers can also be used in the diameters of the fibrils can be significantly smaller than the fiber diameters mentioned above. The fiber level used in the packing of the support material can vary from 0.01 percent to 50 percent by weight of the support sand. Most preferably, the fiber concentration ranges from 0.1 percent to 5.0 percent by weight of the support material. The modulus or rigidity of the fiber seems to be important to determine the operation. The module is a measure of the resistance to deformation of a material and is a material property instead of a phenomenon of the sample. Stiffness is a specific number of samples that depends on both the material and its dimensions. As a general rule, fibers with a modulus of approximately 70 GN / square meter or greater, are of course preferred. This includes materials similar to E glass fibers, S glass, AR glass, aramid boron and graphitized carbon. Organic polymers other than aramides usually have relatively lower modulus values. In order for organic polymers such as nylon to be useful in this application, larger diameter fibers are required to provide operation equivalent to that of glass E and more rigid materials. In the materials listed above, glass E is a class of commercially available glass fibers brought to the optimum for electrical applications, glass S is used for strength applications and glass AR has improved alkali resistance. These terms are common in the glass fiber industry and the compositions of these types of glass will be universally understood. A wide range of inventions are useful. The length and diameter have been discussed above. An elongation (length to diameter ratio) in excess of 300 is preferred. The fiber can have a variety of shapes ranging from simple, round or oval cross-sectional areas to complex cross-sectional areas of trilóbulo, figure-eight, star-shaped, rectangular, or the like. Most commonly, straight fibers are used. Curved, curled, spiral-shaped and other three-dimensional fiber geometries are useful. Likewise, the fibers can be hooked at one or both ends. They may be of a composite structure, for example, a fiberglass coated with resin to increase fiber adhesion with fiber. The materials from which the fibers are formed is not a key variable as long as the fibers do not interact chemically with the components of the well treatment fluids and are stable in an underground environment. Therefore, the fibers can be glass, ceramic, carbon, natural or synthetic polymers or metal filaments. Mixtures of these fibers can also be used advantageously. Glass, carbon and synthetic polymers are preferred due to their low cost and relative chemical stability. The density of the fibers used is preferably greater than one gram per cubic centimeter to avoid separation by flotation in the suspensions, fluid weight / particles. Preferably, the density of the fiber is within the range of 1 to 4 grams per cubic centimeter, closely simulating the density of the particulate materials used. Glass fibers are particularly preferred because of their relatively low cost, easy availability and high rigidity. Due to the fact that the placing fluids and fluids of the underground formation tend to have an alkaline pH, it is especially preferred to use an alkali resistant glass (hereinafter referred to as AR glass) having a high zirconium content. The use of commercially available more common silica glasses is possible within the scope of this invention, but, the solubility of these glasses in an alkaline medium, particularly at elevated temperatures, may affect the long-stroke stability of the fiber / material mixture. of support through its duration in the survey. Carbon fibers are preferred for use under harsher conditions. That is, under conditions in which the duration of the glass fibers in the formation is limited. This may include wells with bottomhole temperatures of approximately 150 ° C, steam injection wells, wells in formations where the water with cream is not saturated with silica (such as limestone formations), wells that could be expected that they are treated with acid, particularly hydrofluoric acid sometimes after the mixture of the support material / fiber is put in place and wells that involve environments of a high or low or corrosive pH. Preferably, the carbon fibers should preferably be at least partially graphitized, preferably more than 90 percent graphitized and more preferably more than 95 percent graphitized. The fibers can be comprised of pitch, polyacrylonitrile fibers, or novolac fibers by processes known to those familiar with the art. Examples of commercially available carbon fibers that are useful in this process include, but are not limited to, Donacarbo-S or Donacarbo-S S-335 from Donac Company, Ltd, T-125T carbon fibers from Kreha Corp. of America , Dialead Carbon Fibers from Mitsubishi Kasei Corp. and Panex carbon fibers from Zoltek Corporation. A number of different support materials may be used in this invention. Sand and synthetic sized inorganic support materials are more common. Examples include 40/60 sized sand, 20/40 sized sand, 16/20 sized sand, 12/20 sized sand, 8/12 sized sand, and similarly mentioned ceramic support materials, such as "CARBOLITE ™" support materials. The support material can be sand coated with resin or a ceramic support material. Resin-coated sand is used in some cases as a substitute for more expensive ceramic support materials because both are said to be more resistant to crushing than sand. The addition of fibers would help control the reflux of the support material or serve other purposes as described herein. The combination of sand and fibers coated with resin would provide a more resistant package than any system alone. This can be useful by itself. In addition, the fibers could allow the use of highly pre-cured resin-coated backing materials thereby minimizing the deleterious interaction of the curable resin-coated backing material with typical fracturing fluid components.

The practice for the execution of the preferred work is to mix the fibrous material throughout the batch of support material to be pumped during the work. This can be achieved by adding the fiber to the support material before it is mixed with the fluid, adding the fiber to the fluid before it is mixed with the support material or adding a thick suspension of fibers at some other stage, preferably before. of the thick suspension being pumped to the bottom of the well. In certain cases, it is preferred to pump the slurry of the support material and fibers, only during a portion of the work, for example, the last 10 percent to 25 percent of the support material within the fracture as an "embedment" for control reflux in the most economical way and due to other reasons. The plug could be pumped to other stages, for example, to provide an absorbed flake inhibitor to be pumped to the front of the fracture. In certain cases, it may be desirable to pump small plugs from the thick suspension of the support material and the fiber between the plugs of the thick suspension of the support material or to pump small plugs from a thick suspension of fiber between the plugs of the coarse suspension of the support material. This could conceivably be used to control the downward flow dynamics of the fracture, for example, by providing behavior more similar to the flow of a plug or stopper. The pumping of small plugs of thick fiber suspension as the embedded is an example of this general procedure. The thick suspension of a mixture of the support material and the fibers is useful due to several reasons within the entire range of application and deposit from fracturing to sand control. This includes especially the latest fracturing and sand pack technologies and a high permeability stimulus. In these applications the permeabilities of the formation are typically higher than those for the classical fracturing that extends up to the scale of lOmd to 2 Darcia. As a result, the fractures are shorter (eg, from 3.05 to 60.96 meters) and wider (eg, from 3.81 to 5.08 centimeters) than the classic fractures. The control of the backflow of the support material in these types of jobs can reduce or eliminate the need for expensive hardware, such as gravel packing screens in the hole to simplify the work design. The selection of fiber can be based on chemical as well as physical reasons. For example, in the gravel filter and related applications where it is anticipated that the packaging at its resulting site will be treated with mixtures of acid containing hydrofluoric acid, carbon fibers will be preferred in relation to the glass fibers when a prolonged duration of the fibers. In addition, these treatments can provide channels in the porous package which serve to facilitate the filtering action of the packing of the support material as will be described further below. The opposite may also be desirable. The use of carbon fibers through the first 90 percent or so of the work followed by glass fibers in the flush would result in a packing that could be treated with hydrofluoric acid solutions to absorb the glass, allow the reflux of a small portion of the sand in the face of the fracture and improve well productivity. Pumping alternative plugs of thick suspensions of the support material / fiber containing the different fibers, could be followed by acid treatment to produce a fracture with high permeability zones (where the glass fibers were) but with packing zones of the Stable support material / fiber (where the carbon fibers were) to keep the fracture open. In addition, in some cases, the acid treatment may provide channels or voids in the porous packaging. These voids are regions where the support material is removed from the porous packaging. The treatment of the porous packaging can sometimes result in the formation of one or more "finger" projections through the porous packing. Beyond the advantages to avoid backflow of support material, additional advantages have been observed in the use of fibrous materials in the well treatment fluid. First, the presence of fibers the presence of fibers has been advantageously found to reduce the friction found by the fluid in the tubular, thus economizing energy and making it possible to pump jobs that would otherwise not be economical. This will be described in more detail below. The presence of fibers in the fluid also slows the rate of sedimentation of the solid materials in the fluid, thereby allowing the use of smaller amounts of the polymeric gelling material in the placement fluid. This feature offers the advantages of lower cost, greater retained permeability, a need for lower breaker concentrations and to avoid chemical interaction with the components of the treatment fluid.

The fluid loss properties of the fibers can also be obtained when the fibers are incorporated into a fracturing fluid carrying the support material. In areas of high fluid loss, the fibers without the sand will concentrate on a mat, the loss of additional fluid in these areas. The fibers also offer an opportunity to place the well treatment chemicals in a dispersed form within the packing of the support material. In this way, porous or dissolvable or hollow fibers can be filled or formed with different materials such as polymer breaks, scale inhibitors and / or paraffin inhibitors and asphaltene that can be released slowly into the package. The materials from which the fibers are formed are not a key variable as long as any chemical interaction between the fibers and the components of the well treatment fluids does not dramatically decrease the ability of the fibers to carry out the desired function. In some cases, the desired function may actually require chemical interaction with well treatment fluids. The exact mechanism of greatly reduced friction can be achieved while pumping the fibers and the support material in relation to the practice of this invention, is not able to be easily determined. However, without limiting this invention it is in no way believed that the support material during pumping in a fluid within a tubular, usually tends to align along the center of the tubular and in fact tends to provide a flow of destabilized fluid causing higher friction forces. When pumped with sufficient amounts of fibers, however, the mixture of the support material / fiber exhibits reduced friction, apparently because the mixture stabilizes the support material through a larger cross-sectional area of the pipe, in instead of just * along the center of the pipe. This results in the formation of a thin lubricant water layer on the surface of the tube wall, facilitating a decreased friction pressure. The fibers can be used to design complex flow channels in the packing of the support material. For example, a fracturing job can be modeled in such a way that the gaps or channels (sometimes called "fingers") of the support material flow out of the packing of the backing material after the gasket is formed at the bottom of the well , resulting in the creation of open channels that allow well fluids to flow into the well without considerable restriction. Of course, the packing of the support fluid still provides an effective barrier to the particles to the support material or fines that would otherwise flood the survey. . These fingers can vary in lengths from approximately 2.54 centimeters to several meters or even longer. They can be created in a number of ways. For example, the well can be reflowed at a rate sufficient to create channels without loss of most of the packing of the support material. A fiberglass supporting material package using glass fibers can be treated with slurry acid (an aqueous solution of hydrochloric acid and hydrofluoric acid) under matrix conditions to dissolve the glass fibers within the porous packaging in patterns similar to fingers. This can be achieved at treatment pressures less than that required to cure the formation. When the well is allowed to flow, the support material will be produced again from those areas similar to fingers that no longer contain any fibers. This type of process or others results in the selective creation of a package at its site where the package contains a series of concentrations of fiber mixtures / support material. For example, most of the fracture must be packed or sealed with a packing of support material that contains, for example, 1.5 weight percent of fibers as a total fiber / support material mixture. During the final recess at the completion of the fracturing work (such as during the last 1 percent to 15 percent of the total support material placed in the well) the amount of fibers could be decreased in such a way that a lower level could be used of concentration of fibers, e.g., 1 percent of fibers. In general, the stability of the package to flow decreases with the decreased concentration of the fiber. In other words, the more fibers there are, the more resistant the packaging will generally be. Using this invention, the area closest to the sounding could develop open fingers while the rest of the packaging remains stable. In another example, most of the packaging could consist of a packing of carbon fiber backing material and the embedment could consist of a packing of support material and glass fibers. In that case, treatment with sludge acid or another solution containing hydrofluoric acid or solvent could dissolve certain of the glass fibers and produce fingers in that area that would not spread to areas containing carbon fibers (because they do not carbon is believed to be soluble in hydrofluoric acid).

In a similar manner, channels may be created in the porous packages of the support material and fiber coated with resins or under certain conditions even without fibers. The acid treatment can remove the resin coating on the resin-coated support material after it is in place in the formation. In that case, it is possible to decrease the resistance to flow of that portion of the package, allowing it to destabilize and leave the package, thus allowing the fingers to form. In the presence of fibers, acid treatment can be provided shortly after fracturing. With support materials coated with resin, the acid treatment would occur only after the resin-coated support material has been allowed to cure properly. The use of acid-resistant fibers, such as carbon, also allows the formations to be treated with acids after the fiber / support material packaging is in place. In that case, the acid treatments would not tend to dissolve the glass fibers in a matter of minutes to hours. The use of fibers can reduce costs compared, for example, with the use of resin-coated backing materials because the use of the fibers does not require prolonged cure times as is usually necessary in applications using a coated backing material In addition, the fibers can be advantageously used where the multi-zone formations with low bottomhole temperatures require a prolonged paralysis in time between the fracturing of each formation in order to allow the coated backing material to cure. resin. The long healing times associated with these formations can be greatly avoided by using fibers so that no downtime is required and several zones can be fractured in a single day. In this case, the cost economy will vary depending on the number of zones that will fracture, and the times of the required paralysis. In some cases this will result in the ability to fracture a well in a day instead of over a period of about a week. This is a considerable reduction and reduces the cost and reduces the downtime for the well, which is expensive in terms of loss of production. Using the resin-coated support material could be achieved by paralyzing the well for healing followed by a pumping of viscous fluid having a mobility ratio in the bottomhole conditions of at least 50/1 greater than the following fluid that it would be injected at a lower amount than the fraturation regimes. This fluid could be constituted of gelled brines, but it could also be a gelled oil. After the viscous fluid, a solution of regular mud acid containing a mutual solvent such as a mud acid of U66 brand (it is believed that U66 is a registered trademark) or of butyl acetate could be applied in a concentration of about 10% by weight. hundred. This fluid could be allowed to flow into the fluid to lend viscosity so that it would react with and remove the viscous consolidation resin within the channel or finger. The standstill time could be based on the type of resin used for consolidation. It is anticipated that some resin systems would be more favorable than others for this application. The well would then be produced at a rate that would produce the new unconsolidated support material outside the created channels. This cleaning process could be helped in some cases in low pressure wells by injecting nitrogen or carbon dioxide and pumping the well again quickly to create conductive channels or fingers. In certain applications, the fibrous material need not be made of fibers but could be platelet type materials that increase the cohesion of the support material in place. These platelet materials can increase the cohesion of the support material and minimize the amount of back-flow of support material when the well is produced. Platelets could be used in the complete process of fracturing work or as a recessed. In an applicationThe platelet materials could be mixed with gravel at a certain vertical level, where the gravel is used for sand control. The platelets in this case would prevent the gravel placed to the outside of the well reflow with the fluids produced eliminating the need for a sieve in the sounding. Platelets can be comprised of a wide variety of materials, including metal discs or chips, polymers, ceramics, glass or other naturally occurring materials. Preferably, the approximate size of the platelets would be greater than 0.6 millimeter in the largest dimension. The fluids to be used as the transport medium for the suspension of the fluid are not believed to be a critical factor in the practice of the invention. In general, common fluids such as water-based fluids and oil-based or petroleum-based fluids (foamed or non-foamed) can be used. The preferred fluid will vary depending on the specific requirements of each well. The following examples will illustrate various formulations incorporating the fibers. It will be understood that the presentation of these examples is solely for purposes of illustration of the invention and should not be construed in any way as limiting the scope or applicability of the concept of the present invention.

EXAMPLE 1 (OF CONTROL): The leakage regime of a guar fracturing fluid crosslinked with borates was determined as follows: A synthetic seawater fracturing fluid containing 3.59 grams / liter of a polymer slurry, 3.785 liters / 3, was prepared, 785 liters of a surfactant, 1,893 liters / 3, 785 liters of a bactericide and 0.938 liters / 3, 785 liters of an antifoaming agent. Approximately 2000 milliliters of this fluid was crosslinked with a borate crosslinking agent, emptied into a large baroid cell, heated at 93 ° C for 30 minutes. Using a pressure of 70.30 kilograms per square centimeter, a fluid escape test was carried out with a limestone core of 2.54 centimeters that has a low permeability (0.5 milidarcios). The results are presented in Table A.

EXAMPLES 2 TO 5: In a similar manner to Example 1, the behavior of the fiber / fracture fluid mixtures was determined. All tests were carried out identically to Example 1 but included 2.0 grams of glass fibers (1.27 centimeters long and 16 microns in diameter) that were added to the fluid before crosslinking. Other modifications of Example 1 were as follows: EXAMPLE 2 contains 3.59 grams per liter of a slurry of a polymer.

EXAMPLE 3 contains 2.30 grams per liter of a polymer slurry.

EXAMPLE 4 was prepared using tap water at 2 percent KCl, 3.59 grams per liter of the polymer slurry, 3,785 liters per 3.785 liters of surfactant 1,893 liters per 3.785 liters of bactericide and .947 liters per 3.785 liters of the antifoaming agent. No crosslinking agent was added to the system.

EXAMPLE 5 is identical to Example 3 but a limestone core having a permeability of 100 millidarces was used.

The data are presented in Table A. These data show that the fibers dramatically reduce the escape or leakage regime under fracturing conditions.

TABLE A: EXHAUST OR LEAK VOLUMES AS A TIME FUNCTION EJ. 1 EJ. 2 EJ. 3 EJ. 4 EJ. 5 1 min. 0.4 mi 0.3 mi 0.6 mi 0.8 mi 6.6 mi 4 min. 1.2 mi 0.6 mi 0.9 mi 1.0 mi 7.6 mi 9 min. 2.1 mi 0.6 mi 1.1 mi 1.7 mi 8.2 mi 16 min. 2.9 mi 0.6 mi 1.1 mi 2.2 mi 8.8 mi min. 3.6 mi 0.6 mi 1.4 mi 2.7 mi 9.4 mi 36 min. 4.4 mi 0.6 mi 1.5 mi 3.1 thousand 10.1 mi EXAMPLE 6: (CONTROL) The exhaust regime of the particle carrier fluid was measured. The fluid contained tap water and 9.59 grams per liter of hydroxyethylcellulose. The particulate material was a calcium carbonate sized (from 1 to 500 microns) that was added at a concentration of .060 gram per liter of fluid. Approximately 250 milliliters of this fluid was mixed and added to a large baroid fluid loss cell heated at 77 ° C. After 15 minutes, a nitrogen pressure of 35.15 kilograms per square centimeter was applied to force the fluid against a limestone core of 2.54 centimeters having a permeability of 250 milidarcios. The results are presented in Table B.

EXAMPLES: 7 to 10 The tests were repeated using glass fibers only and in combination with the calcium carbonate particulate material. The charge of particles remained constant at .060 grams per liter of the fluid. The fibers were added to the fluid at the time of the addition of calcium carbonate. The fiber was added as a function of the weight percentage of the initial calcium carbonate material.

EXAMPLE 6: 100% Calcium Carbonate: 0% Fiber EXAMPLE 7. 99% Calcium Carbonate; 1% Fiber EXAMPLE 8: 95% Calcium Carbonate; 5% Fiber EXAMPLE 9: 90% Calcium Carbonate; 10% Fiber EXAMPLE 10: 0% Calcium Carbonate; 100% Fiber TABLE B EXHAUST VOLUMES AS A TIME FUNCTION TIME EJ. 6 EJ. 7 EJ. 8 EJ. 9 EJ. 10 0 0 0 0 0 0 1 minute 110 87 76 171 30-1 / 2 4 minutes 117 90 79 174 31 9 minutes 118 93 81 175 31-1 / 2 16 minutes 119 94 83 176 37 minutes 118 94 83 176 37 36 minutes 118 94 83 176 38 Example 10 (single fibers) showed no migration to the core. The particulate systems (Example 6) always show some migration towards the nucleus. The data demonstrates superior exhaust control by the fibers. An additional advantage of the fibers is that there is no migration to the particles towards the gravel packing or to the formation, therefore, there is less damage. The following examples illustrate the ability of fibrillated fibers to stabilize the support material packaging: EXAMPLE 11: (CONTROL): 200 grams of 20/40 mesh sand in 105 milliliters of an aqueous guar solution was emptied into a 25 mm diameter glass column equipped with a valve in the bottom. Packing permeability was 380 darci. The sand flowed quickly through a 3.18 mm diameter valve when it opened.

EXAMPLE 12: Similarly, Example 11 was repeated but 2 grams of the fibrillated polyacrylonitrile fiber were mixed with the same slurry before it was emptied into the column. Packing permeability was 120 darcia. The packing did not flow out when the valve was opened. It was also stable when the valve had been completely removed leaving a 6.35 mm diameter hole directly below the sand packing. This illustrates the ability of fibrillated fibers to consolidate a sand package.

EXAMPLE 13: The Fibers stabilize the Sand Packing: a non-reticulated guar solution of 3.59 grams per liter was elaborated. The composition of this fluid was the same as in Example 1. Fifty milliliters of this fluid was mixed with 0.8 gram of glass fibers 12 millimeters long and 16 microns in diameter. They were mixed with a Hamilton Beach agitator at low speed for 15 seconds. 100 grams of the 20/40 support sand were added to the mixture and mixed by hand in a closed vial of 112 milliliter capacity by light agitation. The resulting mixture was emptied into a vertical glass column 12 millimeters in diameter in a "T" section at the bottom. The left end of the "T" had a sieve installed and the far right did not have it. First, water was flowed down the column and out of the left side of the "T" to clean the sand / fiber guar and produce a packing. The permeability of the package was then measured. It was 278 darcios.

Then, the water flowed from left to right through the "T". This washed the sand and fiber from the "T" shaped section. The sand / fiber packing in the section in the column remained stable. The direction of the water then changed to flow down the column and off the right side of the "T". This created a pressure drop through the sand / fiber packing and no screen prevented the sand from moving with the flow. The pressure drop was increased (increasing the flow rate) until the sand / fiber packing failed and flowed out of the vertical section of the column. The pressure drop across the sand / fiber packing required to do this was in excess of 275 kPa. Almost no amount of the sand in the sand / fiber packing flowed out of the vertical section of the column until the sandbag "failed".

EXAMPLE 14: 3.59 grams per liter of the non-crosslinked guar solution was mixed with the support sand (50 milliliter solution with 100 grams of sand) following the same procedure as in Example 13, but WITHOUT the fiber. This mixture was placed in the column and the guar was cleaned from the sand packing in the same manner as in Example 13. The permeability of the sand packing was 250 darcia. Sand packing failed under a low pressure that was not able to be measured. These Examples (13 and 14) illustrate that the mixing of the fibers with the support sand caused the formation of a stable packing in the column. The fibers retained the sand in place against a much greater force (pressure) than sand without the fibers. Likewise, the fibers had a negligible effect on the permeability of the sand packing.

EXAMPLE 15: Nylon fibers: 50 milliliters of 3.59 grams per liter of the guar solution were mixed with 0.2 gram of nylon polyamide fibers 20 millimeters long, and 64 microns in diameter. Mixing was carried out in a manner similar to that of Example 13. This mixture was emptied into the column and tested as described in Example 13. The permeability of the sand / fiber package was 200 darcia. The sand / fiber packing failed at a reduced pressure through the 265 kPa package.

EXAMPLE 16: Stabilization of Sand Packing with High Viscosity Fluids: 1 gram of glass fibers 32 millimeters long and 16 microns in diameter was mixed with a solution of corn syrup and water having a viscosity of 600 centipoise. Mixing was carried out on a Hamilton Beach shaker at low speed for 10 seconds. Then, 100 grams of the support sand 20/40 were mixed with the fiber and the solution. The mixture was emptied into the column described in Example 13. In this case, the 600 centipoise corn syrup solution was flowed through the column. The permeability of the sand / fiber packing was 352 darcios. The pressure drop across the sand / fiber packing was increased with the outflow direction on the right side of the "T" (without screen). The pressure drop through the sand packing was raised to 400 kPa without packing failure. This example illustrates that the fibers cause the sand packing to be stable even with high viscosity fluids flowing therethrough. High viscosity fluids flowing through the sand would occur if a guar gel was refluxed through the fracture during cleaning.

EXAMPLE 17: Sedimentation: a reticulated guar / borate gel was made in the amount of 3.59 grams per liter. The composition was that of the guar solution in Example 13. Glass fibers 12 millimeters long and 16 microns in diameter (0.8 weight percent sand) and a 20/40 support sand were added to an amount of gel in such a way that the concentration of the sand was 1.80 grams per liter of the gel. The sand in the fiber was added to the guar solution before the solution of the gel crosslinking agent. The fiber was added to the solution and dispersed with a Hamilton Beach mixer. This was added to the sand in a closed jar and briefly mixed by shaking. The composition of the crosslinking agent solution was 0.3 gram of boric acid, 0.6 gram of sodium hydroxide, 1.2 grams of sodium gluconate, 0.5 milliliter of triethanolamine and 0.6 gram of sodium thiosulfate for 500 milliliters of the guar solution. . The resulting mixture was placed in a heated closed column and mixed further by inverting the column once for one minute. The mixture was heated to 66 degrees centigrade and the column oriented in a vertical position. The mixture was run to the bottom of the column. The settling or sedimentation of sand and fiber in guar gel was observed as a function of time at 66 degrees Celsius. The settlement percentage was calculated as follows: settlement percentage = 100 X (total height - height of the sand) / maximum liquid height The total height is the height of the sand plus the liquid of the gel. The height of the sand is the height of the top of the sand layer.

The maximum liquid height was determined with sand and water in the same amounts. After 315 minutes the sedimentation for sand and fiber was 17 percent. There was no tendency for sand or fibers to phase-separate during sedimentation.

EXAMPLE 18: The experiment of Example 17 was repeated with 1.3 percent of the glass fiber based on the weight of the sand. In this case, after 260 minutes the sedimentation was 14 percent.

EXAMPLE 19: The sand only in the fluid of Example 17 was set at 60 percent in 300 minutes. By comparison with Examples 17 and 18, this example shows that the glass fibers reduce the sedimentation rate of the sand in the gel.

EXAMPLE 20: Interaction with Borate Gel: Six liters of the non-crosslinked guar solution of 3.59 grams per liter were mixed with 47.6 grams of glass fibers 12 millimeters long, 16 microns in diameter. The fiber level was based on a sand load of 960 grams per liter. No sand was added to the fiber / solution mixture. The fiber / solution mixture was allowed to stand for about half an hour after mixing. Two samples of 50 milliliters were removed. The fibers were filtered from one of the 50 milliliter samples. The Fann 35 viscosity of each sample was measured at 21 ° C. The sample with the fibers had viscosity of 51 and 30 centipoise at a rate of 170 to 510 seconds-! respectively. The filtered sample had viscosities of 42 and 24 centipoise, respectively. The viscosities of the filtered sample were within the specifications for this guar solution. The solution with fibers had a slightly higher viscosity. A solution of the borate crosslinking agent (composition in Example 17) was then added to both solutions. The time to gelation was measured for both, by "hanging edge" methods. The filtered solution had a "hanging edge" time of 4 minutes, 44 seconds. The sample with fiber had a "hanging edge" time of 4 minutes, 27 seconds. Both of these crosslinking time periods are within the specifications for these guar gels. This example illustrates that the preferred glass fibers do not affect the viscosity and "hanging edge" gelation times of borate cross-linked guar gel. This illustrates that the glass fibers do not significantly affect the chemistry or viscosity of the guar gel.

EXAMPLE 21: Interaction With Zirconate Gel: The same procedure was followed to mix as in Example 20 with a hydroxypropyl guar solution of 5.99 grams per liter. The 12 mm glass fibers were added and then filtered from an aliquot of the solution. This aliquot and another aliquot that had not been exposed to the fibers were crosslinked in a zircon solution of .539 grams per liter. The solution was 40 percent of the zirconium crosslinking agent, 24 percent of a high temperature stabilizer and 36 percent water. The pendant crosslink times were 9:19 minutes for the sample not exposed to the fibers and 10:13 minutes for the sample exposed to the fibers. Again, the fibers do not affect the chemistry of the cross-linked gel.

EXAMPLE 22: Conductivity: the conductivity test was carried out with a 20/40 mesh support agent. The fluid was 3.59 grams per liter of the non-crosslinked guar solution. The composition was 17 milliliters of 2 percent KC1 water, 0.12 milliliter of a thickened guar slurry, 0.02 milliliter of a fluorocarbon surfactant and 0.005 milliliter of a defoamer. The fluid was mixed with 63 grams of the preservative agent. support 20/40.

The test was carried out in a conductivity cell to 121 ° C and a closing effort of 351.50 kilograms per square centimeter. The conductivity after 23 hours of reflux was 157 darci. The test was repeated with the same amounts of fluid and support agent. In addition, 0.5 gram (0.8 percent) of glass fibers with a diameter of 16 microns and 12 millimeters in length were mixed with the flow agent and fluid. The conductivity after 24 hours of reflux was 153 darci. This example illustrates that the fibers have a negligible effect on the permeability of the support agent package.

EXAMPLE 23: Slot Flow. The stability of the fiber / sand package was tested in a groove geometry. 5 liters of 3.59 grams per liter of a non-crosslinked guar solution (34 milliliters of the guar slurry, 5 milliliters of the surfactant and 1.25 milliliters of the defoaming agent and 5000 milliliters of tap water) were drawn. This was mixed by recirculating the fluid through a holding tank and a centrifugal pump for 15 minutes. Then 5000 grams of the 20/40 sand were added and allowed to disperse for about 1 minute. 50 grams of the glass fiber 12 millimeters long and 16 microns in diameter were added to the mixture. The resulting slurry was pumped into the slot. The slot is approximately 1.68 meters long, of 6.35 millimeters wide and 15.24 centimeters high. The surfaces were smooth with the front surface being clear to allow observation. A screen was placed above the exit hole so that the sand did not flow out of the slot. The slurry was pumped into the slot from the other end. In this geometry a pack of sand and fibers accumulated against the screen while the fluid was allowed to flow through the screen into the holding tank. A 15.24 cm long sand / fiber package was built against the screen. The fluid was saved then washed with water from the package. The sieve was removed from the end of the slot leaving the package with an open face of 6.35 millimeters by 15.24 centimeters. The water was flowed through the package to test its concentration. The flow of water was increased to a pressure drop of .422 kilogram per square centimeter supported by the package. At this point, the package began to fail and sand flowed out of the slot.

EXAMPLE 24: Slow Flow Glass Fibers, Rough Walls: The same slurry was tested again on the groove geometry as in Example 23. In this example, the walls of the groove were roughened. This was accomplished by adhering a 20/40 sand layer to the groove walls with rubber cement. in this geometry a sand / fiber package was obtained 55. 88 centimeters and the concentration of the package exceeded a reduction of 1.05 kilograms per square centimeter (upper limit on the pump).

EXAMPLE 25: Slot with Gas Flow: A thick slurry similar to that used in this example was used in Example 23. In this example, we use 1.20 grams per liter of guar solution. This slurry was pumped into the rough-walled slot and screen as described in Example 24. The guar solution was washed with a pack of sand / fiber with water. Then the package was dried with air flowing through it for 3-1 / 2 hours. The sieve was removed and the test for the resistance of the package was carried out. The length of the package was 45.72 centimeters. The air flow rate was increased to an aspiration of .914 kilogram per square centimeter through the package. The package did not fail. The package was then further dried at a low air flow rate for two additional hours. The test was repeated. The sand / fiber package did not fail with the flow up to an aspiration of .773 kilogram per square centimeter through the package. This example illustrates that the sand / fiber package is resistant to gas flows as well as water flows.

EXAMPLE 26: 1.27 cm Aramid Fiber Slot Flow: "KEVLAR ™" polyaramide fibers were tested in the groove geometry with rough walls. The fluid was at a rate of 2.40 grams per liter of a non-crosslinked guar solution similar to that of Example 23. The aramid fibers were 12 millimeters long and 12 microns in diameter. The mixture of the slurry was 4 liters of fluid, 4 kilograms of sand of 20/40 support material and 12 grams of "KEVLAR" fiber (0.3 weight percent sand). The slurry of sand / fiber was pumped into the rough-walled slot with the screen at one end as described in Examples 23 and 24. The resulting sand pack was 36.83 centimeters long. The fluid was washed from the sand fiber bundle with water. The sieve was removed and the water was again flowed through the package. The package began to fail at an aspiration of .211 kilogram per square centimeter.

EXAMPLE 27: Slot Flow, 2.54 cm Nylon Fibers: We tested the nylon fibers of 2.54 centimeters long in the rough wall slot. The fibers were 64 microns in diameter. The slurry was 5 liters of a non-crosslinked guar solution of 3.59 grams per liter, 5 kilograms of sand from the 20/40 support material and 15 grams of nylon fibers. The length of the sand / fiber package was 15.24 centimeters. The package began to fail at an aspiration of less than .0703 kilogram per square centimeter.

Examples 23 to 27 illustrate that the fibers stabilize a package of the support material in a fracturing geometry even with smooth walls and without closing force.

EXAMPLE 28: Groove Flow: The strength of the sand and fiber package was tested. A non-crosslinked guar solution of 3.59 grams per liter was used with the same composition as in Example 23 except with 2 percent water of KC1. The 20/40 support material was added to the fluid at a rate of 1440 grams per liter. Glass fibers 12 millimeters long and 16 microns in diameter were also added to 1 percent of the level of the support material. The slurry was loaded in a 13.34 cm slot by 13.34 centimeters by 6.35 mm. The walls of the slot were lined with stone Limestone Springwall. The effort during the closing of 17.58 milligrams per square centimeter was applied. The cell was heated to a temperature of 99 ° C. the fluid was raised with the gel with a 1 percent solution of KCL flowing at a slow rate (50 milliliters per minute). The brine was then washed from the cell with a flow of saturated nitrogen gas. The cell was then heated to 107 ° C. The test was not carried out with the flow of nitrogen to an increased suction through the package. The package was stable at 1.41 kilograms per square centimeter / .305 meter with a closing effort that varied from 7.03 to 14.06 kilograms per square centimeter.

EXAMPLE 29: Slit Flow, WITHOUT FIBERS: The same experiment as in Example 28 was carried out with the support material without fibers. At a closing effort of 17.58 milligrams per square centimeter, a 6.35 millimeter groove, 107 ° C, the support material package failed to less than .014 kilogram per square centimeter / .305 meter. These examples demonstrate the ability of the fibers to stabilize a package of support material under representative bottomhole conditions.

EXAMPLE 30: Patio shape: the glass fibers were tested in a patio test. Glass fibers 12 millimeters long, 16 microns in diameter were added at a level of 1 percent to the sand in a simulated fracturing job. The fibers were added by hand in the fracturing fluid mixer with the support fluid of 20/40. This mixture was combined with 3.59 grams per liter of a cross-linked fracturing fluid in the mixer. Then it was flowed through a triple pump, a tree economizer, an obstruction coil with suction of 70.30 kilograms per square centimeter and 274.2 meters of a 7.62 centimeter pipe. The pumping program was: 1 ppg of the support material at 6 barrels per minute 1.5 ppg of the support material at 6 barrels per minute ppg of the support material at 6 barrels per minute ppg of the support material at 8 barrels per minute ppg del support material at 8 barrels per minute Samples were taken from the mixture at the outlet of the pipeline. The glass fibers were well mixed with the support material and the fluid even when some breakage of the fibers was evident. The example demonstrates that fiber / sand slurries can be pumped with conventional pumping equipment and that the fibers are stable enough to survive this treatment.

EXAMPLE 31: Drilling Packaging: the ability of the fibers to keep sand in a reservoir through a 6.35 millimeter perforation was tested. A drilling model of 6.35 millimeters in diameter and 7.63 centimeters in length with a deposit of 1229 cubic centimeters at the exit was used for the tests. The tank to be equipped with a 20 mesh screen on the other side from the drilling. The thick suspension could then flow into the reservoir through the perforation and out through the screen. A 4.5 liter solution of 2.40 grams per liter of hydroxyethylcellulose (HEC), a solution (135 grams of NH4CI (3 weight percent), 28.3 milliliters of a HEC solution and dry caustic soda was prepared to raise the pH to 8 ). This was mixed by recirculating the fluid through a holding tank and a centrifugal pump. The fluid was hydrated for approximately 30 minutes. 13.5 grams of Aramid cut of 1.27 centimeters long were mixed and 2,696.5 grams of sand of 20/40 were added to the mixture. (6.00 grams per liter of the support material, 0.5 percent by weight of fiber based on the support material).

The resulting slurry was pumped into the reservoir through a 6.35 millimeter perforation. The pack of sand and fibers accumulated against the screen, while the fluid was allowed to flow through the screen into the holding tank. After packing the perforation, the lines, the holding tank and the pump were cleaned and filled with water. The direction of flow was reversed and water was pumped from the side of the screen through the packed perforation. No support material was produced through the 6.35 mm hole even increasing the flow rate until a pressure drop across the package of 1.05 kilograms per square centimeter was reached and held for several minutes. The water flow was disconnected and connected several times. This also did not produce sand.

EXAMPLE 32: The same perforation was packed with 20/40 sand and glass fibers 12 millimeters long and 16 microns in diameter using a non-reticulated guar solution of 3.59 grams per liter. 4.5 liters of fluid were prepared (90 grams of KCl (2 weight percent), 4.5 liters of a surfactant, 1125 milliliters of a defoaming agent, 30.6 milliliters of the guar slurry) and hydrated for 30 minutes. 27 grams of glass fibers were added and after one minute 2700 grams of the 20/40 support material (600 grams per liter, 1 weight percent fiber based on the support material). The packing and the water flow were carried out as in Example 31. The packed perforation was maintained for 10 days. Within this period of time, the water was flowed through it approximately 5 times and each time connecting and disconnecting the pump several times. The packing was stable and produced at most one teaspoon of the support material.

EXAMPLE 33: The same installation as in Example 31 with the exception of a perforation of 1.27 centimeters. This time, polypropylene fibers (1.27 centimeters long, 4 denier) and 3.59 grams per liter of HEC were used. Fuido: 4.5 liters, 135 grams of NH4CI, 42.5 milliliters of the HEC solution, caustic soda to raise the pH up to 8. Support Agent: 2,696.5 grams of sand of 20/40 (.599 grams per liter). Fiber: 27 grams of polypropylene, 1.27 centimeters long, 4 denier (1 percent by weight based on the support material). Packing and flowing water through the above worked well, no sand production was found yet through the 1.27 centimeter hole.

Examples 31 to 33 illustrate that different types of fibers can be used to hold the sand in place in the formation beyond the perforation tunnels. This applies to gravel filtration, where the gravel is placed outside the perforations to stabilize the sands of the underground formation.

EXAMPLE 34: Stabilization of Different Types of Support Material: column experiments were carried out using the fluid composition (3.59 grams per liter of guar solution) and the procedure as in Example 13. Aliquots of 50 milliliters of fluid were mixed with 100 grams of each of the different support materials and 1 gram (or 1.6 grams) of each of the glass fibers 12 millimeters long and 16 microns in diameter. The support materials were CARBOLITE ™ "20/40 sand coated with the" ACFRAC SB ULTRA ™ "curable resin of 20/40," ISOPACK ™ "light weight gravel of 20/40, the" CARBOLITE "support material had The "SB ULTRA" had approximately the same density and sphericity as the sand, but it has a polymer coating.The "ISOPAC" which is the light weight gravel is much less dense than sand and is more spherical, and has a polymer coating.The results of the column tests are shown in Table C.

TABLE C. Resistances of the Different Fiberglass Seal Packing / Support Material Fiber Level CARBOLITE SB ULTRA ISOPAC St.% Sand 1 percent > 225 kPa > 250 kPa 55 kPa 1. 6 percent > 250 kPa > 250 kPa Examples 13 and 34 illustrate that the coating and sphericity of the backing material do not affect the ability of the fiber to reinforce the sealant pack. Low density support materials ("ISOPAC") may require higher amounts of fiber for the strength of the sealing gasket.

EXAMPLE 35: The procedure of Example 31 was repeated with the exception that the sealant was manufactured in such a way that half of the drilling pattern closest to the drill hole was filled with an identical sand / fiber mixture while half from the back of the hole was filled with sand. The sealing pack was tested in the same way. No sand was produced.

Example 35 demonstrates that the thick suspension of the support material / fiber can be used as a recess during the final stages of the process, or can be pumped in stages between the plugs of the thick suspension of the support material EXAMPLE 36: Strength tests of the sealant packing of the support / fiber material were carried out on a rectangular cell with internal dimensions of 12.7 centimeters long, 3.8 centimeters and 2.5 centimeters thick. The cell was open at both ends. A perforation-type geometry was installed in the cell, creating a restriction of 0.63 cm in all internal dimensions. The cell was equipped with a screen at the exit. A slurry containing 500 milliliters of guar solution of 3.59 grams per liter in water (composition in Example 1), 500 grams or sand of 20/40 and water (the composition in Example 1), 500 grams of sand from 20/40, and 1.25 grams of carbon fiber of 7 microns per 0.63 cm was pumped into the cell and a pack was formed against the outlet screen. The guar was washed from the package and then the sieve was removed from the exit hole. A closing effort of 35.15 kilograms per square centimeter was applied to the face of the sealing pack. Water was flowed from the entrance to the exit through the length of the package. The sealing package of the support material and carbon fiber withstood the flow of water up to 35 kPa (pressure before the package failed and flowed through the restriction.

EXAMPLE 37: The same test as the previous one was carried out with 5 grams of AR quality glass fibers (diameter of 20 microns, 1.27 centimeters long) were added to the slurry of sand and carbon fiber. The resulting packing was maintained at an aspiration of 135 kPa without failure.

EXAMPLE 38: The same test as the previous one was carried out with a thick suspension of 500 milliliters of 3.59 grams per liter of the guar solution, 500 grams of sand of 20/40, and 5 grams of AR-quality glass fibers. (20 microns in diameter, 1.27 centimeters long). The packet failed to an aspiration of 36 kPa.

EXAMPLE 39: The same test as the previous one was carried out with a thick suspension of 500 milliliters of the guar solution of 3.59 grams per liter, and 50 grams of the 20/40 sand without added fiber. The seal packet failed immediately upon initiation of water flow and no pressure drop capable of measuring was maintained through the packing.

EXAMPLES 36 to 39 show that the carbon fibers can be used to stabilize the sealing package and that the glass fibers can result in stronger sealing packages than a single type of fiber.

EXAMPLE 40: Strength tests of the fiber packet and support material were carried out in a disk-shaped cell. The disc diameter is 15.2 centimeters, and the thickness is 1.2 +/- 0.05 cm, and the cell has 10.2 cm inlet and outlet openings through it. A screen was placed through the outlet. The slurry contained 1000 milliliters of the 5.99 gram guar solution per liter, 1000 grams of the support material, 15 grams of the AR glass fibers (diameter 20 microns, 12.7 millimeters long) which was pumped into the cell and formed a shutter pack against the screen. In each test, the size of the support material was varied. The guar was washed from the packet shutter and then the sieve was removed. The closing effort of 70.30 kilograms per square centimeter was applied to the faces of the disk. The excess of the package was cleaned from the cell so that the package was perpendicular to the direction of flow from the inlet and outlet. This resulted in an 11.4 cm inlet to outlet plug pack length. Water was then flowed through the package until it failed and until the support material flowed out of the cell. This coincided with the relaxation of the closing effort.

SUPPORT MATERIAL SHOCK PACK RESISTANCE 20/40 60 kPa 12/20 21 kPa 16/30 21 kPa The same procedure as in Example 40 was followed with the exception that it did not add fiber to the 20/40 sand packet. The packet failed to initiate water flow and no pressure aspiration was maintained. The results show that the fibers will reinforce the different sizes of the support material.

EXAMPLE 41: 500 milliliters of a 5.99 gram borate cross-linked guar gel per liter were prepared. The gel contained 3 grams of guar, 10 grams of potassium chloride, 0.5 milliliter of surfactant, 0.25 milliliter of bactericide, 0.125 milliliter of antifoam agent, 0.5 milliliter of stabilizer (iron control), 0.6 gram of an oxygen scavenger, 0.6 gram of boric acid, 1.5 grams of sodium hydroxide and 3 grams of sodium gluconate. 500 grams of United States 20/40 mesh sand and 7.5 grams of AR-grade glass fiber (diameter 20 microns, 12.7 milliliters in length) were mixed in the gel. The resulting slurry was emptied into a metal tube with an internal diameter of 22.1 millimeters and 127 millimeters in length. The ends of the tube were capped, and then heated to 150 ° C for 24 hours. These conditions were sufficient to "disintegrate" the gel. The tube was cooled, opened and fitted to a washer with a 12.7 mm hole in one end of the tube. The tube was connected to the water source in such a way that the washer was at the outlet end of the tube. Effectively the mixture of the slurry was retained against slipping out of the tube by the washer, but the water could flow through the pack of slurry in thick suspension. The flow of water was started at a low flow rate to wash the disintegrated gel from the sand packet. No sand flowed out of the tube with the water. The rate of water flow was then increased. Sand did not flow until the flow rate reached 7.6 liters per minute corresponding to an aspiration of 381 kPa through the sealant package. At this point, the sand packet failed and ran out of the pipe through the washer.

EXAMPLE 42: The same experiment as the previous one was carried out with the cross-linked gel and the sand, but without the AR glass fibers. The sand pack flowed out of the tube through the washer at a very low flow rate during cleaning of the disintegrated gel from the pack.

EXAMPLE 43: This example shows that the use of fibers can reduce the treatment pressures. During a fracturing treatment in South Texas, the concentration of 20/40 ceramic support material was changed from 0 to .908 to 1.82 to 2.72 to 3.63 kilograms of the added support material (ppa) per 3,785 liters of fluid. Shortly after the initiation of the 8 ppa stage, the treatment pressure increased from 407.74 kilograms per square centimeter to more than 527.25 kilograms per square centimeter. Then, 1.5 percent fiber was added to the slurry. The treatment pressure quickly decreased again to 407.74 kilograms per square centimeter. After some time had elapsed, the addition of fibers was stopped. The pressure of treatment immediately began to increase. When the pressure reached 456.95 kilograms per square centimeter, the addition of fibers was resumed, this time to 1 weight percent of the support material. The treatment pressures again decreased to 386.65 kilograms per square centimeter. This example demonstrates the use of fibers to reduce the treatment pressure during a fracturing treatment.

EXAMPLE 44: Fibers were used to provide rapid wellbore clearance reducing treatment costs. Typical wells in the shale formations in Indiana contain several productive zones. The creation of a large bill to cover all areas in a particular well is not a viable solution. In the previous practice it had involved the fracturing of each zone using a support material coated with resin. At the end of each treatment the well was closed for 12 to 20 hours to allow the resin-coated support material to cure. The well then allowed to flow for 30 minutes and the next area then fractured. In this way, approximately one week is required at the site to fracture four zones in a well. With the use of fiber at 1.5 percent by weight of the support material during the last stage of each treatment, the fractured zone can be stirred within ten minutes and then the next zone fractures. That second zone is then produced for approximately 30 minutes and then the next (third) zone can be fractured and so on. In this way, four zones were fractured in a single well in less than 8 hours at the site. This resulted in savings of 3 to 4 days of equipment time at the site that would otherwise be required while waiting for the resin-coated support materials to cure, followed by subsequent drilling of the backing material cured in the probe. In most cases, several days are required at the site for a mechanical injection head and a drill to pierce the backing material coated with cured resin. This can reduce costs by several thousand pesos per well. This example illustrates the use of fibers to allow rapid wellbore removal thus reducing the treatment costs of multi-zone wells.

EXAMPLE 45: Creating fingers or channels in a porous plug pack can dramatically increase the productivity of a well compared to normal fracturing processes. A plexiglass cell was constructed that contains a cavity of 22.86 centimeters by 9.84 centimeters by 3.81 centimeters. The cell was equipped with a slurry of a guar solution of 5.99 grams per liter containing 16/20 sand and 1.5 percent glass fiber by weight sand by pumping the slurry through the metal tube through the cell and against the sieve at the opposite end. Water was then pumped through the packing or sealing pack of the support material / fiber in the same direction to remove the residual guar. Air was then pumped through the cell in the same direction to displace most of the water. An aqueous glycerol solution having a viscosity of 300 centipoise was then pumped through the screen into the package and out of the open tube. The flow rate was increased to 50 milliliters per minute without failure of the sealing package. This is roughly equivalent to a flow rate of about one-half of a barrel per day of high viscosity fluid per borehole. As the flow rate increases, a finger or channel begins to form in the plug pack. At a rate of 380 milliliters per minute, the channel is approximately 1.27 centimeters in diameter and extends through the length of the cell. The flow rate can be increased to more than 1550 milliliters per minute without additional changes in the packet shutter. This example illustrates the very high flow regime that can be handled by this channel. This is a way to dramatically increase the productivity of a well compared to normal fracturing practices.

EXAMPLE 46: After a conventional fracturing treatment using a 15% resin-coated backing based on the total volume of the pumped support material, the well is closed for a sufficient period of time to cure the support material coated with resin. The viscous fluid is then pumped to the bottom of the well at less than the nal fracture pressure. The viscous fluid may be gelled brine or gelled oil. The viscosity of this fluid is at least 50 times greater than that of the following fluid. The following fluid is a conventional slurry acid containing a mutual solvent such as butyl acetate. This fluid will be introduced into the anterior fluid in the sealant pack of the resin-coated support material by dissolving the coating and allowing the backing material to be produced again from these fingers once the well has been stirred. This reduces well productivity as in the example immediately preceding this example.

EXAMPLE 47: This example is basically the same as in Example 46 with the exception that the embedding of the resin-coated support material is further stabilized by the addition of 1.5 weight percent fibers of the resin-coated support material. In this case, no stopping time is needed and the acid can be pumped immediately after the viscous fracturing fluid. Or if desired, the acid treatment may be after the processing described in Example 46 above. In any case, channels of high productivity are created in the shutter package.

EXAMPLE 48: The use of fibers can allow the optimization of the reflux regimes to maximize the removal of the polymer from the fracture and thus increase the productivity of a well. In South Texas, for example, fractures using the resin-coated support material should be reflowed at relatively slow rates, typically less than 250 barrels of water per day. Otherwise, a catastrophic failure of the resin-coated backing pack may occur. At this slow rate only a very limited amount of the fracturing fluid and the associated polymer residues can be recovered before the gas leaves and begins to be produced from the formation. Once the gas production begins, the rate of return of the water decreases and the polymer remaining in the fracture can be baked on the surfaces of the support material clogging the flow channels and reducing the productivity of the well. In a well in South Texas, for example, the backflow of a work with resin-coated support material was monitored. The gas came out after approximately 22 hours. At this stage, less than 10 percent of the volume of fracturing fluid had been recovered and less than 10 percent of the polymer that had been pumped during the work had been returned to the surface. Less than 15 percent of the total polymer pumped had returned to the surface after 50 hours of total reflux time. In contrast, a well was fractured using fibers to control the reflux of the control support material in this same formation. The water return regime was increased to more than 2000 barrels of water per day without failure of the sealing package. The gas came out only after 8 hours but by that time it had already recovered more than 15 percent of the polymer pumped. After 50 hours, 25 percent of the polymer pumped during the fracture treatment had been returned to the surface. This is almost twice the cleaning efficiency of the fracturing treatments with the resin-coated support material. In adjacent information, polymer return rates in excess of fifty percent have been recovered after 50 hours of reflux time. This example illustrates the use of fibers that can allow the optimization of flow rates to maximize the removal of the polymer from the fracture and thus increase the productivity of the well. The invention has been described in more limited aspects of the preferred embodiments thereof, including numerous examples. Other modalities have been suggested and still others will occur to those skilled in the art when reading and understanding this specification. It is intended that all these modalities be included within the scope of this invention.

Claims

CLAIMS;

1. A method for treating an underground formation penetrated by a sounding using a fluid suspension comprising the steps of: (a) providing a fluid suspension, the suspension consisting of a fluid, a particulate material and a solid material, the solid material it is selected from the group of solid materials consisting of metal, polymers, ceramics and glass; (b) pumping the fluid suspension to the bottom of the well through a sounding; (c) deposit the fluid suspension in the formation; (d) re-flowing the fluid from the formation, thereby forming a matrix of solid material of particulate material; and (e) reduce the migration of particulate material from the matrix to the survey.

2. A method for treating an underground formation penetrated by a sounding using a fluid suspension comprising the steps of: (a) providing a fluid suspension, the suspension consisting of a fluid, a particulate material and chips of the polymeric material; (b) pumping the fluid suspension to the bottom of the well through the borehole; (c) deposit the fluid suspension in the formation; (d) re-flowing the fluid from the formation, thereby forming a chip matrix of the solid polymeric material and the particulate material; and (e) reduce the migration of particulate material from the matrix to the sounding.

3. The method for treating an underground formation penetrated by a sounding, using a fluid suspension comprising the steps of: (a) providing a fluid suspension, the suspension comprising a fluid, a support material and solid particles, the particles solid are selected from the group of particles consisting of metal, polymers, ceramics and glass; (b) pumping the fluid suspension through a borehole to the bottom of the well; (c) deposit the fluid suspension in the formation; (d) flowing the fluid back from the formation, thereby forming a solid particle matrix and the support material; and (e) reduce the migration of support material from the matrix to the survey.

4. A method for treating an underground formation penetrated by a sounding using a fluid suspension, comprising the steps of: (a) providing a fluid suspension, the suspension comprising a fluid, a particulate material and particles of the polymeric material. (b) pumping the fluid suspension to the bottom of the well through the borehole; (c) deposit the fluid suspension in the formation; (d) flowing the fluid back from the formation, thereby forming a matrix of particles of polymeric material and a particulate material; and (e) reduce the migration of particulate material from the matrix to the borehole.

5. A method to reduce the production of support material from a well after fracturing an underground formation penetrated by the well, which comprises: (a) pumping a fluid from the surface of the ground through the well and into the underground formation, the fluid comprises a viscous liquid, a support material and chips or discs of the polymeric material, (b) forming a matrix within the underground formation, the matrix comprises the support material and the polymer material in close association with one another , and (c) reduce the production of support material from the well.

6. A method for inhibiting the reflux of the support agent from an underground formation to a low power consumption survey comprising the steps of: (a) providing a fluid suspension comprising a mixture of a support agent and fibers; (b) pumping the fluid suspension including a mixture of the support agent and the fibers through the sounding using reduced amounts of energy; and (c) depositing the mixture of the support agent and the fibers in the underground formation.

7. A method for treating an underground formation penetrated by a sounding using a suspension, comprising the steps of: (a) providing a suspension, the suspension comprising a fluid, a particulate material and solid chips of the material; (b) pumping the suspension to the bottom of the well through a sounding to the formation; (c) deposit the suspension in the formation; (d) passing the formation fluid back through; (e) forming a porous plug pack comprising the solid chips of material, and the particulate material, further wherein a channel is formed in the porous plug pack; and (f) wherein the channel is formed using an acid to remove the solid chips of material from the porous plug pack.

8. A fluid for the treatment of an underground formation comprising a viscous liquid consisting of a gelled oil, a gelled aqueous fluid, aqueous polymer solutions, aqueous surfactant solutions, viscous emulsions of water and oil or petroleum and the mixture of any of these fluids with a gas, wherein the fluid has an intimate mixture of a particulate material and a fibrous material suspended therein.

9. The fluid according to claim 8, wherein the particulate material has a size ranging from US mesh of 10 to 100 and is selected from a group consisting of sand, resin-coated sand, a material of support coated with resin, ceramic beads, synthetic organic beads, glass microspheres and sintered minerals. The fluid according to claim 8, wherein the fibrous material is selected from a group consisting of glass fibers, inorganic fibers, synthetic organic fibers, natural organic fibers, ceramic fibers, carbon fibers and metal filaments.; further wherein the fibers and the particulate material can be assembled in a matrix, and the fibers and the particulate material are selectively removable by chemical or physical means to facilitate the formation of channels or voids within the matrix. 11. In an underground formation penetrated by a sounding, a porous plug pack comprising a particulate material in an intimate mixture with the fibrous material; wherein the particulate material is a fracture support material that is selected from a group consisting of sand, resin-coated sand, a resin-coated support material, ceramic beads, glass microspheres, synthetic organic beads, a support material coated with resin and sintered minerals; the fibrous material is selected from a group consisting of natural organic fibers, synthetic organic fibers, glass fibers, carbon fibers, ceramic fibers, inorganic fibers, metal fibers and mixtures thereof, wherein the sealing package is placed adjacent to the sounding; further, wherein the voids or channels are formed within the porous plug pack, the voids or channels comprising regions of reduced particle concentration. 12. A fluid for the treatment of an underground formation comprising a viscous liquid consisting of a gelled oil or petroleum, a gelled aqueous fluid, aqueous polymeric solutions, aqueous surfactant solutions, viscous solutions of water and petroleum and mixtures of any of these fluids with a gas, wherein the fluid has an intimate mixture of a particulate material and a fibrous material suspended therein, furthermore where the fluid is capable of reducing the friction forces encountered by the fluid suspension in a tubular device pumping the fluid suspension with the fibers. 13. A fluid for filtering gravel from a borehole into a formation to improve production, the formation contains hydrocarbons for production from the formation of sand, the fluid comprises a viscous liquid having a mixture of a particulate material and a material suspended in the fibrous material, the fibrous material is able to reduce the undesirable migration of the sand towards the borehole and increase the permeability for the production of hydrocarbons from the formation, the fibrous material is adapted to prevent the migration of sand towards the sealing package of gravel thus facilitating the use of a larger gravel mesh size to increase the permeability of the gravel pack. 14. A fluid suspension adapted to treat an underground formation penetrated by a sounding comprising: (a) a viscous fluid, and (b) resin-coated sand, (c) wherein the resin-coated sand with the viscous fluid forms a matrix within the underground formation, (d) further wherein the voids or channels are formed within the matrix by dissolving or by removing selectively from the resin-coated sand matrix. 15. A fluid for the treatment of an underground formation comprising a viscous liquid consisting of a gelled oil or oil, a gelled aqueous fluid, aqueous polymer solutions, solutions of an aqueous surfactant, viscous emulsions of water and oil or oil and mixtures of any of these fluids with a gas, wherein the fluid has an intimate mixture of a support material and fibers that is suspended therein, furthermore where the support material is deposited in the formation with the fibers to form a sealing package of the support material, wherein the fluid is able to reduce the amount of undesirable sedimentation of the support material, the fluid being adapted to facilitate the reduction of polymer loads to transport and place the support material within the formation underground, resulting in a sealing package of support material of greater permeability.