MX2007008850A

MX2007008850A - Soluble diverting agents.

Info

Publication number: MX2007008850A
Application number: MX2007008850A
Authority: MX
Inventors: Syed Akbar; Patrick R Okell; A Richard Sinclair
Original assignee: Fairmount Minerals Ltd
Priority date: 2005-01-21
Filing date: 2006-01-20
Publication date: 2008-01-16
Also published as: US20060175059A1; CA2595686A1; CA2595686C; RU2433157C2; GB2437869A; CN101146888A; WO2006088603A1; CN101146888B; GB0714796D0; RU2007131659A; GB2437869B; NO20074239L

Abstract

Methods and compositions for stimulating single and multiple intervals in subterranean wells by diverting well treatment fluids into a particular direction or into multiple intervals using water soluble coated diverting agents are described. The water soluble coating of the diverting material is preferably a collagen, poly(alkylene) oxide, poly(lactic acid), polyvinylacetate, polyvinylalcohol, polyvinylacetate/polyvinylalcohol polymer or a mixture thereof applied as a coating on any number of proppants. The method allows for the diverting of the flow of fluids in a downhole formation during a well treatment, such as during a fracturing process. Following completion of a treatment such as a hydraulic stimulation, the soluble diverting agent can be dissolved and removed by the water component of the well production.

Description

SOLUBLE DERIVATION AGENTS FIELD OF THE INVENTION The present invention provides methods and compositions for the treatment of underground wells and, more specifically, provides methods and compositions for stimulating multiple intervals in underground wells. In particular, this invention provides methods and compositions for deriving well treatment fluids at multiple intervals by introducing consolidation materials coated with a water soluble polymer, eg, collagen, polyvinyl acetate / polyvinyl alcohol, polyalkyl oxides, poly (acid) lactic), periodic table elements of group I or II (alkali metals or alkaline earth metals), silicate polymer or combinations thereof with materials that are slowly soluble in water for use in redirecting the flow of stimulation fluids from a pipe string in the underground environment. DESCRIPTION OF RELATED ART Well treatments, such as acid treatments and fractures of underground formations, are routinely used to improve or stimulate the recovery of hydrocarbons. In many cases, an underground formation may include two or more intervals that have permeability and / or variable injection capacity. Some intervals may have relatively low injection capacity, or ability to accept injected fluids, due to relatively low permeability, "in-itself" high voltage, and / or formation damage. Such intervals can be completed through preparations in a piped sounding and / or can be completed with the open hole. In some cases, such intervals of formation may be present in a highly deviated or horizontal section of a sounding, for example, a section of the lateral open hole. In any case, when the multiple treatment intervals have variable injection capacity which is often the most common case, if not in all cases, the treatment fluid of the introduced well will be displaced in one, or only a few, of the intervals that have greater injection capacity. Even if there is only one interval to deal with, the tendency for the growth of the fracture may be either up or down. This depends on the tension in si tu of the formation and the variation of the permeability in the formation layer. Under the fracture there may be a water zone. If the fracture created breaks in this area, the well can be ruined due to the excess water and a cut of the oil components of the producing interval. Above the created fracture zone there may be a gas stopper which it would cause damage to the production of the well due to the derivation of the gas to the liquid oil components of the well. In an effort to more evenly distribute the well treatment fluids displaced in each of the multiple ranges to be treated, methods and materials have been developed to derive treatment fluids at permeability and / or lower injectivity intervals. However, conventional derivation techniques can be expensive and / or can only achieve limited success. In this regard, mechanical bypass techniques are typically complicated and expensive. In addition, mechanical bypass methods are typically limited to tube-hole environments and rely on adequate cement and the isolation of the tools to achieve bypass. The efficient and simultaneous treatment of multiple sets of perforations on an extended vertical section has thus been a problem in the stimulation of wells for many years. Numerous bypass treatment methods have been used, such as oil-soluble calcium soap, sulfuric acid, and Dowell's "Fixafrac" (a mixture of lime, kerosene, a classified calcium chloride soap, and a gelation agent, and FLAX-2 ™ from Dowell as described by Harrison in his compressive review Journal of Petroleum Technology, pp. 593-598 (1972), for treat multiple zones with a wide variety of effectiveness. A wide variety of chemical-based derivatizing agents have been used in attempts to seal the openings in the formation and derive the treatment fluids to other areas of the formation. For example, wax beads have been used as bypass agents. However, the beads have limited melting points, from about 58.88 ° C to about 88.88 ° C (138 ° F to about 192 ° F), rendering them useless if the temperature of the formation exceeds its melting point. Naphthalene or naphthalene particles (moth balls) and sodium chloride have also been described as being useful as efficient bypass agents. Naphthalene particles are readily soluble in oil, but melt at approximately 82.22 ° C (180 ° F), thus limiting their use to applications in lower temperature formations. Sodium chloride, which has a melting point of about 798.88 ° C (1,470 ° F), while useful at high temperatures, requires that the well has been cleaned with water or diluted acid after the formation has been treated to completely eliminate the sodium chloride particles. In addition, sodium chloride can not be used with hydrofluoric acid to treat underground wells due to the formation of insoluble precipitates that can problematically block the well. Alternatively, derivatizing agents such as polymers, suspended solids and / or foam have been employed when multiple ranges of injectivity or variable injection capacity have been treated simultaneously. Such bypass agents are typically pumped into an underground formation prior to a well treatment fluid to hermetically seal the larger permeability ranges and derive the well treatment fluid at lower permeability intervals. However, the derivation action of such bypass agents is often difficult to predict and monitor, and may not be successful in diverting the treatment fluid at all desired intervals. These problems can be aggravated more in open hole completions, especially in highly deviated terminations that have large areas of a formation open to sounding. The presence of natural fractures can also make the derivation more difficult. Over the years several attempts have been made to direct the expeditions of different permeability areas in one survey. US Patent No. 2,803,306 to Hower offers a process for increasing the permeability of underground formation having several zones of variable permeability.

The described steps include introducing into a hole in the well a treatment fluid containing hydrochloric acid which has oil soluble particles dispersed therein, the material is selected from gonsonite, naphthalene, para-dichlorobenzene, anthracene, and β-naphthol. After the treatment, the. particles provide a partial obstruction of the most permeable zones of the underground formation, allowing the treatment fluid to enter the less permeable zones. U.S. Patent No. 3,797,575 conferred to Halliburton discloses derivatizing additives comprised of relatively insoluble solid material in water dissolved in a solvent such as methanol or isopropanol. When the additive is combined with an aqueous treatment fluid, the solid material, dissolved in the additive, is precipitated in the aqueous treatment fluid in a finally divided form, which then acts as a bypass agent. US Patent No. 3,724,549, also licensed to Halliburton, discloses a derivatizing agent material for deriving aqueous treatment fluids in progressively less permeable underground formations. The material is composed of a carrier liquid and particles classified as cyclic or linear hydrocarbon resins that have between approximately 20 and approximately 1,400 carbon atoms, and a melting point of approximately 93.33 ° C (200 ° F). It is described that this material is considerably insoluble in water and acid, but soluble in oil, such that the resin can be removed by the oil produced after the completion of the operation of the oil treatment. The use of radiation-induced polymers as either temporary or permanent derivatizing agents has been described by Knight, et al. in U.S. Patent No. 3,872,923. According to the specification, temporary or permanent reductions in permeability can be obtained by injecting an aqueous solution containing a water-soluble polymer obtained by radiation-induced polymerization of acrylamide and / or methacrylamide and acrylic acid, methacrylic acid, and / or salts of alkaline metals of such acids. The resulting polymeric derivatizing agent has properties, such as temperature and pH stability, in order to effect a permeability reduction of the porous medium. The permeability within the formation can be restored by subsequent treatment with a chemical to break the polymer, such as a solution of hydrazine hypochlorite or with strong mineral acids. U.S. Patent Nos. 3,954,629 and 4,005,753 by Scheffel, et al. , they offer derivation agents polymeric, and methods of treating underground formations with such polymeric derivatizing agents, respectively. It is described that the polymer composition comprises solid particles of a homogeneous mixture of polyethylene, ethylene-vinyl acetate copolymer, a polyamide, and a softening agent such as long chain aliphatic diamides. It is reported that these polymeric bypass agents are suitable for use in underground formations where the formation temperatures are 176 ° C (350 ° F) or higher. Temporary obturation methods of an underground formation using a derivatization material comprising an aqueous carrier liquid and a derivatizing agent comprising a solid azo component and a methylene component are described by Dill, et al. in U.S. Patent No. 4,527,628. The derivatizing agent is preferably Hansa Yellow G (yellow pigment YH-5707 Fanchon) or Fast Yellow 4RLF dye, both of which have an azo component and a methylene component and are further characterized since they have a melting point of at least 167 ° C (332.6 ° F), a degree of solubility in water at a water temperature of about 93.33 to about 218.33 ° C (200 to about 425 ° F), and a degree of solubility in kerosene at a temperature of about 93.33 ° C to about 218.33 ° C (200 ° F to about 425 ° F). In U.S. Patent No. 6,367,548, Purvis et al. , discloses methods and compositions for stimulating multiple intervals in underground wells by treatment fluids of diversion wells at multiple intervals. According to the specification, this is completed by alternatively displacing the bypass agent from the annulus of the borehole to an underground formation and displacing the treatment fluid from a pipe string to the underground formation. Other methods for the derivation of a fracture treatment include the limited entry technique described by LaGrone, et al. , SPE 530, pp. 695-702 (1963), and the Multiple Fracture Fracture Technique Using a Derivative Agent (TMFUD) suggested by Dingxiang, et al. , SPE 30816, pp. 80-86 (1988), the last of which has shown an average oil production improvement of 15.0 t / d for each well, and a cumulative production improvement of 340.3 x 104 tons. A derivative agent based on viscoelastic surfactant has also been described for use in acid stimulations (Alleman, D., et al., SPE 80222 (2003)), which is a VES gel (polyQuat) characterized by a stable vesicular structure. at high pH and a thermal stability of approximately 121.11 ° C (250 ° F). This agent of Gel-type shunt is typically pumped into an underground formation prior to a well stimulation fluid to hermetically seal the high permeability ranges and derive the well treatment fluid at low permeability intervals. In light of all these advances and new techniques, the derivation action of derivative agents is often difficult to predict and monitor, and may not be successful in diverting the treatment fluid to all desired ranges, thus failing to not allow the maximum benefit of the fracture procedure. These problems can be aggravated more in open hole completions, especially in highly deviated terminations that have large areas of an open formation to the sounding. The presence of natural fractures within the underground formation can also • serve to make the derivation more challenging. Thus, there is a need for new compositions and methods for deriving well treatment fluids at multiple intervals of variable permeability within an underground formation. BRIEF DESCRIPTION OF THE INVENTION The present invention provides a method of using particles that have an outer coating soluble as derivatizing agents in underground formations. He Soluble outer coating will dissolve after a desired period of time at the temperatures and pressures of the bottom of the hole in the presence of fracture fluids of the bottom of the hole and fracture compositions. Examples of the soluble outer coating include collagen, poly (alkylene) oxide polymers, poly (lactic acid), polyvinylacetate, polyvinyl alcohol, polyvinylacetate / polyvinylalcohol, polylactone, polyacrylate, latex, polyester, group I or II silicate polymers or mixtures thereof. The present invention provides water soluble polymer coated binding materials as derivatizing agents and methods of using such derivatizing agents to treat an underground formation. The bypass agent together with a carrier liquid are introduced into an underground formation. The liquid carrier flows to fractures and / or intervals within the underground formation. Fractures or intervals have varying degrees of permeability. In accordance with the methods of the present invention, the liquid carrier with the derivatizing agent will flow into the first most permeable range. The formation temperature will cause the water-soluble polymer coating of the derivatizing agent to soften and swell, thereby sealing the fracture.

In one embodiment, a convenient bypass agent is described for deriving well treatment fluids into a single or multiple range, wherein the bypass agent is comprised of a substrate of particles and a water soluble outer layer. Such a water-soluble outer layer polymer is exemplified, without limitation, by collagen, poly (alkylene) oxide polymers, poly (lactic acid) polyvinylacetate, polyvinylalcohols, polyvinylacetate / polyvinylalcohol, polymeric lactones, water-soluble acrylics, latex, polyester, group I or II silicate polymer, and mixtures thereof. In a further embodiment, a suitable bypass agent is disclosed for deriving the well treatment fluids into a single or multiple range, wherein the bypass agent is comprised of a particulate substrate, an intermediate water-insoluble layer and a external polymer soluble in water. The polymer of the water-soluble outer layer is exemplified, without limitation, by collagen, polymer of oxides (of alkylene), poly (lactic acid), polyvinylacetate, polyvinylalcohols, polyvinylacetate / polyvinylalcohol, polymeric lactones, water-soluble acrylics, latex, polyester, group I or II silicate polymers and mixtures thereof. The water-insoluble intermediate layer is exemplified by polymers novolac of phenol -aldehyde and polymers resole of phenol -aldehyde. In another embodiment, a convenient derivatizing agent is described for deriving the well treatment fluids in a single or multiple range within a sounding, wherein the derivatizing agent is substantially a water soluble polymer particle such as a count of collagen or granular particles of poly (alkylene) oxide polymer, poly (lactic acid), polyvinylacetate, polyvinylalcohol, polyvinylacetate / polyvinylalcohol, polymeric lactones, water-soluble acrylics, latex, polyester, group I or II silicate polymer, or mixtures thereof. In another embodiment, a method of stimulating individual ranges of underground formation is disclosed, the method including the steps of introducing a derivatizing agent having a water-soluble component in its outer layer into an internal pipeline of a borehole in combination with a low viscosity fluid or a fracture fluid; displacing the derivatizing agent and the fracture fluid into the underground formation, allowing the derivatizing agent to progressively seal portions of the formation to be treated; and repeat the process as necessary, add the bypass agent to the carrier fluid in plugs during the fracture operation. DESCRIPTION OF THE FIGURES The following figures are part of the present specification and are included to show certain aspects of the present invention. The invention can be better understood by reference to one or more of these figures in conjunction with the detailed description of the specific embodiments presented herein. FIG. 1 shows a cross-sectional elevation view of a portion of the bottom of the hole of an underground formation having a vertical casing and a single treatment interval, where the variably coated bypass agents are injected into the formation containing the hydrocarbons according to one aspect of the present disclosure. Fig. 2 illustrates the cross-sectional elevation view of the underground formation of FIG. 1, where consolidating materials being injected into a hydrocarbon-containing formation have derivatized agents of the present invention injected. FIG. 3 shows a well with vertical tubing and multiple treatment intervals 58, 60 and 62 and agents of shunts coated in a variety of ways that are injected, according to one aspect the present disclosure. DEFINITIONS The following definitions are provided to assist those skilled in the art to understand the detailed description of the present invention. The term "carrier liquid" as used herein refers to oil-based or water-based liquids that are capable of moving particles (eg, consolidants) that are in suspension. The low viscosity carrier fluid has less transport capacity and the particles can be affected by gravity so that they emerge if they are less dense than the fluid or submerge if they are denser than the fluid. High viscosity liquids can transport particles with less sedimentation or rises since the viscosity overcomes the effects of gravity. The term "crosslinker" or "crosslinking agent," as used herein, refers to those compounds used to modify proteins covalently, such as collagen, and includes homobifunctional crosslinkers containing two identical reactive groups, and homobifunctional crosslinkers containing two different reactive groups. The term "derivatizing agent", as used herein, generally means and refers to an agent that functions to prevent, either temporarily or permanently, the flow of a liquid to a particular location, usually located in an underground formation, where the agent serves to seal the location and thereby cause the liquid to "drift" to a location different The term "consolidating", as used herein, refers to those sized particles that are used in well examinations and treatments, such as hydraulic fracture operations, to support open fractures following treatment. Such sized particles are often mixed with the fracture fluid (s) to sustain open fractures after a hydraulic fracture treatment or well treatment at the bottom of the similar hole. In addition to grains of sand and walnut crust that occur naturally, the term "consolidating" includes man-made or specially engineered consolidants such as resin-coated sand or high-strength ceramics such as sintered bauxite. The resin-coated consolidants are typified by those that are coated with phenol-aldehyde novolac polymers or phenol-aldehyde resole polymers. Typically, but not necessarily, consolidating materials are carefully classified by size and sphericity to provide an efficient conduit for the production of the fluid from the deposit to the borehole. In embodiments described and disclosed herein, the use of the term "introduce" includes pumping, injecting, pouring, releasing, displacing, staining, circulating, or otherwise placing a fluid or material into a well, borehole, or underground formation using any convenient shape known in the art. Similarly, as used herein, the terms "combine", "contact", and "apply" include any convenient method known to mix, expose, or otherwise cause two or more materials, compounds, or components to go together in a manner sufficient to cause at least the partial reaction or other interaction to occur between the materials, the compounds, or the components. The term "water soluble" as used herein refers to resins, polymers, or coatings which are stable (do not dissolve) under surface conditions, environment, but which are soluble after a given time (generally for several hours) or several days) when placed in an underground environment. The term "treatment", as used herein, refers to any of the numerous operations on or in the well at the bottom of the borehole, borehole, or deposit, including but not limited to a type of examination treatment, a type of treatment stimulation, such as a hydraulic fracture treatment or an acid treatment, isolation treatments, control of tank fluid treatments, or other types of treatment. remedial treatments carried out to improve the operation and the total productivity of the well. The term "stimulation" as used herein, refers to the operations of improving or restoring productivity in a well as a result of a treatment of hydraulic fracture, acid fracture, acidification of matrix, sand, or other type of treatment intended to increase and / or to maximize the production rate of the well or its duration, often increasing the highly conductive flow paths of the deposit. DETAILED DESCRIPTION OF THE INVENTION In embodiments of the disclosed derivatizing agent, the single and multiple intervals of an underground formation can be treated or stimulated in stages by successively introducing the derivatizing agent comprising a particulate substrate and an exterior coating slowly soluble in water comprising Collagen or a combination of collagen and a material that is not collagen slowly soluble in water.

The invention provides compositions of particles comprising coatings of soluble materials comprising collagen, as well as processes for preparing such compositions. These compositions are useful in the underground formations to derive the well treatment fluids in a simple range to increase the fracture length or at multiple intervals of an underground formation having permeability and / or injectivity or variable injection capacity during an operation of hydraulic fracture. Using the bypass agents of the present invention in fracture processes, the consolidant (or particle substrate) coated with a slowly water soluble coating such as a collagen alone or in combination with a non-collagenic, water soluble plastic coating material , acts to derive the fracture, while the coatings on the consolidants act by defining the limits of the initial fracture. Following the fracture treatment, the coating can be removed due to the slow dissolution characteristics of the coating, leaving standard consolidation agents with high permeability to flow into the fracture and act as consolidants. While the compositions and methods are described in terms of "comprising" various components or steps, the Compositions and methods may also "essentially consist of" or "consist of" the various components and steps. A. Substrate Particulate or particulate material, also referred to herein as a substrate material, suitable for use with the present invention includes a variety of particulate materials known to be convenient or potentially convenient consolidating agents which may be employed in operations in the bottom of the hole. According to the present invention, particulate material (or substrate material) which can be used includes any suitable consolidating agent for hydraulic fracturing known in the art. Examples of such particulate materials include, but are not limited to, natural materials, silica consolidants, ceramic consolidants, metallic consolidants, synthetic organic consolidants, mixtures thereof, and the like. Suitable natural products for use as consolidating materials include, but are not limited to, walnut shells such as, Brazil nut, and macadamia nut, in addition to fruit bones such as peach bones, apricot kernels, olive stones. and any impregnated resin or coated resin version thereof. Typical resin coatings or impregnations include bisphenols, bisphenol homopolymers, mixtures of bisphenol homopolymers with phenol-aldehyde polymer, bisphenol-aldehyde resins and / or polymers, phenol-aldehyde polymers and homopolymers, modified and unmodified resols, phenolic materials including arylphenols, alkylphenols, alkoxyphenols, and aryloxyphenols, resorcinol resins, epoxy resins, novolak polymer resins, novolak bisphenol-aldehyde polymers, and waxes, as well as the precured or curable versions of such resin coatings. Suitable silica consolidants for use with the present invention include, but are not limited to, crystal spheres and glass microspheres, glass beads, silica quartz sand and sands of all types such as white or brown. Typical silica sands suitable for use include Nordic white sands (Fairmount Minerals, Chardon, OH), Ottawa, Jordan, Brady, American walnut, Arizona, St. Peter, Wonowoc, and Chalfort, as well as any resin coated version of these sands. In the case that silica fibers are used, the fibers can be straight, curved, wavy, or spiral, and can be of any degree, such as E-grade, S-grade, and AR-grade. Examples of resin-coated silica consolidants suitable for use with the present invention include consolidants deformables such as the FLEXSAND LS ™ and FLEXSAND MS ™ (available from BJ Services, Inc., Houston, TX) and tempered Tempered HS®, Tempered LC®, Tempered DC®, and Tempered TF®, all available from Santrol, Fresno, TX. Suitable ceramic consolidants for use with the methods of the present invention include, but are not limited to, ceramic beads; spent fluid thermal cracking catalysts (FCC) such as those described in US Patent No. 6,372,378 which is incorporated herein in its entirety; ultra-light weight porous ceramics; economical lightweight ceramics such as "ECONOPROP ™" (Carbo Ceramics, Inc., Irving, TX); lightweight ceramics such as "CARBOLITE ™"; intermediate strength ceramics such as "CARBOPROP ™" (available from Carbo Ceramics, Inc., Irving, TX); high-strength ceramics such as "CARBOHSP ™" and "sintered bauxite" (Carbo Ceramics, Inc., Irving, TX), and HYPERPROP G2 ™, DYNAPROP G2 ™, or OPTIPROP G2 ™ encapsulated, curable ceramic consolidants (available from Santrol, Fresno, TX) as well as any version coated with resin or impregnated with resin, such as those described above. Convenient metallic consolidants for use with the embodiments of the present invention include, but are not limited to, spherical metallic particles or shot pellets. aluminum, aluminum pellets, aluminum needles, aluminum wire, iron shot, steel shot, and the like, in addition to any resin-coated version of these metallic consolidants. Synthetic binders are also suitable for use with the present invention. Examples of suitable synthetic consolidants include, but are not limited to, plastic beads or beads, nylon beads, nylon pellets, SDVB beads (benzene divinyl styrene), carbon fibers such as PANEX ™ carbon fibers from Zoltek Corporation ( Van? Uys, CA), and resin agglomerate particles similar to "FLEXSAND MS ™" (BJ Services Company, Houston, TX), as well as resin coated versions thereof. Additionally, it is also envisioned that soluble materials suitable for use as consolidants will be useful with the methods of the present invention. For example, soluble solids that are put into the channels of the created perforations include, but are not limited to, marble or limestone marbles or some other suitable carbonate particulates. Additionally, wax, plastic, resin, coated or uncoated particles which are soluble through contact with treatment chemical or which can melt and flow back from the Fractures are convenient for use as consolidants with the present invention. Conveniently with the present invention, consolidating agents are typically used in concentrations of about 1 to about 18 pounds per gallon (about 120 g / l to about 2,160 g / l) of the fracture liquid composition, but more concentrations can also be used. high or lower if required. Similarly, the particulate substrate suitable for use with the present invention has a particle size in the range of US Standard Test mesh numbers of from about 4 to about 200 (i.e., mesh apertures of about 0.4572 mm to about 0.00762 mm (0.18 inches to about 0.003 inches)). More particularly, suitable particle substrate sizes for use with the present invention include size ranges from about 4 meshes (4750 microns) to about 200 meshes (75 microns). Also suitable for use with the present invention are particulate materials or consolidants having size designations of 6/12, 8/16, 12/18, 12/20, 16/20, 16/30, 20/40, 30 / 50, 40/70 and 70/140, although any desired size distribution, such as 10/40, 14/20, 14/30, 14/40, 18/40, and the like, as well as any combination of the same1 (for example, a mixture of 10/40 and 14/40). The preferred mesh size, according to the present invention, is the 20/40 mesh. B. Soluble Coating The soluble coatings used in accordance with the present invention can be any number of known soluble agents that are slowly soluble in underground formations at the bottom of the bore, over a period of time. The soluble polymer materials used in accordance with the present invention must be soluble (ie, capable of dissolving in) in brines, water, oil, organic solvents, acidic or acidic media, and / or in fluids having a pH in the range from approximately 1 to approximately 14, in addition to mixtures thereof under the conditions found in the underground formation at the bottom of the borehole. Preferably, the soluble coating is a structural protein such as collagen or atelocollagen, a vegetable protein such as that found in wheat, corn, oats or almonds, or a collagen that originates from a marine environment. The last type of collagen can be extracted from fish, algae, plankton, micro-plankton, and the like. More preferably, the soluble coating is collagen, including Type I collagen, Type II collagen, collagen of Type III, Type IV or Type V collagen, in addition to combinations thereof. More preferably, according to the present invention, the soluble coating is a Type I collagen or an atelocollagen. Suitable Type I collagens or atelocologens for use as soluble coatings according to the present invention are those collagens that contain at least one hydroxyproline residue. Such collagens or atelocollagen type I include collagens found in tendons, skin, bone, scar tissue, and the like, such as tropocollagen, in addition to products derived from the controlled, enzymatic or chemical reduction of collagen proteins. Such collagens preferably have a molecular weight of from about 10,000 Daltons to about 500,000 Daltons, and more preferably from about 100,000 Daltons to about 300,000 Daltons. Suitable molecular weights of approximately 100,000 Daltons, 125,000 Daltons, 150,000 Daltons, 175,000 Daltons, 200,000 Daltons, 225,000 Daltons, 250,000 Daltons, 275,000 Daltons, 300,000 Daltons, in addition to molecular weights between any two of these values, for example, collagens having a molecular weight of about 225,000 to about 275,000 Daltons. For example, a preferred Type I collagen suitable for use with the present invention is tropocollagen with a molecular weight of approximately 250,000 as that provided by Milligans and Higgins, Inc. (Johnstown, NY). Convenient collagens for use in the present invention have Bloom strengths of about 7.03 kg / cm2 (100 psi) at about 63.27 kg / cm2 (900 psi), and more preferably about 21. 09 (300) psi at about 49.21 kg / cm2 (700 psi). More preferably, suitable collagens for use with the present invention have Bloom strengths of about 28.12 kg / cm2 (400 psi) to about 42.18 kg / cm2 (600 psi). Suitable Bloom resistances, according to the present invention, are approximately 28.12 kg / cm2 (400 psi), approximately 28.82 kg / cm2 (410 psi), approximately 29.52 kg / cm2 (420 psi), approximately 30.23 kg / cm2 (430 psi), approximately 30.93 kg / cm2 (440 psi), approximately 31.63 kg / cm2 (450 psi), approximately 32.34 kg / cm2 (460 psi), approximately 33.04 kg / cm2 (470 psi), approximately 33.74 kg / cm2 (480 psi), approximately 34.45 kg / cm2 (490 psi), approximately 35.15 kg / cm2 (500 psi), approximately 35.85 kg / cm2 (510 psi), approximately 36.56 kg / cm2 (520 psi), approximately 37.26 kg / cm2 (530 psi), approximately 37.96 kg / cm2 (540 psi), approximately 38.66 kg / cm2 (550 psi), approximately 39.37 kg / cm2 (560 psi), approximately 40.07 kg / cm2 (570 psi), about 40.77 kg / cm2 (580 psi), about 41.48 kg / cm2 (590 psi), and about 42.18 kg / cm2 (600 psi), in addition to Bloom strengths between two of any of these values, for example of about 28.12 kg / cm2 (400 psi) to about 36.56 kg / cm2 (520 psi), such as 35.99 kg / cm2 (512 psi). Bloom Resistance, as used herein, refers to the measured value of the strength and / or stiffness of a gelatinous substance, such as collagen, formed by a standard solution of defined concentration that has been held at a constant temperature for a period of time. specific time, in accordance with standard bloom test procedures, such as BS757: 1975, GMIA Test Standard B5757, International Standard IS09665 for testing adhesive animal adhesives, or similar standards as described in "Official Methods of Analysis of AOAC INTERNATIONAL ( OMA), "17th edition, Volume II, AOAC International Publications (2003). Bloom bloom values are typically given in "pounds per square inch" (psi) or grams, which reflect the force required to knock down a chosen area of the sample surface at a distance of 4 mm. In a typical procedure, a gel product, such as collagen or gelatin, is formed at a specific consistency (eg, a 6 and 2/3% solution) and maintained at a constant temperature in a water bath.

Constant temperature at 10 C for 18 hours. A device called Texture Analyzer (for example, the Texture Analyzer TA.XT2Í, Scarsdale, NY) then measures the weight in grams (or the pressure in psi) required to knock down an AOAC® gelometric immersion (Association of Official Analytical Chemists) standard that has a lower 4 mm edge, pointed, on the gel; alternatively, an immersion BS may be used, which has a bottom edge rounded to a radius of 0.4 mm as the immersion. For example, if this procedure requires 200 grams to lower the dipper, then the gelatin has a strength of 200. Suitable Type I collagens for use with the present invention have a sieve distribution / size designation of 6/12, 8 / 16, 12/18, 12/20, 16/20, 16/30, 20/40, 30/50, 40/70 and 70/140, in addition to sieve distributions between any two of these designations, although it can be used any size distribution desired, such as 8/40, 10/40, 14/20, 14/30, 14/40, 18/40, and the like, in addition to any combination thereof (e.g. a mixture of 10 / 40 and 14/40). The preferred mesh size, according to the present invention, is 8/40 mesh. Collagen as used herein as soluble coatings, can be either crosslinked, non-crosslinked or a combination of both, and the type and degree of crosslinking will depend on the specific application of the soluble collagen-based coating. There are four fundamental strategies for fixing collagen materials and materials constructed from processed collagen fibers or purified collagen. These include exogenous chemical crosslinking using agents that covalently couple neighboring collagen fibrils using reactive radicals directed to the target in the fibrillar collagen system and the crosslinking molecules themselves; physicochemical crosslinking techniques such as photo-oxidation, microwave irradiation, dehydration and dehydrothermal treatment that covalently bind the collagen fibrils via the side chains of reactive amino acids that occur naturally; chemical catalysis of intramolecular crosslinks between amino acid side chains in the collagen fibrils; and polymerization of compounds mixed with collagenous assemblies and formation of non-covalent or polymeric covalent interactions that do not chemically react with the collagens fibrils [Koob, TJ, "Collagen Fixation", in Encyclopedia of Bioma terials and Biomedical Engineering, nek, GE, Bowlin , GL, Eds., 2004]. According to the present invention, the collagen used as a soluble coating is preferably crosslinked using crosslinking techniques chemistry. These include, but are not limited to, aldehyde-based crosslinking techniques, crosslinking techniques based on polyepoxy compounds, the use of isocyanates, crosslinking of the carbodiimide, crosslinking based on acyl azide. More preferably, the collagen is crosslinked using crosslinking techniques based on añdehydes, such as for example using glutaraldehyde or formaldehyde. The aldehyde-based crosslinking techniques include those techniques that use a reagent containing two groups of reactive aldehydes to form covalent crosslinks between neighboring collagen proteins, especially the e-amino groups of lysine residues in the collagen [Khor, E. , Bioma terials, Vol. 18: 18; pp. 95-105 (1997)]. Suitable aldehydes for use with the present invention include but are not limited to glutaraldehyde, formaldehyde, propionaldehyde and butyraldehyde. The techniques and crosslinking based on polyepoxy and agents include the use of compounds, such as short, branched polymers, which end in reactive epoxy functionalities. Suitable polyepoxy compounds for use as crosslinking agents in the present invention include but are not limited to glycerol ethers, glycol, and polyglycidyl glycerol ethers.

The isocyanates are also suitable for use as crosslinking agents in the present invention. Generally, isocyanates (R-NCO) react with primary amines to form a (R-H-CO-NH- -R) urea linkage; therefore, difunctional isocyanates have the ability to cross-link collagen via their lysine side chains. Suitable isocyanates for use as crosslinking agents in the present invention are preferably the diisocyanates, including biphenyl diisocyanate, dimethoxy-4,4'-biphenyl diisocyanate, dimethyl-4,4'-biphenyl diisocyanate, 1,3-bis ( isocyanatomethyl) benzene, phenyl diisocyanate, toluene diisocyanate, tolylene diisocyanate, diisocyanate hexane, diisocyanate octane, diisocyanate butane, isophorone diisocyanate, xylene diisocyanate, hexamethylene diisocyanate, octamethylene diisocyanate, phenylene diisocyanate, and poly (hexamethylene diisocyanate). Preferably, the isocyanate used as a crosslinking agent of the collagen molecules of the present invention is hexamethylene diisocyanate. Carbodiimide crosslinking agents and techniques may also be used within the scope of the present invention. These agents react with the carboxyl groups of side chains of aspartic and glutamic acid within the collagen to form isocylurea derivatives / iso-peptides bonds [Khor, E., ibid.] Carbodiimides suitable for use as crosslinking agents with the collagen of the present invention, include but are not limited to N, N'-dicyclohexylcarbodiimide (DCC); N, N '-diisopropylcarbodiimide (DEC); N, N'-di-tert-butylcarbodiimide, l-ethyl-3- (3-dimethylaminopropyl) carbodiimide (EDC; EDAC), water-soluble EDC (WSC); l-tert-butyl-3-ethylcarbodiimide; 1- (3-dimethylaminopropyl) -3-ethylcarbodiimide; bis (trimethylsilyl) -carbodiimide; 1,3-bis (2,2-dimethyl-1,3-dioxolan-4-ylmethyl) carbodiimide (BDDC, as described in U.S. Patent No. 5,602,264); N-Cylcohexyl-N '- (2-morpholinoethyl) carbodiimide; N, N'-diethylcarbodiimide (DEC); l-cyclohexyl-3- (2-morpholinoethyl) carbodiimide methyl-p-toluenesulfonate [e.g., Sheehan, J.C., et al. , J. Org. Chem. , Vol. 21: pp. 439-441 (1956)]; oligomeric alkyl cyclohexylcarbodiimides, such as those described by Zhang, et al. [J. Org. Chem., Vol. 69; pp. 8340-8344 (2004)]; Polymer bond DDC; and polymer bond EDC such as cross-linked N-ethyl-N '- (3-dimethylaminopropyl) carbodiimide in JANDAJEL ™.

Additionally, N-hydroxysuccinimide can be used (NHS), l-hydroxy-7-azabenzotriazole (HOAt) or similar reagents in conjunction with carbodiimide to minimize internal rearrangement of the activated isocylurea derivative and to provide more efficient crosslinking. With respect to the carbodiimide treatment, the acyl azide crosslinking agents produce covalent linkages between the carboxylic acid side chains of glutamic and aspartic acids and the e-amino groups of the collagen lysines (Petit, H., et al. J. Biomed, Mater. Res., Vol. 24: pp. 179-187 (1990) Following the esterification of the carboxyl groups in which a methyl group is added to the acid, the biomaterial is treated with hydrazine to form the corresponding hydrazine, then sodium nitride is added to react with the hydrazine and form the acyl azide.In this method any number of hydrazines known in the art may be used, including the hydrazine of maleimidopropionic acid (MPH). chemical crosslinking suitable for use in the present invention to provide cross-linked collagen molecules which act as soluble coatings on the co-material particles nsolidation include but are not limited to homobifunctional crosslinkers such as BMME, BSOCOES, DSP (a thio-cleavable crosslinker), DSS, EGS, water soluble EGS, and SATA, as well as heterobifunctional crosslinking agents including GMB, MBS , PMPI, SMCC, SPDP, and MPH (acid hydrazine maleimidopropionic), MCH, EMCH (hydride of maleimidocaprionic acid), KMUH (hydrazide of N- (k-maleimidoundecanoic acid)), and MPBH (hydrazide of 4- (4-N-MaleimidoPhenyl) butyric acid), all available from Interchim (Cedex, France). Other convenient techniques for crosslinking the collagen fibers for use as soluble consolidation coatings include but are not limited to dehydration, UV irradiation at 254 nm, glucose-mediated crosslinking (glycation) in conjunction with UV irradiation, and biological cross-linking. . The above techniques include the use of natural products such as genipin and its related iridoid compounds which are isolated from the fruits of the gardenia plant (Gardenia jasminoides), which are dialdehydes in aqueous solution and whereby they can react with the groups e-amino in the side chains of the lysine of the neighboring collagen molecules to provide cross-linking. Other suitable biological crosslinking systems for use with the present invention include catechol-tannone tanning systems, such as 3,4-dihydroxythiramine, and nordihydroguaiaretic acid (NDGA), isolated from the creosote bush, which acts as an agent of cross-linking via the two catechols in NDGA (Koob, T.J., Comp. Biochem. Physiol. , Part A, Vol. 133: pp. 1171-1192 (2002)). Coatings slowly soluble in water in the particle substrates, according to the present disclosure, can also be non-collagenic materials such as synthetic polymers that are slightly soluble in water. Such non-collagenic materials include but are not limited to: polyethylene oxides, polypropylene oxides, polycaprolactones; polyethylene / polypropylene grafts and polycaprolenes; grafts of polyethylene / polypropylene oxides and polycaprolactones; acrylics soluble in water or reducible in water; reducible phenoxy resins in water; latex; polyesters, soluble block copolymers, polyvinyl alcohol (PVA) grafts and polyvinyl acetates; polylactides and derivatives of polylactic acid, polyglycolic acid (PGA); polyglycollactic acid; (PGLA). Also useful for a water-soluble coating are elements of the periodic table of group I or II (alkali metal or alkaline earth metals), silica polymers, eg SOLOSIL ™ (Foseco International, Ltd., Great Britain), a polymer of sodium silica. C. Method of Use In modalities of the disclosed method, single or multiple intervals of an underground formation may be treated or stimulated in stages by successively introducing a derivatizing agent of the present invention into formation followed by the introduction of the well treatment fluid into the formation. As used herein, "borehole" includes sections of the cased and / or open hole in a well, it is understood that a borehole may be vertical, horizontal, or a combination thereof. The term "pipe string" refers to any convenient conduit for the placement and transportation of fluids to a borehole including, but not limited to, a work string, drill pipe, rolled pipe, etc. In addition, it will be understood with benefit to this disclosure that the disclosed bypass agents and bypass treatment techniques are suitable for use with any type of well treatment fluid including, but not limited to, acid treatments, treatments with condensates, hydraulic fracture treatments, and their like. In addition, it will be understood that the benefits of the disclosed methods and compositions can be realized with well treatments performed below, at or above a fracture pressure of a formation. First: THE USE OF THE POLLING WELL: In this aspect of the invention, the use of fully soluble particles in the borehole (such as collagen) is disclosed. water-soluble polymer plastics or mixtures thereof) to derive fluid flow from one area to another and subsequently dissolve). The use of collagen (in both forms, crosslinked and non-crosslinked) and soluble plastics are useful in bypassing the flow of fluids in the well. These bypass materials should be in the mesh size range of 1 to 100, preferably of mesh size of 4 to 50 and can be used in combination with other additives or plastic materials to reinforce the performance by diverting the flux from the fluids. zone to another. These materials have been used as bypass ball sealants but recent tests have shown that the material can be used as a bypass agent to prevent fluid from flowing to one zone to another either of greater pore pressure or lower permeability . The present invention provides a method of treating a cased borehole to derive the flow of fluids from one zone to another. The method involves pumping a bypass fluid that is made of an aqueous carrier liquid having dispersed therein a particulate form of a water soluble polymer and where the particulate polymer has a density greater than or equal to less than the density of the carrier liquid. While the bypass fluid is pumped into the well The polymer in the form of particles sediments in areas of the borehole and through this drifts the flow of a treatment fluid from one area to another. Generally, the treatment fluid is diverted or blocked from the flow to a zone of greater pore pressure or lower permeability. In the methods of this invention which relates to the use of the borehole, the water soluble particulate polymer is collagen, poly (alkylene) oxide, poly (lactic acid), polyvinylacetate, polyvinylalcohol, polyvinylacetate / polyvinylalcohol, polylactone. , polyacrylate, latex, polyester, silicate polymer of elements of the periodic table of group I or II (alkali metal or alkaline earth metals) or mixtures thereof. Typically, the particulate polymer is present in the carrier liquid in an amount of about 1.1984xl0"4 kg per liter (0.001 pounds per gallon) to about 1.1984 kg per liter (10 pounds per gallon) of the carrier liquid. The particulate polymer is comprised of varying densities greater or less than the density of the carrier fluid Typically, the carrier liquid is water, brine, aqueous acid solutions, or gelled acid solutions.

Second: USE OF GENERATED FRACTURE: In this aspect of the invention the use of particles coated with various consolidating agents (coated with any fully soluble collagen or a mixture of soluble and insoluble collagen or polymeric plastic materials) can be pumped into the fractured formations to prevent fractures from the derivation outside the production area. For example, a dense sintered bauxite particle with a soluble or partially soluble coating will fall to the bottom of the fracture and derive the fracture from the lower stratum or water zone. Also, a low density walnut wrap with a soluble or partially soluble coating will tend to rise within the fracture to derive the upward growth fracture in a gas or water zone. The coating may be either fully soluble or partially soluble since the consolidating material will remain at the fracture site and provide conductivity in the fracture after the fracture work is completed. Part of the coating on the consolidating material must be soluble but a mixture of both plastic and soluble and insoluble collagen is desirable to prevent movement of the consolidating agent in the fracture.

The use of bypass agents in fractures is that a consolidating or consolidating agent will be coated with a soluble or partially soluble coating - using a collagen and / or polymeric plastic coating material or any mixture thereof. The fracture will be derived using these soluble coatings on the consolidants as the boundaries of the initial fracture are defined. After the fracturing treatment the coating will disappear and the previously coated particles will return to the normal consolidating agents, which have high permeability. Coatings in variable density consolidants can cause fracture boundaries to be established early in the fracturing process since a low viscosity fluid will allow a high density coated consolidation material to settle or fall into the fracture to make a lower limit on the fracture and derive it out of the borehole to make a longer fracture and increase the productivity of the well. Similarly, a low density coated consolidant will tend to rise to the top of the growth fracture to form an upper limit and derive the growth fracture away from the upper zones that can damage the production of the well. With the fracture contained in the upper part and the bottom, the fracture can grow outward and a larger contained fracture will improve the potential productivity of the well. Figure 1 illustrates a well with a section of the vertical cased sounding well and a single interval formation to be treated according to one embodiment of the present disclosure. The well 10 of Figure 1 has a casing 12 extending from the head 11 of the well for at least a portion of its length and is cemented around the outer part with cement liner 14 to hold the tubing 12 in place and insulate the penetrated formation or intervals. The cement lining 14 extends upwardly from the bottom of the borehole in the annulus between the outside of the casing 12 and the inner wall of the borehole at least a point above the formation 18 that produces the stratum. / that contains the hydrocarbons. The reasons for the inclusion of this coating are many, but essentially the cement lining 14 helps to ensure the integrity of the borehole (ie, so that it does not collapse), or to isolate specific, different geological zones (i.e. , an area that contains the oil of an area (undesirable) that produces water). The borehole is also optionally equipped with a casing or a lining shoe 16 in order to help direct the string 12 of tubing passing live rock or obstacles during its placement in the borehole. For the hydrocarbons in the production stratum 18, it is necessary to establish fluid communication between the production stratum 18 and the interior of the casing 12. This is complemented by perforations 15 made through the casing 12 and the cement casing 14 by means known per se. those of ordinary experience in art. Such means include, but are not limited to, punching guns, molded charging devices and phase charging devices, such as those described in U.S. Patent Nos. 6,755,249,5,095,099, and 5,816,343; Horizontally Oriented Drilling Systems (HOPS), such as those manufactured by Owen Oil Tubes, Ine, (Ft. Worth, TX); mechanical drilling devices such as laterally movable punches (U.S. Patent No. 2,482,913), needle punches drills, and sprocket drills such as those described in U.S. Patent No. 4,220,201; and obturators that can be sheared such as those described in US Patent No. 4,498,543. The perforations 15 form a flow path for the fluid from the formation to the casing 12, and vice versa.

The hydrocarbons flowing out of the production layers 18 through the perforations 15 and into the interior of the casing 12 can be transported to the surface through a production line 20. A production packer 22 can optionally be installed near the lower end of the production pipe 20 and above the larger bore 15 to achieve a pressure seal between the production pipe 20 and the pipe 12. Optionally, and equally acceptable in accordance with the present invention, the production pipes 20 are not necessary, in which case the total volume of the casing 12 is used to drive the hydrocarbons to the surface of the earth. When the bypass is necessary during a well treatment operation, the heavy weight consolidating bypass agents 26a and / or the light weight consolidating bypass agents 26b, both of which are substantially coated with a soluble coating in accordance with the present invention (i.e., have a coating containing collagen), are used to substantially seal the upper and lower sections of the production layer 18. This substantial seal, or boundary formation, occurs when the temporary bypass agents 26a and / or 26b are introduced into the tubing 12 at a predetermined time. during the treatment. When the bypass agents 26a and / or 26b are introduced into the fluid upstream of the perforated portions of the tubing 12, they are transported downstream of the production or tubing pipe 20 via the flow of the treatment fluid 24. Once the treatment fluid 24 reaches the perforated interval in the tubing, it flows externally through the perforations 15 and into the stratum 18 being treated. The flow of the treatment fluid 24 through the perforations 15 brings the temporary bypass agents 26a and / or 26b through the perforations and out of the stratum 18. At this point, the heavy weight consolidating bypass agents 26 have a density greater than that of the treatment fluid 24, settle at the bottom of the fracture created (as indicated by the arrows), forming a temporary "lower limit" between the fracture and, for example, a sand, shale or layer 19 of clay or other area which is desirable to hermetically seal the production stratum. Similarly, the light weight consolidating bypass agents 26a, which have a density less than that of the treatment fluid 24, rise to the top of the fracture created (as indicated by the arrows), forming by means of this other temporary "upper limit" between the fracture and an undesirable layer, such as a shale or a clay band of the stratum. Figure 2 illustrates the next step of this aspect of the present invention. Once the temporary bypass agents 26a and 26b are located at the top and / or at the bottom of the fracture created, respectively, the fluid flow velocity and the viscosity of the treatment fluid 24, which contains particles 28 In this way, the fracture can grow outward, away from the borehole (in the direction of the arrow) and thereby increase the total length of the fracture, helping by means to increase the simulation and / or longevity of the well. At the end of the well treatment, the soluble coating on the temporary bypass agents 26a and 26b will dissolve, allowing the particles of the remaining consolidation material to be removed with the treatment fluid 24 through the perforations 15, or remain and act as additional consolidants in consolidating the opening of the fractured strata. Figure 3 illustrates a further embodiment of the present invention. A well 50 having a vertical cased sounding well with a casing 54 extended from the head 52 of the well for at least a portion of the well length of the well. sounding, and a cement lining 56 extending upwardly from the bottom of the borehole in the annulus between the outside of the tubing 54 and the inner wall of the borehole, at least to a point above the existing stratum, similar to what is shown in FIGURE 1. Exposed within the section of the open hole of the borehole is an underground formation having multiple treatment intervals 58, 60 and 62. Although three separate intervals are illustrated in FIGURE 3, it will be understood with benefit from this disclosure that either of two treatment ranges can be treated up to any number of treatment intervals using the methods and compositions of the present disclosure. Furthermore, it will be understood that such treatment intervals may be disposed contiguously rather than separated by relatively impermeable areas such as schist fractures. Although FIGURE 3 illustrates a fully piped well, it will also be understood that the disclosed treatment methods can be used with virtually any type of completed borehole scenario. For example, the disclosed methods can be advantageously employed to treat well configurations including, but not limited to, vertical boreholes, fully-jacketed boreholes, horizontal boreholes, boreholes they have multiple sides, and sounding wells that share one or more of these characteristics. In FIGURE 3, treatment intervals 58, 60 and 62 represent identified ranges of an underground formation that has been identified for treatment. With respect to this, any number of intervals or only a portion of them present in the underground formation can thus be identified. Alternatively, such intervals may also represent perforated intervals in a cased sounding well. As shown in FIGURE 3, the perforations 66 extend through the tubing 54 and the cement liner 56 by means known to those skilled in the art, and in so doing form a flow path for the fluid from the formation towards the tubing 54 and vice versa. The hydrocarbons flowing out of the production stratum at intervals 58, 60 and 62 through the perforations 66 and into the tubing can be transported to the surface through the production pipe 64. In addition, and as illustrated in FIGURE 3, a production packer 68 can optionally be installed substantially near the lower end of the production pipe 64 and above the higher bore 66 to achieve a pressure seal between the pipe 64 of production and the tubing 54. The production pipe 64 does not need to be always used, and in those cases the total interior volume of the tubing 54 is used to drive the hydrocarbons to the surface of the wellhead 52. When the bypass is necessary during a well treatment, bypass agents 72 are used to substantially seal some of the perforations 66. The substantial seal occurs when flow is significantly reduced through a bore 66, as is often indicated by an increase in the borehole pressure as a bypass agent 72 blocks one or more bores 66. In accordance with this aspect of the present invention, it is preferred that the bypass agents 72 be substantially spherical in shape, although they can be used other geometries. Using the bypass agents 72 of the present invention to seal off some of the perforations 66 is supplemented by introducing the bypass agents 72 into the tubing at a predetermined time during treatment. When the bypass agents 72 are introduced into the fluid upstream of the perforated portions (66) of the tubing 12, they are transported downstream of the production line 64 or tubing 12 by a flow of the fracturing fluid 70. Once the fracturing fluid 70 reaches the perforated interval in the tubing, it flows out through the perforations 66 and into the treatment intervals 58, 60 and 62 that are being treated. The flow of fracturing fluid 70 through the perforations 66 leads the bypass agents towards the perforations 66 causing them to settle on the perforations. Once seated on the perforations 66, the bypass agents 72 are maintained in the perforations 66 by differential pressure of the fluid existing between the interior of the tubing 54 and the treatment intervals 58, 60 and 62 on the outside of the tubing 54. bypass agents 72 are dimensioned preferentially to substantially seal the perforations 66 when seated thereon. The seated bypass agents 72 serve to effectively close the perforations 66 to a time such that the differential pressure is reversed and the bypass agents are released, or until the bypass agents 72 are dissolved for a period of time due to the changes in its environment (for example, the introduction of water.) The bypass agents 72 will first tend to seal the perforations 66 through which the fracturing fluid 70 is flowing more rapidly.The preferential closure of the high speed perforations 66 flow tends to equal treatment of treatment intervals 58, 60 and 62 during the total perforated interval. For maximum settlement effectiveness on the perforations 66, the bypass agents 72 must have a density less than the density of the treatment fluid 70 in the borehole at the temperature and pressure conditions found in the perforated bottom area. of the perforation. Generally and in accordance with this aspect of the present invention, the derivatizing agent 72 will have at least one substantial outer surface comprised of collagen or a mixture of collagens. The number of derivation agents 72 necessary during a refurbishment or well treatment depends on the objectives and characteristics of the individual well and the stimulation treatment, and can be determined by someone skilled in the art. In the practice of the methods disclosed, the agent or convenient bypass means to achieve the derivation of the fluids towards the identified treatment ranges that is employed is the derivatizing agent of the present invention comprising a particulate substrate and an outer layer of collagen slowly soluble in water. In one embodiment, a neutrally buoyant variation of this collagen-containing derivation system can be employed in order to reduce the opportunity for segregation of the agent from derivation and the carrier fluid of the derivatizing agent in the form of particles. A "neutrally buoyant" bypass system is a system in which a bypass agent is suspended in the form of particles in a carrier fluid having specific gravity or density close enough to result in a mixture in which the solid components of the Bypass do not sediment or float substantially in the system under static conditions. Such segregation may result in, for example, accumulation of the derivatizing agent in one or more locations in the well of sounding and retention of the pipe string within the sections of the borehole. Further segregation may result in the loss of the bypass action due to the movement of the bypass agent away from the intervals to be treated. Neutrally buoyant bypass systcan be of particular advantage in highly deviated or horizontal wells, where gravity segregation of a non-neutrally buoyant bypass system can prevent efficient blockage or reduction in permeability of the total circumference of the face of the formation exposed in the borehole due, for example, to up or down migration of the bypass agent into the highly deviated or horizontal section of the borehole.

The derivatizing agents that may be employed include the derivatizing agents of the present invention, which have an exterior coating slowly soluble in water, alone or in combination with any derivatizing agent (eg, petroleum soluble, acid soluble, etc.). ) suitable for deriving the subsequent treatment fluids towards the intervals having lower injectability or injection capacity. A convenient derivatizing agent according to the present invention is a derivatizing agent which is substantially collagen. Examples of suitable derivatizing agents that may be combined with the derivatizing agent of the present invention include, but are not limited to, benzoic acid flakes, wax (such as "Divert VI" available from BJ Services), gilsonite or unitaite grade cement, polymers (including, but not limited to, natural polymers such as guar or synthetic polymers such as polyacrylate), rock salts, and the like. Other types of suitable derivatizing agents that may be employed include, but are not limited to, acid soluble derivatizing agents such as those described in U.S. Patent No. 3,353,874 and phthalimide particles such as those described in U.S. Patent No. 4,444,264. .

In one embodiment of the present invention, any type of carrier fluid having a convenient density can be used to form a neutrally buoyant bypass system, including natural or synthetic brines (such as water with KCl, etc.), and carrier fluids including gelation agents (such as normal or synthetic polymers) or other fillers known in the art. The cement grade gilsonite (also known as "Uintate") is a natural variety of asphalt that is crushed and classified into small sized particles. The composition of the derivatizing agent can be mixed at the well site with specific chemically modified fresh water (water containing for example, about 0.05% to about 1% of a wetting surfactant) to disperse the gonsonite and optionally, a bulking agent (which includes but is not limited to salts such as KCl, NH4C1, NaCl, CaCl2, etc.) to adjust the density and / or control the formation of clay, and a gelation agent (a polymer such as guar gum, hydroxy) propilguar, carboxy methylhydroxy proprilguar, carboxy methyl hydroxyethyl cellulose, xanthan gum, carboxy methyl cellulose, etc.) for adjusting viscosity and / or reducing drag. The derivatizing agent of the present invention is preferably present in the fluid carrier in concentrations from about 1.1984xl0 ~ 4 kg per liter to about 1.1984 kg per liter (0.001 pounds per gallon to about 10 pounds per gallon) of carrier liquid, but concentrations outside this range can also be used. The most preferred concentrations of the derivatizing agents are from approximately 1.1984x10"3 kg to approximately 0.7190 kg per liter (0.01 to approximately 6 pounds per gallon) of carrier fluid Concentrations of the derivatizing agent of less than approximately 1.1984x10 ~ 4 kg. per liter (0.001 pounds per gallon) will not easily clog or seal formations when used in carrier fluid volumes that are not normally available at an oil well site.A progressively larger volume of carrier fluid will be required to create fillings of suitable formation at concentrations of less than 1.1984x10 ~ 4 kg per liter (0.001 pounds per gallon). Concentrations of the derivatizing agent greater than about 10 pounds per gallon will not increase the derivation of the treatment fluid to an appreciable degree and therefore both are not particularly desirable in carrying out the present invention. It is basically composed of water, brine, saline acid solutions or gelled acid solutions. The acid solutions can be gelled with a cellulose, gums, polysaccharides, polyacrylamides, amines of alkoxylated fats and mixtures thereof. The derivatizing agent can be added while the treatment is started, continuously as the treatment fluid is pumped into the well bore or can be added at intervals in the carrier fluid between treatment steps. For example, in acidification processes the derivatizing agent can be added to the acidification fluid in a continuous manner. Thus, the derivatizing agent progressively closes portions of the formation that are treated, thereby frustrating the tendency of the acid to flow only in the more permeable portions of the formation and, instead, creating an eventually acidified formation. When the treatment fluid is pumped in stages, the first stage is followed by a volume of the bypass material composed of a carrier fluid, usually gelled or emulsified water or acid, containing the derivatizing agent. The bypass agent hermetically seals the portion of the formation penetrated by the treatment fluid treatment step. The second stage of the treatment fluid is then pumped to another portion of the formation. Alternative volumes of the treatment fluid and the bypass material can continue to be added to provide uniform formation acidified Although the same technique of continuously introducing the derivatizing agent into the carrier fluid for fracture treatments can be used, it is usual for the derivatizing agent to be added to the carrier fluid in plugs during fracture operations. A fracture fluid is known to flow preferentially to the portion of the underground formation which more readily accepts the liquid. After this portion of the formation is fractured, the bypass agent can be added to the fracture fluid so that it will seal the already fractured portion of the formation. Because the fracture fluid flows preferentially to the fracture zone, it will carry the bypass agent with it. By means of this the fractured zone is clogged and the fracture fluid is derived to the most permeable portion of the formation that still accepts fluid. This method of fracture and derivation may, in one aspect of the present invention, be repeated to obtain multiple fractures. The derivatizing agent is removed from the formation by means of sublimation of the derivatizing agent or by solubilization of the derivatizing agent by the fluids produced. The increase in the temperatures of the formation results in a higher dissolution or sublimation rate of the derivation agent. For example, it has been found that at approximately 121.11 ° C (250 ° F), approximately 80% by weight of collagen slightly soluble in water sublimes in 24 hours, while at 149 ° C (300 ° F), approximately 95% in sublimate weight in 24 hours and at a temperature of approximately 204 ° C (400 ° F), approximately 99% of the collagen slightly soluble in water sublimes / dissolves in about 24 hours. This shows that the rate of sublimation / dissolution of the derivatizing agent increases with the increase in the temperature of the formation. The following examples are included to demonstrate preferred embodiments of the invention. It should be appreciated by those skilled in the art that the techniques disclosed in the examples that follow represent techniques discovered by the inventors work well in the practice of the invention, and thus can be considered to constitute preferred modes for their practice. However, those skilled in the art should, in light of the present disclosure, appreciate that many changes can be made in the specific embodiments which are disclosed and still obtain an equal or similar result without departing from the scope of the invention. EXAMPLES Example 1: Prophetic example The following prophetic example describes a method of how the soluble coating can be used on the consolidating agent or agents of the present invention to derive the growth of the fracture and extend the fractures to the productive zone of an oil or gas well. The primary purpose of the soluble coated consolidator is to define an upper limit and a lower limit on the vertical fracture generated hydraulically so that the main direction of growth continues to extend outwards in length away from the borehole. This additional length of the conductive fracture helps to drain additional areas of productive formation, allowing to improve the production of oil, gas and / or water recovery and allowing to establish higher flow velocities as a result of greater fracture length. The following steps can be followed using the soluble coated binding materials of the present invention. 1. A fracture injection speed is established with a low viscosity fracture fluid. 2. A soluble coated binding agent is added, such as walnut shells coated with a cross-linked collagen, bauxite coated with cross-linked collagen, or a combination of both to the mixing tank to form a suspension in the fracture fluid. The fracture fluid containing the soluble coated consolidating agent is pumped to the bottom of the perforation. The first part of the suspension enters the initial fracture, taking most of the fluid. While this is being done, it slowly seals the boundaries of the fracture created due to the use of a soluble derivatizing agent, such as collagen, which softens and swells slowly in the fluid. Once the flow rate in the first fracture is decreased or substantially reduced, the pressure is increased until another flow path, fracture, or zone begins to take up the suspension containing the soluble coated consolidating agent. In case both, the upper part and the bottom of the fracture need to contain the soluble coated consolidation material, two different densities of the consolidation material are preferably used. For example, a particle of high density bauxite is coated with a soluble collagen coating that softens and swells slowly while remaining in the fracture to the bottom of the vertically created fracture. To retard the upward growth in vertical fracture, to the injection fluid is added a second low density consolidation material, such as a soluble coated walnut shell. While the injection fluid enters the formation, the consolidation material coated with soluble, low density material ascends in the vertical fracture and slows down fluid loss and growth in an upward direction. While the fracture is still being injected with the fluid above the fracture velocity and pressure, the fracture continues to grow away from the borehole and control of fracture growth is maintained by controlling the flow velocity of the fracture fluid. The injection is continued until the regular consolidation material fills the fracture, until the pressure reaches a pre-established limit or until the planned total volume is injected. In the formation standard coated, non-soluble consolidating materials, such as Ottawa Sand (20/40), ceramic, or any number of resin-coated consolidation materials, are injected, once the growth of the upper part is decreased and From the bottom. The pumping continues until the total amount of consolidation material (or materials from consolidation) is placed on the fractures created. 8. The well is plugged and the pumping equipment is removed. 9. The well is returned to production and the soluble collagen coating on the walnut or bauxite shells is removed as the water in the formation dissolves the soluble coating over the consolidation material over time. Example 2: Procedure for determining the speed and degree of dissolution of the polymer Sand substrate was coated with water soluble polymers: From here on, the following test procedure was used to determine the speed and the degree of solubility: Determine the total polymer mass on the sand by means of the regular LOl procedure. Add 500 grams of coated sand in 1 liter of water. Take a 400 mm filter paper and weigh it on an analytical balance up to four decimal places. Prepare vacuum filtration apparatus using 400 mm filter paper, perforated ceramic funnel, 2 liter Erlenmeyer flask with side opening connected to the vacuum pump by a rubber tube. Filter the coated sand and the water suspension through the 400 mm filter paper after each one minute interval. Remember to add the coated sand again in the filtered water. Remove the filter paper from the perforated funnel after the end of the filtration and let it dry by keeping it in desiccators. Weigh the filter paper. That is, the combined weight of the dissolved polymer and the filter paper, and thus it must be greater than the weight of the filter paper before being used in the filtration process. Calculate the% of dissolved polymer using the following formula: X = ((C-B) / A) JxlOO Where, X = the percentage of dissolved polymer A = mass (grams) of the polymer on the sand grains B = mass (grams) of the filter before the filtration process C = mass (grams) of the filter after the filtration process The results of this test procedure were that a polyethylene oxide (WSR 80 from Dow Chemical) reached total dissolution at 80 ° F in approximately 30 minutes, at 150 ° F this required approximately 180 minutes, and at 200 ° F it required approximately 90 minutes . The same test was performed using another polymer. These results showed that polypropylene oxide polymer (WSRN 750 from Dow Chemicals) reached full dissolution at 26.66 ° C (80 ° F) in approximately 390 minutes, at 65.55 ° C (150 ° F) it required approximately 320 minutes, and at 93.33 ° C (200 ° F) required approximately 245 minutes to completely dissolve. The polymers that swelled showed 100% solubility in 30 minutes, but the microscopic analysis showed retention in the filter paper because they swelled instead of dissolving. The formation of gelatinous mass and visible increase in the volume of the sand / water suspension indicates that swelling of the polymer instead of dissolution of the polymer. All compositions, methods and / or processes disclosed and claimed herein may be made and executed if undue experimentation in light of the present disclosure. While the compositions and methods of this invention have been described in terms of preferred embodiments, it will be apparent to those skilled in the art that variations can be applied to the compositions, methods and / or processes and in the steps or sequence of steps of the methods described herein without departing from the concept and scope of the invention. More specifically, it will be apparent that certain agents that are chemically and physiologically related can be substituted for the agents described herein while similar or the same results would be achieved. All substitutes and similar modifications apparent to those skilled in the art are considered within the scope and concept of the invention.

Claims

CLAIMS 1. A derivation material, characterized in that it comprises: a substrate of particles; and a water soluble polymer coating, wherein the water soluble polymer coating forms a substantial external coating on the particulate substrate.
2. The bypass material of claim 1, characterized in that the particulate substrate is selected from the group consisting of natural materials, silica consolidants, ceramic consolidants, metallic consolidants, synthetic organic consolidants, and mixtures thereof.
3. The bypass material of claim 1, characterized in that the particulate substrate is a resin-coated consolidant.
The derivative material of claim 1, characterized in that the water-soluble polymer is collagen, poly (alkylene) oxide polymer, poly (lactic acid), polyvinylacetate, polyvinylalcohol, polylactone, polyacrylate, latex, polyester, elements of the Periodic table of group I or II, silica polymers (alkali metals or alkaline earth metals) or mixtures thereof.
5. The derivative material of claim 1, characterized in that the particulate substrate has a particle size of about 3 mesh to about 200 mesh.
6. The bypass material of claim 4, characterized in that the collagen is type I collagen, collagen type II, type III collagen, type IV collagen or type V collagen.
7. The derivative material of claim 4, characterized in that the water soluble collagen is crosslinked with a crosslinking agent selected from the group consisting of aldehydes, carbodiimides, isocyanates, and acyl azides.
The bypass material of claim 1, characterized in that it further comprises a polymer that is not soluble in water in combination with the water soluble polymer coating.
9. The derivatizing material of claim 8, characterized in that the polymer that is not soluble in water is phenol-aldehyde novolac polymers and phenol-aldehyde resole polymers.
10. The derivative material of claim 1, characterized in that the water soluble polymer is poly (alkylene) oxide, poly (lactic acid), polyvinylacetate, polyvinyl alcohol, polyvinyl acetate / polyvinyl alcohol graft polymers or mixtures thereof.
11. The derivatizing material of claim 10, characterized in that the poly (alkylene) oxide is poly (ethylene) oxide, poly (propylene) oxide, poly (ethylene oxide) -poly (propylene oxide) block copolymers ), or mixtures thereof.
12. A bypass fluid for deriving oil well treatment liquids to progressively less permeable portions of an underground formation, said fluid characterized in that it comprises: an aqueous carrier liquid having dispersed therein a particulate bypass material of any claims 1-11.
13. The bypass fluid of claim 12, characterized in that the particulate bypass material comprises varying densities greater or less than the density of the carrier fluid.
14. The bypass fluid of claim 12, characterized in that the bypass material is present in the carrier liquid in an amount of about 1.1984 x 10"4 kg per liter (0.001 pounds per gallon) to about 1.1984 kg per liter ( 10 pounds per gallon) of the carrier liquid
15. The bypass fluid of claim 12, characterized in that the carrier liquid is water, brine, aqueous acid solutions, or gelled acid solutions.
16. A method of treating an underground formation during the fracture treatment in order to enhance the stimulation of the underground formation, the method characterized in that it comprises: pumping a derivative fluid of any of claims 12-15 into the underground formation; allowing the carrier liquid to impregnate in the formation to bring the bypass material into the underground formation; and allowing the bypass material to seal porous portions of the formations, thereby diverting the flow of the treatment fluid to less permeable portions of the formation.
The method of claim 16, characterized in that the formation has a temperature from about 23.88 ° C to about 204.44 ° C (75 ° F to about 400 ° F).
18. The method of claim 16, characterized in that the treatment of the underground formation is a fracture treatment, and wherein the increased stimulation is the length of the fractures.
19. A method of treating a piped well for diverting the flow of fluids from one zone to another, the method characterized in that it comprises: pumping in said well well a bypass fluid comprising an aqueous carrier liquid having dispersed therein a particulate form of a water soluble polymer, wherein the particulate polymer has a density greater than or less than the density of the carrier liquid; allow the particulate polymer to derive the flow of a treatment fluid from one area to another.
The method of claim 19, characterized in that the treatment fluid is diverted to flow into a greater pore pressure or lower permeability zone.
The method of claim 19, characterized in that the borehole has a temperature of about 23.88 ° C to about 204.44 ° C (75 ° F to about 400 ° F).
The method of claim 19, characterized in that the water-soluble polymer is collagen, (alkylene) oxide, poly (lactic acid), polyvinylacetate, polyvinylalcohol, polylactone, polyacrylate, latex, polyester, polyvinyl acetate / polyvinyl alcohol graft polymer. , silica polymer of elements of the periodic table of the Group I or II (alkali metals or alkaline earth metals), or mixtures thereof.
23. The method of claim 19, characterized in that the particulate polymer has a particle size of from about 3 mesh to about 70 mesh.
The method of claim 22, characterized in that the poly (alkylene) oxide is poly (ethylene oxide), poly (propylene oxide), poly (ethylene oxide) -poly (propylene oxide) block copolymers, or mixtures thereof.
25. The method of claim 19, characterized in that the particulate polymer is comprised of varying densities greater or less than the density of the carrier fluid.
26. The method of claim 19, characterized in that the particulate polymer is present in the carrier liquid in an amount of about 1.1984 x 10"4 kg per liter (0.001 pounds per gallon) to about 1.1984 kg per liter ( 10 pounds per gallon) of the carrier liquid
27. The method of claim 19, characterized in that the carrier liquid is water, brine, aqueous acid solutions, or gelled acid solutions.