MX2011008782A - Method for diversion of hydraulic fracture treatments. - Google Patents

Abstract

Disclosed herein are methods that include a method for treating a well bore including treating a subterranean formation with a first treatment fluid, wherein the first treatment fluid treats a first treated zone. A degradable diverting material may then be introduced into the subterranean formation. The subterranean formation may be treated with a second treatment fluid where the degradable diverting material diverts at least a portion of the second treatment fluid away fro the first treated zone.

Description

METHOD FOR THE DEVIATION OF FRACTURE TREATMENTS HYDRAULICS FIELD OF THE INVENTION The present invention relates to methods useful in underground treatments, and, at least in some embodiments, to methods for diverting fracturing fluids into an underground formation.

BACKGROUND OF THE INVENTION After a well is drilled and completed in an area of an underground formation, it may often be necessary to introduce a treatment fluid into the zone. As used in this document, "zone" simply refers to a part of the formation and does not imply a particular stratum or geological composition. For example, the production zone can be stimulated by introducing a hydraulic fracturing fluid into the production zone to create fractures in the formation, thus increasing the production of hydrocarbons derived from it. To ensure that the production zone is uniformly treated with the treatment fluid, some form of deviation within or between zones in the underground formation may be useful. For example, you can use a plug or plug expanded between sets of perforations to divert a treatment fluid between the perforations. In another technique, solid biasing agents, such as support agent particles, can be used to form expandable plugs in the coating to divert fluid within or between zones. In another technique, balls can be used to seal individual perforations to divert fluid within or between zones. Such techniques may be only partially successful in diverting the fluid and ensuring uniform distribution of fluid between the various production zones and perforations within an underground formation.

One of the many problems in using part or all of the above described methods, it may be that the means for diverting the treatment fluid is subsequently removed from the well preferably to allow the maximum flow of the hydrocarbons produced from of the underground zone in the well. For example, a plug in general, is removed or drilled out at the end of the operation to allow production. Similarly, sand plugs or bridges are empty for production; Sealing balls are often recovered for production. This may involve additional measures in the treatment process leading to a additional time] and expenses.

BRIEF DESCRIPTION OF THE INVENTION The present invention relates to methods useful in underground treatments, and, at least in some embodiments, to methods of diversion of fracturing fluids within an underground formation.

According to one aspect, the invention provides a method for treating a well whose method comprises introducing a degradable deviating material into the underground formation, wherein the degradable deviating material deflects at least a portion of the treatment fluid. .

In another aspect, the invention provides a method for fracturing an underground formation comprising: fracturing a part of an underground formation with a fracturing fluid through a first perforation tunnel to create a first fracture; introducing a degradable deviation material into the interior of the first drilling tunnel; and fracturing the underground formation with the fracturing fluid through a second drilling tunnel to create a second fracture, where the degradable deviating material deflects at least a part of the fracturing fluid out of the first tunnel of drilling.

In a further aspect, the present invention provides a method for treating a well comprising treating an underground formation with a first treatment fluid, wherein the first treatment fluid treats a first treated zone; introduce a degradable deviation material into the underground formation; and treating the underground formation with a second treatment fluid, wherein the degradable deviating material deviates at least a portion of the second treatment fluid from the first treated zone.

In a further aspect, the present invention provides a method for fracturing an underground formation comprising fracturing an underground formation with a fracturing fluid through a first perforation tunnel to create a first fracture; introducing a degradable deviation material into the first drill tunnel at a sub-fracture pressure; and fracturing the underground formation with the fracturing fluid through a second drilling tunnel to create a second fracture, wherein the degradable deviating material deflects at least a part of the fracturing fluid out of the first drilling tunnel.

In one aspect Further, the present invention provides a method for fracturing a well comprising fracturing a well with a fracturing fluid containing a plurality of support agent particles through a first drilling tunnel to create a first fracture; forming a plug of supporting agent particles in the well, wherein the plug covers the first drilling tunnel; introducing a degradable deviating material into the plug of supporting agent particles at a sub-fracture pressure; fracturing the underground formation with the fracturing fluid through a second drilling tunnel to create a second fracture, where the degradable deviating material diverts at least a part of the fracturing fluid out of the first drilling tunnel covered by the plug of support agent.

In a preferred aspect, the treatment fluids and fracturing fluids used do not comprise cement.

The functions and advantages of the present invention will be apparent to those skilled in the art. While numerous changes can be made by those skilled in the art, such changes are within the scope of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS These drawings illustrate certain aspects of some of the embodiments of the present invention, and should not be used to limit or define the invention.

The Figure illustrates a cross-sectional side view of an exemplary embodiment of the present invention.

Figure Ib illustrates a cross-sectional side view of an alternative exemplary embodiment of the present invention where the fracturing treatment is placed using a jet injection tool into the well.

Figure 2a illustrates a cross-sectional side view of an exemplary embodiment of the present invention after a first treatment in accordance with one embodiment of the present invention.

Figure 2b illustrates a cross-sectional side view of an exemplary embodiment of the present invention after a first treatment in accordance with an alternative embodiment of the present invention where the fracturing treatment is placed using an in-jet jet tool. from the well.

Figure 3a illustrates u a. side view in cross section of an exemplary embodiment of the present invention with a horizontal well that is formed there after a first treatment according to an embodiment of the present invention.

Figure 3b illustrates a cross-sectional side view of an exemplary embodiment of the present invention with a horizontal well that is formed there after a first treatment in accordance with an alternate embodiment of the present invention where the fracturing treatment is placed using a jet injection tool into the well.

Figure 4a illustrates a cross-sectional side view of an exemplary embodiment of the present invention after a second treatment in accordance with one embodiment of the present invention.

Figure 4b illustrates a cross-sectional side view of an exemplary embodiment of the present invention after a second treatment according to an alternate embodiment of the present invention where the fracturing treatment is placed using a jet injection tool into the water well.

DETAILED DESCRIPTION OF THE INVENTION The present invention relates to methods useful in underground treatments, and, at least in some modalities, to methods of deviation of fracturing fluids within an underground formation.

The term "particle" as used herein is not limited to any particular form and is intended to include particles of material having the physical form of platelets, chips, flakes, ribbons, bars, strips, spheroids, choroids, pallets , tablets or any other physical form.

The term "degrade", "degradation", "degradable", and the like when used herein refer to the two relative cases of hydrolytic degradation to which the deviating, deviating material may be subjected, ie, heterogeneous (or massive erosion) and homogeneous (or surface erosion), and any stage of degradation between these two. This degradation can be a result of, among others, a chemical or thermal reaction or a reaction induced by radiation.

As used herein, the term "treatment" refers to any underground operation that utilizes a fluid in conjunction with a desired function and / or for a desired purpose. The term "treatment" does not imply any particular action of the fluid or any other particular component thereof.

As used in this disclosure, the term "Improvement" of a fracture refers to the extension or lengthening of a natural fracture or previously created in the formation.

"Zone", as used in this document, simply refers to a part of the formation and does not imply a particular stratum or geological composition.

While there are numerous advantages of the present invention, only some may be described or alluded to in this document. In one embodiment, the diverting materials of the present invention can be advantageously used to divert a treatment fluid from one zone in an underground formation to another, and can then degrade in the underground formation without the need for an additional step of remove the deviation material. In one embodiment, the treatment may be a fracturing treatment and the use of degradable deviation material may allow the creation of multiple fractures through various perforations without the need for additional related operations, such as moving the pipe or placing a plug in the hole.

In one embodiment, a method of the present invention may include treating an underground formation with a first treatment fluid, wherein the first treatment fluid treats a first treated zone; introduce a degradable deviation material into the underground formation; and treating the underground formation with a second treatment fluid, wherein the degradable deviating material deviates at least a portion of the second treatment fluid from the first treated zone. The first treatment can be one of several useful treatments in an underground environment including a fracturing treatment, and the degradable deviation material can be used to divert fracturing fluid from an existing fracture to another hole to create or improve a new fracture.

In one embodiment, a degradable deviating material can be any material capable of degrading in an underground environment. Additionally, the degradeable deviating material may be in any form for delivery, including for example, particles or powders. Non-limiting examples of degradable deviating material that can be used in conjunction with the methods of the present invention may include, but are not limited to, degradable polymers. Suitable examples of degradable polymers that may be used in accordance with the present invention may include, but are not limited to, homopolymers, random, block, graft, and star and hyper-branched aliphatic polyesters. The polycondensation reactions, ring opening polymerizations, free radical polymerizations, anionic polymerizations, carbocationic polymerizations, ring-opening coordination polymerizations, and any other suitable process can prepare such suitable polymers. Specific examples of suitable polymers may include polysaccharides such as dextran or cellulose; chitins; chitosans; proteins, aliphatic polyesters; poly (lactides); poly (glycolides); ??? (e-caprolactones); poly (hydroxybutyrate); poly (anhydrides); aliphatic polycarbonates; poly (orthoesters); poly (amino acids); poly (ethylene oxides); and polyphosphazenes. Of these suitable polymers, aliphatic polyesters and polyanhydrides may be preferred.

The aliphatic polyesters can be chemically degraded, inter alia, by hydrolytic cleavage. The hydrolysis can be catalyzed either by acids or bases. Generally, during hydrolysis, carboxylic end groups can be formed during chain cleavage, and this can improve the additional hydrolysis ratio. This mechanism is known in the field as "autocatalysis", and can make polyesters of greater massive erosion.

Suitable aliphatic polyesters have the general formula of repeating units shown below: Formula I where n is an integer between 75 and 10,000 and R is selected from the group consisting of hydrogen, alkyl, aryl, alkylaryl, acetyl, heteroatoms, and mixtures thereof.

Of the suitable aliphatic polyesters, poly (lactide) may be preferred. The poly (lactide) can be synthesized either from lactic acid by a condensation reaction or more commonly by ring opening polymerization of cyclic monomeric lactide. Since both lactic acid and lactide can achieve the same repeat unit, the general term poly (lactic acid) as used herein refers to Formula I without any limitation as to how the polymer was made such as from lactides, lactic acid, or oligomers, and without reference to the degree of polymerization or level of plasticization.

The lactide monomer can generally exist in three different forms: two stereoisomers L- and D-lactide and racemic-D, L-lactide '(meso-lactide). The acid oligomers Lactide oligomers are defined by Formula II where m is an integer: 2 = m = 75. Preferably, m is an integer: 2 < m < 10. These limits may correspond to enumerating the average molecular weights below 5,400 and below about 720, respectively. The chirality of the lactide units can provide the means for adjusting, among others, the degradation rates, as well as the physical and mechanical properties. The Poly (L-lactide), for example, can be a semi-crystalline polymer with a relatively low hydrolysis rate. This may be desirable in applications of the present invention where a slower degradation of the degradable deviating material might be desired. Poly (D, L-lactide) can be a more amorphous polymer with a faster rate of hydrolysis resulting. This may be suitable for other applications where faster degradation might be appropriate. The stereoisomers of lactic acid can be used individually or combined to be used in accordance with the present invention. Additionally, these can be copolymerized with, for example, glycolide or other monomers such as e-caprolactone, 1,5-dioxepan-2-one, trimethylene carbonates, or other suitable monomers to obtain polymers with different properties or degradation times. Additionally, the lactic acid stereoisomers can be modified for use in the present invention by, inter alia, mixing, copolymerizing or otherwise mixing the stereoisomers, mixing, copolymerization or otherwise mixing high molecular weight polylactides and low, or by mixing, copolymerization or otherwise mixing a polylactide with another polyester or polyesters.

Other plasticizers can be used in the compositions and methods of the present invention, and include oligomeric lactic acid derivatives, selected from the group defined by the formula: Formula III where R is hydrogen, alkyl, aryl, alkylaryl or acetyl, and R is saturated, where R 'is hydrogen, alkyl, aryl, alkylaryl or acetyl, and R' is saturated, where R and R ' they can not be both H, where q can be an integer: 2 = q = 75; and mixtures thereof. Preferably q can be an integer: 2 = q = 10. As used herein, the term "oligomeric lactic acid derivatives" the oligomeric lactide derivatives.

The plasticizers can be present in any amount that provides the desired characteristics. For example, the various types of plasticizers discussed in this document provide (a) more effective compatibilization of the components of the components of the fusion mixture; (b) improved processing characteristics during the mixing and processing steps; and (c) control and regulation of the sensitivity and degradation of the polymer by moisture. For flexibility, a plasticizer may be present in larger amounts while other characteristics are improved by smaller amounts. The compositions may allow many of the desired characteristics of pure unpleasant polymers. In addition, the presence of a plasticizer can facilitate the processing of fusion, and better the rate of degradation of the compositions in contact with. the environment. The deeply plasticized composition can be processed into a final product in an adopted way to retain the plasticizer as a deep dispersion in the polymer for certain properties. This may include: (1) cooling the composition at a rate adapted to retain the plasticizer as a deep dispersion; (2) the melt processing and cooling of the composition at a rate adapted to retain the plasticizer as a deep dispersion; and (3) processing the composition in a final product in a manner adapted to maintain the plasticizer as a deep dispersion. In certain embodiments, the plasticizers may be at least immediately dispersed in the aliphatic polyester.

An aliphatic polyester can be poly (lactic acid). D-lactide is a dilactone, or cyclic dimer, of D-lactic acid. Similarly, L-lactide is a cyclic dimer of L-lactic acid. Meso D, L-lactide is a cyclic dimer of D-, and L-lactic acid. The racemic D, L-lactide comprises a 50/50 mixture of D-, and L-lactide. When used only in this document, the term "D, L-lactide" is intended to include meso D, L-lactide or racemic D, L-lactide. Poly (lactic acid) can be prepared from one or more of the above. The chirality of the lactide units can provide the means to adjust the degradation rates as well as the physical and mechanical properties. The Poly (L-lactide), for example, can be a semi-crystalline polymer with a relatively low hydrolysis rate.

This may be desirable in applications of the present invention when low degradation is preferred. Poly (D, L-lactide) can be an amorphous polymer with a faster rate of hydrolysis. This may be suitable for other applications of the present invention. The stereoisomers of lactic acid can be used individually combined or copolymerized according to the present invention.

The aliphatic polyesters of the present invention can be prepared substantially by any of the conventionally known manufacturing methods such as those disclosed in U.S. Patent Nos. 6,323,307; 5,216,050; 4,387,769; 3,912,692 and 2,703,316, the relevant floods of which are incorporated herein by reference in their entirety.

The poly (anhydrides) may be another type of pleasant polymer useful in the present invention. The hydrolysis of poly (anhydride) can proceed, inter alia, by terminating free carboxylic acid chains to produce carboxylic acids as final degradation products. The one that moves erosion can be varied over a wide range of changes in the polymer backbone.

Examples of suitable poly (anhydrides) may include poly (adipic anhydride), poly (suberic anhydride), poly (sebasic anhydride), and poly (dodecanedioic anhydride). Other suitable examples include, but are not limited to poly (maleic anhydride) and poly (benzoic anhydride).

The physical properties of degradable polymers may depend on several factors such as the composition of the repeating units, chain flexibility, presence of polar groups, molecular mass, degree of branching, crystallinity, orientation, etc. For example, short chain branches can reduce the degree of crystallinity while long chain branches can lower the melt viscosity c impart, among others, elongation viscosity with stress stiffness behavior. The properties of the material used can also be adjusted by mixing, and copolymerization thereof with another polymer, or by a change in the macromolecular architecture (eg, hyper-branched, star-shaped polymers, or dendrimers, etc.). ). The properties of any suitable degradable polymer (e.g., hydrophobicity, hydrophilicity, degradation rates, etc.) can be adjusted by introducing selected functional groups along the polymer chains. For example, poly (phenylactide) can be degraded in about 1/5 part of the racemic poly (lactide) rate at a pH of about 7.4 to 55 ° C. Someone of common knowledge in the matter with the benefit of this disclosure will be able to determine the appropriate functional groups to introduce into the structure of the polymer chains to achieve the desired physical properties of the degradable polymers.

When choosing the appropriate degradable material, one must consider the degradation products that may result. The degradation products must not adversely affect other operations or components. The choice of degradable material may also depend, at least in part, on the well conditions, eg, the well temperature. For example, lactides have been found to be suitable for low temperature wells, including those in the range of about 60 ° F (15 ° C) to about 150 ° F (66 ° C), and it has been found that polylactides are suitable for wells with temperatures above this range. Also, poly (lactic acid) may be suitable for higher temperature uses. Some stereoisomers of poly (lactide) or mixtures of such stereoisomers may be suitable for even higher temperature applications.

In one embodiment of the present invention, the degradable deviating material can be formed into particles of selected sizes. That is, the polymer degradable deviating material can be degraded in such a solvent such as methylene chloride, trichlorethylene, chloroform, cyclohexane, methylene diiodide, mixtures thereof and the like. The solvent can then be removed to form a solid material from which it can be formed into desired particle sizes. Alternatively, fine powders can be mixed and then granulated or granular to form blends having any desired particle size. In one embodiment, the degradable deviating material can be formed into particles with a size ranging from 100 mesh (0.15 mm) to one quarter of an inch (6 mm).

Examples of treatment fluids that can be introduced into the underground formation containing the degradable deviation material include, but are not limited to, foams based on water, fresh water, salt water, formation water, various aqueous solutions and various hydrocarbon-based solutions. Aqueous solutions include, but are not limited to, acidic aqueous solutions, aqueous solutions of scale inhibiting material, aqueous solutions of water blocking material, aqueous clay stabilizing solutions, aqueous solutions of chelating agents, aqueous solutions, surfactants, fluids. aqueous fracturing; and aqueous solutions for paraffin removal. Hydrocarbon-based solutions may include, but are not limited to, oil, oil-water emulsions, oil-based foams, hydrocarbon solutions of scale-inhibiting material, hydrocarbon-based drilling fluids, emulsified hydrocarbon-based acidification fluids, and hydrocarbon-based fracturing fluids.

When the aqueous treatment fluid is an aqueous acidic solution, the aqueous acidic solution may include one or more mineral acids such as hydrochloric acid, hydrofluoric acid, or organic acids such as acetic acid, formic acid and other organic acids or mixtures thereof. . In acidification procedures to increase the porosity of the underground production zones, a mixture of hydrochloric and hydrofluoric acids can be used.

Another aqueous treatment fluid that can be introduced into the underground production zone according to this invention is a solution of an aqueous scale inhibiting material. The aqueous scale inhibitor solution may contain one or more scale inhibiting materials including, but not limited to, ethylenediamine tetraacetate, pentamethylene phosphonate, hexamethylene diamine phosphonate and polyacrylate. These scale-inhibiting materials can adhere to the surfaces of the underground zone whereby they can inhibit scale formation in tubular products and the like when hydrocarbons and water are produced in the underground zone.

Another aqueous solution of 'treatment which can be used as a solution of an aqueous water blocking material. The water blocking material solution may contain one or more water blocking materials that can adhere to the formation in water production areas whereby water production can be reduced or terminated. Examples of water blocking materials that can be used include, but are not limited to, sodium silicate gels, crosslinked organic polymers with cross linkers of metal and organic polymers crosslinked with organic cross linkers. Of these, organic polymers cross-linked with organic cross linkers are preferred.

Suitable fracturing fluids for use in the present invention generally comprise a base fluid, a suitable gelling agent, and carrier agent particles. Optionally, other components may be included if desired, as recognized by someone experienced in the art with the benefit of this disclosure. For example, the fluids used in the present invention may optionally comprise one or more additional additives. known in the art, including, but not limited to, fluid loss control additives, gel stabilizers, gas, salts (e.g., KC1), pH adjusting agents (e.g., regulators), corrosion inhibitors, dispersants, flocculants, acids, foaming agents, anti-foaming agents, H2S scavengers, lubricants, oxygen scavengers, weighting agents, scale inhibitors, surfactants, catalysts, clay control agents, biocides, reducing agents friction, particles (e.g., support agent particles, gravel particles), combinations thereof, and the like. For example, a gel stabilizer comprising sodium thiosulfate can be included in certain treatment fluids of the present invention. Individuals skilled in the art, with the benefit of this disclosure, will recognize the types of additives that may be suitable for a particular application of the present invention.

The water-based fluid used in the treatment fluids of the present invention may comprise fresh water, salt water (eg, water containing one or more salts dissolved therein), brine, sea water, or combinations thereof. same. Generally, the water can be from any source, provided that it does not contain components that could adversely affect the stability and / or performance of the water. the treatment fluids of the present invention, for example, copper ions, iron ions, or certain types of organic materials (e.g., lignin). In certain embodiments, the density of the water-based fluid may be increased, among other purposes, to provide additional transport of particles and suspension in the treatment fluids of the present invention. In certain embodiments, the pH of the aqueous base fluid can be adjusted (eg, by a regulator or other pH adjusting agent), among other purposes, to activate a crosslinking agent, and / or to reduce the viscosity of the treatment fluid (eg, activate a switch, deactivate a cross-linking agent). In these embodiments, the pH can be adjusted to a specific level, which may depend on, among other factors, the types of gelling agents, cross-linking agents, and / or switches included in the treatment fluid. Someone with common knowledge in the field, with him. benefit of this disclosure, will recognize when such density and / or pH adjustments are appropriate.

A gelling agent can be used in a treatment fluid of the present invention and can comprise any polymeric material capable of increasing the viscosity of an aqueous fluid. In certain embodiments, the gelling agent may comprise polymers having the minus two molecules that may be capable of cross-linking in a cross-linking reaction in the presence of a cross-linking agent, and / or polymers having at least two molecules therefore cross-linking (i.e. cross-linked gelling agent). The gelling agents can be of natural occurrence, synthetic, a combination thereof. In certain embodiments, suitable gelling agents may comprise polysaccharides, and derivatives thereof containing one or more of these monosaccharide units: galactose, mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronic acid, pyranosyl sulfate. Examples of suitable polysaccharides include, but are not limited to, guar gums (e.g., hydroxyethyl guar, hydroxypropyl guar, carboxymethyl guar, carboxymethyl hydroxyethyl guar, and carboxymethyl hydroxypropyl guar ("CMHPG")), cellulose derivatives (eg. .ej., hydroxyethyl cellulose, carboxyethyl cellulose, carboxymethyl cellulose, and carboxymethyl hydroxyethyl cellulose), and combinations thereof. In certain embodiments, the gelling agents comprise an organic carboxylated polymer, such as CMHPG. In certain embodiments, the derivatized cellulose is a cellulose with allyl or a vinyl monomer, such as those disclosed in the documents of U.S. Patent Nos. 4,982,793; 5,067,565; Y 5,122,549, the relevant tribulations of which are incorporated herein by reference. Additionally, polymers and copolymers comprising one or more functional groups (e.g., hydroxyl, cis-hydroxy, carboxylic acids, carboxylic acid derivatives, sulfate, sulfonate, phosphate, phosphonate, amino, or amide groups) can be used. ).

The gelling agent may be present in the treatment fluids of the present invention in an efficient amount to provide the desired viscosity. In some embodiments, the gelling agents may be present in an amount in the range of 0.10% to 4.0% by weight of the treatment fluid. In certain embodiments, the gelling agents may be present in an amount in the range of 0.18% to 0.72% of the weight of the treatment fluid.

In those embodiments of the present invention where it is desired to crosslink the gelling agent, the treatment fluid may comprise one more of the crosslinking agents. The crosslinking agents may comprise a metal ion that is capable of crosslinking at least two molecules of the gelling agent. Examples of suitable cross-linking agents include, but are not limited to, borate ions, ions of zirconium IV, titanium IV ions, aluminum ions, antimony ions, chromium ions, iron ions, copper ions, and zinc ions. These ions can be provided by providing any compound that is capable of producing one or more of these ions; examples of such compounds include, but are not limited to, boric acid, disodium octaborate tetrahydrate, sodium diborate, pentaborates, ulexite, colemanite, zirconium lactate, zirconium triethanolamine, zirconium lactate triethanolamine, zirconium carbonate, zirconium acetylacetonate, maleate zirconium, zirconium citrate, zirconium diisopropylamine lactate, zirconium glycolate, zirconium triethanolamine ammonium glycolate, zirconium lactate glycolate, titanium lactate, titanium malato.de, titanium citrate, titanium ammonium lactate, titanium triethanolamine, and titanium acetylacetonate, aluminum lactate, aluminum citrate, antimony compounds, chromium compounds, iron compounds, copper compounds, zinc compounds, and combinations thereof. In certain embodiments of the present invention, the cross-linking agent can be formulated to remain inactive until it is "activated" by, among other things, certain conditions in the fluid (eg, pH, temperature, etc.). and / or contact with another substance. In some embodiments, the cross-linking agent can be delayed by encapsulation with a coating (eg, a porous coating through which the switch can penetrate slowly, or a degradable coating that degrades into the well) that delays the release of the cross-linking agent to a time or place wanted. The choice of a particular cross-linking agent will be governed by several considerations that will be recognized by one skilled in the art, including but not limited to the following: the type of gelling agent included, the molecular weight of the agent (s) ) gelling agent (s), the pH of the treatment fluid, the temperature, and / or the desired time for the crosslinking agent to crosslink the gelling agent molecules.

When included, suitable cross-linking agents may be present in the treatment fluids of. the present invention in an amount sufficient to provide, inter alia, the degree of cross-linking desired between molecules of the gelling agent. In certain embodiments, the crosslinking agent may be present in the treatment fluids of the present invention in an amount in the range of 0.0005% to 0.2% by weight of the treatment fluid. In certain embodiments, the cross-linking agent may be present in the treatment fluids of the present invention in an amount in the range of 0.001% to 0.05% by weight of the treatment fluid. One skilled in the art, with the benefit of this disclosure, will recognize the appropriate amount of cross-linking agent to include it in the treatment fluid of the present invention based on, among other things, the temperature conditions of a particular application. , the type of gelling agents used, the molecular weight of the gelling agents, the desired degree of viscosity, and / or the pH of the treatment fluid.

In one embodiment, a base fluid may contain a gel switch, which may be useful to reduce the viscosity of the viscosified fracturing fluid in a specified time. A gel switch can comprise any compound capable of lowering the viscosity of a viscosified fluid. The term "switch" (and its derivatives) as used herein refers to a reduction in the viscosity of the viscosified treatment fluid, e.g., by interrupting or reversing cross-links between polymer molecules or some reduction of the size of the gelling agent polymers. The term does not imply any particular mechanism. Gel break agents suitable for applications Specific and gelled fluids are known to one skilled in the art. Non-limiting examples of suitable switches include oxidants, peroxides, enzymes, acids, and the like. Some fluid. viscosified can also be interrupted with sufficient exposure of time and temperature.

In some embodiments, the fracturing fluid or a fluid used to place a gravel pack may comprise a plurality of support agent particles, inter alia, to stabilize the created or improved fractures. The particles suitable for use in the present invention may comprise any material suitable for use in underground operations. Suitable materials for these particles may include, but are not limited to, sand, gravel, bauxite, ceramic materials, glass materials, polymer materials, polytetrafluoroethylene materials, walnut shell parts, cured resin particles comprising pieces of seed husk, fruit bone pieces, cured resin particles comprising pieces of fruit bone, wood, composite particles, and combinations thereof. The particles of suitable compounds may comprise a binder and a filler material wherein the suitable fillers include silica, alumina, carbon pyrolysis, black carbon, graphite, mica, titanium dioxide, meta-silicate, calcium silicate, kaolin, talc, zirconium, boron, volatile ashes, hollow glass micro spheres, solid glass, and combinations thereof. The average particle size can generally oscillate from the mesh of 2 (11.2 mm) to the mesh of 400 (0.037 mm) in the US Serial Screen; however, in certain circumstances, other average particle sizes may be desired and will be entirely suitable for the practice of the present invention. In particular embodiments, the ranges of the average preferred size distribution of the particles is one more than the 6/12 (3.35 / 1.68 mm), 8/16 (2.38 / 1.2 mm), 12/20 (1.68 / 0.85) mesh. mm) 16/30 (1.2 / 0.60 mm), 20/40 (0.85 / 0.42 mm), 30/50 (0.60 / 0.30 mm), 40/60 (0.42 / 0.25 mm), 40/70 (0.42 / 0.21 mm) ), or 50/70 (0.30 / 0.21 mm). It should be understood that the term "particles", as used in this disclosure, "includes all known forms of materials, including substantially spherical materials, fibrous materials, polygonal materials (such as cubic materials), and mixtures thereof. On the other hand, fibrous materials that may or may not be used to withstand the pressure of a closed fracture may be included in certain embodiments of the present invention In certain embodiments, the particles included in the fluids of treatment of the present invention may be coated with any suitable resin or tackifier known to those of ordinary skill in the art. In certain embodiments, the particles may be present in the fluids of the present invention in an amount in the range ranges from about 0.5 pounds per gallon (0.06 kg / l) to about 30 pounds per gallon (3.6 kg / l) volume of treatment fluid.

A method of the present invention may include treating an underground formation with a first treatment fluid, wherein the first treatment fluid treats a first treated zone; introduce a degradable deviation material into the underground formation; and treating the underground formation with a second treatment fluid, where the degradable material deviating from the day at least a part of the second treatment fluid out of the first treated zone. In one embodiment, the treatment of the formation may be a fracturing treatment carried out with a fracturing fluid. In this embodiment, the degradable deviating material can be used to divert fracturing fluid to untreated perforations in order to create a plurality of fractures in the underground formation.

In another embodiment, a method of the present invention it may include introducing the treatment fluid into the underground zone to create a fracture. A degradable deviation material can be packed in drilling tunnels where it can degrade over time. A treatment fluid can be introduced into the underground zone by means of drilling tunnels, where it can be diverted by the degradable deviation material and create another fracture. The degradable deviation material can then be degraded when exposed to conditions in the underground zone.

In Figure 1, an exemplary complete well is shown in an underground formation. As shown, a well 10 can penetrate an area containing hydrocarbons 12. Although Figure 1 represents the well 10 as a vertical well, the methods of the present invention may be suitable for use in deviated, horizontal or shaped parts of wells. On the other hand, as those of common knowledge in the field will appreciate, the exemplary embodiments of the present invention may be applicable for the treatment of both production and injection wells. In the illustrated embodiment, the well 10 may be lined with the liner 16 which may be cemented with the underground formation to create a cement cover 18. A completed well may include perforations 22 in a range of the well 10. The perforations 22 may generally comprise holes or passages through the liner 16 and the cement 18 into the interior of the underground formation 12. The perforations 22 may be formed generally using drill guns, "the which shoot hollow charges from inside the well 10 to form the perforations 22. In another embodiment shown in Figure Ib, a jet injection tool can be used to create a perforation by using a directed fluid stream containing an abrasive to erode one or more perforations 22 within the underground formation 12. The resulting perforations 22 may include drilling tunnels 20 extending outward from the cladding 16 and the cement 18 into the interior of the formation 12. In one embodiment, the perforations 22 they can generally range in size from 1/10 of an inch (2.5 mm) to about 1.5 inches (37.5 mm) in diameter. The drilling tunnels 20 can extend through the liner 16 into the underground formation 12 from about 6 inches (15 cm) to about 36 inches (90 cm). As shown in Figure Ib, a well can also include a work column 14 placed inside the well to move tools into the well and deliver fluids or materials to an area within the well. underground formation 12. For example, working column 14 may include, but is not limited to, spiral pipe, tie pipes, cable lines, or a line of wire. A variety of tools can be placed within the well 10 using the work column 14 including, but not limited to, plugs, plugs, drilling tools, and injection tools, such as jet injection tools.

In one embodiment of the present invention, a variety of treatments are carried out using degradable deviation materials. Suitable underground applications may include, but are not limited to, drilling operations, production stimulation operations (eg, hydraulic fracturing), and well completion operations (eg, purchased or cemented filling). These treatments can generally be applied to the well and to the formation through perforations in the coating. Each of these treatments can be beneficial by the ability to divert a part of a flow of treatment fluid from one or more perforations to other perforations using degradable deviation materials. The deviation of the treatment fluids can help to ensure that the treatment fluids are distributed more evenly between the perforations goal or range of treatment if degradable deviation materials are not used.

In one embodiment, the treatment can be a fracturing operation. In this embodiment, one or more fractures can be created or improved through underground formation to at least partially increase the effective permeability of the surrounding formation. Figure 2a shows an exemplary well with a fracture. The fracture of the underground formation 12 can be achieved by any suitable methodology. By way of example, a hydraulic fracturing treatment may be used which includes introducing a fracturing fluid into the target zone in the well 10 at a pressure sufficient to create or improve one or more fractures 30. In an exemplary embodiment, the fracture fluid can be introduced into the target zone by pumping the fluid through the coating 16 into the target zone. In certain exemplary embodiments, as shown in Figure 2b, the fracturing step may use a jet injection tool 36. By way of example, the jet injection tool 36 may be used to initiate one or more fractures 30 in the underground formation 12 through one or more perforations 22 in the coating 16 by a jetted fluid through the perforations 22, the drilling tunnels 20 and against the formation 12. A fracturing fluid can also be pumped down through the ring 38 between the working column 14 and the liner 16 and then into the interior of the formation 12 at a pressure sufficient to creating or improving the one or more fractures 30. The fracturing fluid can be pumped down through the ring 38 at the same time with the jet injection of the fluid. An example of a suitable fracturing treatment is CobraMaxSM Fracturing Service, available from Halliburton Energy Services, Inc. In another embodiment, a shutter (not shown) may be placed on or near one or more perforations 22 in the 16th siding. A fracturing fluid may be pumped down through the work column 14 into the interior of the formation 12 at a pressure sufficient to create or improve the one or more fractures 30. In certain exemplary embodiments, the fracturing fluid may comprise a viscosified fluid (e.g., a gel or a gel cross-linked). In certain embodiments, the fracturing fluid further comprises a holding agent 32 that is deposited in the one or more fractures 30 to generate fractures with supportive agents. In certain exemplary embodiments, the support agent 32 can be coated with a consolidating people (eg, a curable resin, an agent adhesive, etc.) in such a way that the coated support agent forms an adhesive mass, permeable in the one, or more fractures, for example, to mitigate the flow of supporting agent back when the well is put into production. By way of example, the support agent can be coated with an Expedite ™ resin system, available from Halliburton Energy Services, Inc. In a embodiment shown in Figure 3a, a final cartridge of supportive agent can be placed in the well, to create a supporting agent plug or expanded plug 34 through the well covering one or more perforations 22. As shown in Figure 3a, a jet injection tool can be used to place the agent plug of support or expandable plug 34 through the well. The support agent plugs can be used in deviated, vertical, or horizontal wells.

Optionally, or in conjunction with the fracturing treatment, one or more washing fluids may be used to clean the well, drilling tunnels, or both. When used, treatment fluids can be introduced into the well after the fracturing treatment has ended and the fracture is allowed to close. The wash fluid may, inter alia, be used to displace any excess support agent in the well, drilling tunnels, or both.

However, the washing step can be limited in duration in order to ensure that the support agent placed in a fracture does not move. Generally, the wash fluid can be any fluid that does not react undesirably with the other components used or with the underground formation. For example, the wash fluid may be an aqueous-based fluid (eg, a brine or water produced), a non-aqueous base fluid (eg, kerosene, toluene, diesel, or crude oil), or 'a gas (eg, nitrogen or carbon dioxide).

In one embodiment, fracturing a perforated area in a well can treat one or more perforations that have the least resistance to fracture fluid flow. In general, a fracture created. During a fracturing treatment it will initiate in the zone or perforation with the least effort and will propagate out of the well in length and height based on several factors. Factors may include, but are not limited to, efforts in adjacent areas, fluid leakage, pumping rate, fluid used, and temperature of the formation. A fracture that is created during a fracturing treatment may not cross all productive zones in a perforated interval. As such, the initial fracturing treatment in the well may not fracture all the desired zones in the formation, and any subsequent attempt Re-fracturing can result in existing fractures taking fluid without opening new fractures. The use of supportive agents in fractures can decrease the resistance to fluid flow of existing fractures since the support agent can create a permeable passage of fluids.

Degradable degradable material can be placed in the underground zone or packaged within the drilling tunnels in the underground formation by introducing a carrier fluid containing degradable deviation materials into the underground zone. The degradable deviating material can be brought into the well using a carrier fluid. . The carrier fluid may contain a gelling or viscosifying agent as necessary in order to suspend the degradable deviating material in solution. A variety of carrier fluids may be used including, but not limited to, fresh water, brine, sea water, forming water, or a combination thereof. In one embodiment, the carrier fluid may be a base fluid used in fracturing treatments, including optional additives commonly used in base fluid compositions. In one embodiment, the carrier fluid and the degradable deviating material can be combine to form a slurry and can be pumped into the well through the working column or the annular space between the working column and the lining. The slurry can be pumped into the well below the fracture pressure of the formation at sub-fracture pumping rates. Such fluid flow rate may be sufficient to force the fluid into the path of least resistance (eg, an existing fracture), but not sufficient to create or improve a fracture. This type of flow is commonly referred to as a matrix flow. In one embodiment, the slurry containing the degradable deviating material can be pumped at a matrix flow rate through a borehole and into a drilling tunnel. The perforation tunnel, the fracture, or both may contain support agent particles that can act as a filter, screening the degradable deviating material out of the carrier fluid while the slurry passes through it. This process can result in a layer or package of degradeable deviating material that is formed in the carrier agent particles, the walls of the drilling tunnel, or both. Pumping with the matrix flow rate can ensure that the degradable deviation material is not brought into the fracture where it may not be able to divert a treatment fluid posterior out of the fracture. Once the degradable deviation material is placed inside the drilling tunnel, the resistance of the flow through the borehole can be increased, causing a back pressure that can be measured at the well surface. A back pressure on the surface sufficient to allow another fracture to form in the underground formation, which may be below the fracture pressure of the formation, may indicate that a sufficient plug of degradable deviation material has been placed in the well. .

In another embodiment shown in Figures 3a and 3b, fracturing treatment may result in the placement of a hold-down agent plug 34 within the well, which may cover one or more perforations 22. The hold-down agent plug 34 it can be placed in the well by introducing a fracturing fluid containing a plug of supporting agent particles 32 while the flow of fracturing fluid approaches the matrix flow rate. When a matrix flow rate is achieved, the holding agent 32 may no longer be carried inwardly from the fracture, but instead forms a plug 34 in the well. Methods for forming plugs of supportive agents or expandable plugs are known to those skilled in the art. In this mode, a slurry containing a degradable material of The deviation can be pumped through the plug of the holding agent into the perforations at a matrix flow rate, resulting in the accumulation of the degradable material of deviation in the plug of the holding agent. The resulting layer of deviating material 40 may be able to divert at least a portion of the fluid in the well out of the support agent plug and, consequently, the perforations covered by the support agent plug. Such a deviation can result in the formation of a back pressure that can be detected on the surface to indicate that the degradable deviation material has been substantially placed in the well. A holding agent plug 34 with a deviating material 40 positioned thereon can be useful in offset, vertical, and horizontal wells.

In one modality, the. Underground formation can be treated after the degradable deviation material has been placed in the well. As understood by those skilled in the art, any of a variety of fluids the treatment can be introduced into an underground undercurrent formation with this invention. Because the degradable deviating material is placed in the well or a plug, a treatment fluid may be at least partially diverted to another area of the formation, which may be one or more perforations that does not have a degradable deviation material placed in them. In one embodiment, a perforation, a drilling tunnel, or a holding agent plug that covers one or more perforations having a degradable deviating material placed thereon may have an increased resistance to flow with respect to a perforation or tunnel of perforation that does not have degradable deviation material placed in it. As such, a treatment fluid that is introduced into an underground formation can flow into a new zone or perforation that has the least resistance to flow, treating the new zone.

In one embodiment, the treatment may be a fracturing treatment using a fracturing fluid. An exemplary embodiment of a well that can be treated with a fluid after having degradable deviating material placed therein is shown in Figures 4a and 4b. As discussed above, the fracturing of the underground formation 12 can be achieved by any suitable methodology. For example, a hydraulic fracturing treatment may be used which includes introducing a fracturing fluid into the target zone in the well 10 at a pressure sufficient to create or improve one or more fractures 30, 42. In another embodiment which is shown in FIG. 4b, a fracturing fluid can also be pumped down through the ring 38 between the work column 14 and the. 16 and then into the interior of the formation 12 at a pressure sufficient to create or improve the one or more fractures 30, 42. In still another embodiment, a stopper (not shown) can be used to pump down through the working column 14 into the interior of the formation 12 at a pressure sufficient to create or improve the one or more fractures 30, 42. A fracture 30, 42 can be formed in the area or perforation with the least resistance, and the resistance in the treated area may decrease in the formation of a fracture. Upon the introduction of the fracturing fluid into the zone, the perforations 44 or drill tunnels 46 which are filled with the degradable deviation material 40 may have greater flow resistance than a perforation 22 or untreated drill tunnel 20, thereby directing the fracturing fluid to a bore 22 or drill tunnel 20 untreated. As shown similarly in Figures 3a and 3b, a hold-down agent plug with a degradeable debris material 40 disposed therein may have a greater flow resistance than an untreated drill hole 22 or tunnel 20, thus directing the fracturing fluid towards a perforation 22 or drill tunnel 20 untreated. This method can be used to at least partially divert the fracturing fluid into a bore 22 or drilling tunnel 20 that has not been treated with a deviating material 40. The fracturing fluid can then create or improve a new fracture 42 in the area of interest.

The process of treating an area in a well followed by the introduction of a degradable deviation material into the zone can be repeated as many times as necessary to treat as many zones as desired. Each treatment can affect one or more drilling or drilling tunnels, and a repeat of the method can be used to ensure that all drilling, drilling tunnels, or areas in the well are treated. Such a repetition of the method can be carried out without moving the work column or placing a plug in the well, increasing efficiency and reducing costs. For example, in a modality in which the treatment is a fracturing treatment, the method can be repeated in order to create a fracture in each perforation in each zone of interest in the underground formation.

After the treatment fluid has been used to treat the area as desired, the degradable material of Deviation can be degraded at least partially, allowing formation fluids to be produced. Deviable deviating materials can be degraded according to a variety of mechanisms depending on factors such as well conditions (eg, temperature, pressure, fluid composition, etc.), and any fluid or chemicals introduced externally. . For example, some of the polymeric compositions useful as degradable deviating materials can be degraded in water released from the formation or introduced during a treatment. When the degradable deviating material is self-friendly, the degradable deviating material may degrade at least partially heated in the underground zone. If the underground formation does not contain water that can be released, an aqueous fluid can be introduced into the interior of the formation to assist in the degradation of the deviation material. For example, salt water, sea water, or steam may be introduced into the underground formation to assist in the degradation of the degradable material of deviation. Accordingly, the degradable deviating material may be adequate even when non-aqueous treatment fluids are used or when an aqueous treatment fluid is dissipated within the formation or when one aqueous fluid has been removed from another. way of training ta-1 as a reverse flow. In one embodiment, a chemical composition can be introduced into the formation to assist in the degradation of the degradable deviation material. Suitable compositions may include, but are not limited to, acidic fluids, basic fluids, solvents, vapor, or a combination thereof.

In another embodiment, other treatments known to those skilled in the art can be carried out together with those of the disclosed method. For example, a flushing fluid may be used to clean the well after degradation of the deviating deviating material to clean the well of any degradable deviating material or remaining support agent that may impede the flow of fluid through the well. .

Therefore, the present invention is well adapted to achieve the ends and advantages mentioned as well as those inherent in this document. The particular embodiments disclosed above are illustrative only, since the present invention can be modified and practiced in different but equivalent ways for those experienced in the art who have the benefit of the teachings herein. In addition, there is no intention of any limitation to the details of construction or design shown in this document, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above can be altered or modified and all of those variations are considered within the scope of the present invention. All numbers and ranges disclosed above vary by a certain amount. Whenever an interval with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, each range of values disclosed in this document (in the form, "from a to a b", or equivalently, "from approximately a to b", or, equivalently, "from about ab") it must be understood that it establishes any number and range that is encompassed within the wider range of values. On the other hand, the indefinite articles "a" or "an", as the claims are used, are defined in this document in the sense of one or more of one of the elements they introduce. Also, the terms in the claims have their ordinary, flat meaning unless explicitly and clearly defined otherwise by the patentee.

Claims (16)

NOVELTY OF THE INVENTION Having described the present invention as above, it is considered as a novelty and, therefore, the content of the following is claimed as property: CLAIMS

1. A method for the treatment of a well, which method comprises introducing a degradable material of diversion into an underground formation; and introducing a treatment fluid into the interior of the underground formation, wherein the degradable deviation material deflects at least a portion of the treatment fluid.

2. A method according to claim 1, characterized in that the deviating material of deviation comprises a particle, wherein the particle has a diameter ranging from a mesh of 100 (0.15 ram) to a quarter of an inch (6 mm).

3. A method according to claim 1 or 2, characterized in that the first treatment fluid comprises at least one fluid selected from a group consisting of: an acid solution, a solution of scale inhibiting material, a solution of blocking material from water, a clay stabilizer solution, a chelating agent solution, a surfactant solution, a furation fluid, a paraffin removal solution, an oil-based foam, a drilling fluid, and derivatives thereof.

4. A method according to claim 1, 2 or 3, further comprising: introducing a first treatment fluid to the underground formation before introducing the degradable deviation material into the underground formation.

5. A method according to claim 4, further comprising: reintroducing the degradable deviation material into the underground formation after the treatment fluid of claim 1 (here the second treatment fluid); Y treating the underground formation with a third treatment fluid, wherein the degradable deviating material deflects at least a part of the third treatment fluid.

6. A method according to claim 1, 2 or 3, characterized in that the treatment fluid comprises a fracturing fluid and the method comprises: fracture a part of an underground formation with a fracturing fluid through a first drilling tunnel to create a first fracture; introducing a degradable deviation material into the interior of the first drilling tunnel; Y fracturing the underground formation with the fracturing fluid through a second drilling tunnel to create a second fracture, where the degradable deviation material deflects at least a part of the fracturing fluid out of the first drilling tunnel.

7. A method according to claim 6, characterized in that introducing a degradable deviation material into the interior of the first drilling tunnel occurs at a matrix flow rate.

8. A method according to claim 6 or 7, further comprising: introducing the degradable deviation material into the underground formation after the treatment fluid used to create said second fracture; and treating the underground formation with a third treatment fluid, wherein the divertable deviating material deviates at least one part of the third treatment fluid from the first treated zone and the second treated zone.

9. A method according to claim 1, 2 or 3, characterized in that the treatment fluid is a fluid of fracture containing a plurality of particles of Support agents and the method comprises: fracturing a well with said fracturing fluid at through a first drilling tunnel to create a first fracture; form a plug of particles of support agents in the well, where the plug covers the first drilling tunnel; introduce a degradable deviation material into the particle plug at a sub-fracture pressure; fracturing the underground formation with said fluid from fracturing through a second drilling tunnel to «create a second fracture, where the degradable material of deviation diverts at least a part of the fluid from Fracturing outside the first covered drilling tunnel by the stopper of support agents.

10. A method according to any of the claims 1 to 9, characterized in that the material degradable deviation comprises at least one substance selected from or consisting of: a chitin; a chitosan; a protein, an aliphatic polyester; a poly (lactide); a poly (glycolide); a poly (e-caprolactone); a poly (hydroxybutyrate); a poly (anhydride); a aliphatic polycarbonate; a poly (orthoester); a poly (amino acid); a poly (ethylene oxide); and a polyphosphazene and a derivative thereof.

11. A method according to any of claims 1 to 10, characterized in that the degradable deviation material comprises a plasticizer selected from a group defined by the formula: wherein R comprises at least one substance selected from the group consisting of: hydrogen, alkyl, aryl, alkylaryl, acetyl, and a derivative thereof; where R 'comprises at least one substance selected from the group consisting of: hydrogen, alkyl, aryl, alkylaryl, acetyl, and a derivative thereof; wherein R and R 'can not both be hydrogen; and where q is an integer between about 2 and 75.

12. A method according to any of claims 1 to 11, further comprising: wash the well with a washing fluid.

13. A method according to any of claims 1 to 12, further comprising: degrade at least a part of the degradable deviation material to allow it to move from the well.

14. A method according to any of claims 6 to 13, characterized in that the fracturing of the underground formation comprises using a jet injection tool to create or improve the first fracture.

15. A method according to any of claims 6 to 14, characterized in that the fracturing fluid comprises at least one substance selected from the group consisting of: a fluid loss control additive, a gelling agent, a viscosifier, a gel stabilizer, a gas, a salt, a pH adjusting agent, a corrosion inhibitor, a dispersant, a flocculant, an acid, a foaming agent, an anti-foaming agent, an H2S scavenger, a lubricant, an oxygen scavenger, a weighting agent, a scale inhibitor, a surfactant, a catalyst, a clay control agent, a biocide, a friction reducer, a particle and a derivative thereof.

16. A method according to any of claims 9 to 15, characterized in that the support agent particle is substantially coated with a resin or an adherent agent.