RU2433157C2 - Deflecting fluid - Google Patents

Abstract

FIELD: mining. ^ SUBSTANCE: deflecting fluid for temporary sealing of the upper and lower parts of a treated interval in an underground formation by means of supply of the deflecting fluid into holes defined by a drill hole, being hydraulically connected with the treated interval, besides, the deflecting fluid includes a water bearing fluid, which substantially contains water, where particles of the first deflecting agent and particles of the second deflecting agents are dispersed, where the particles of each of the first and second deflecting agents include particles of the propping agent substrate, having a water-soluble polymer coating, besides, the particles of the first deflecting agent have density, which is higher than the density of the water bearing fluid, while the particles of the second deflecting agent have the density, which is less than the density of the water bearing fluid, where the water-soluble polymers of each of the first and second deflecting agents are independently selected from the group that consists of collagen of type I, collagen of type II, collagen of type III, collagen of type IV, collagen of type V and their mixtures. The method to prepare the treated interval in the underground formation for formation fracturing to increase intensification of flow from the treated interval by means of formation fracturing, includes injection of the above specified deflecting fluid into the treated interval, which results in the fact that the particles of the first deflecting agent are deposited in the lower part of the treated interval, forming a temporary lower border, which substantially seals the lower part of the treated interval relative to the flow of liquid via this lower border, and the particles of the second deflecting agent rise in the upper part of the treated interval, forming a temporary upper border, which substantially seals the upper part of the treated interval relative to the flow of liquid through this upper border. ^ EFFECT: intensification of flow into one or many intervals in underground drill holes as a result of deflection of working fluids flow to process a drill hole in a certain direction. ^ 16 cl, 2 ex, 3 dwg

Description

This application claims the benefit of priority of the provisional application of the United States SN 60/646231, filed January 21, 2005, the entire contents of which are incorporated herein by reference.

FIELD OF TECHNOLOGY

The present invention provides methods and compositions for treating underground boreholes, and more specifically, provides methods and compositions for stimulating inflow at multiple intervals in underground boreholes. In particular, the present invention provides methods and compositions for diverting a flow of working fluids for treating a borehole at multiple intervals by introducing proppant materials coated with a water-soluble polymer, for example collagen, polyvinyl acetate / polyvinyl alcohol, polyalkyl oxides, poly (lactic acid) , polymer silicate of elements of group I or II of the periodic table of elements (alkali metal or alkaline earth metal) or their combinations with materials That are slowly soluble in water, for use when changing the direction of flow of working fluids for the stimulation supplied from the column of tubing into the subterranean environment.

Description of the level of technology

Wellbore treatments, such as acid treatment and hydraulic fracturing treatments for underground formations, are typically used to improve or intensify hydrocarbon production. In many cases, the subterranean formation may include two or more intervals characterized by different permeability and / or injectivity. Some intervals may exhibit relatively low injectivity or the ability to receive pumped working fluids due to relatively low permeability, high voltage at the site of work, and / or impaired formation performance. Such intervals may be completed by training in a cased hole in a borehole and / or may be completed uncased boreholes. In some cases, such reservoir intervals may be present in the section with a large inclination of the bore or in the horizontal section of the borehole, for example, in the side section of an open hole borehole. In any case, when processing several intervals characterized by different injectivity, there is often a situation where the main part, if not the entire amount of injected working fluid for treating a borehole, will be displaced in one or only a few intervals, characterized by the highest injectivity. Even if there is only one interval to be processed, the tendency to crack growth can either intensify or weaken. This depends on the stress in the formation at the place of work and on the differences in permeability in the layer of the formation. A water zone may be located below the crack. If the formed fracture passes into this zone, the well may be destroyed due to the presence of excess water and the cessation of the supply of oil components from the production interval. A gas cap may exist above the formed fracture zone, which can damage production from the borehole due to gas slipping in comparison with the components of liquid oil from the borehole.

In an effort to achieve a more uniform distribution of displaced working fluids for treating a borehole over each of the many intervals to be processed, methods and materials have been developed to divert the flow of working fluids for processing at intervals with reduced permeability and / or injectivity. However, commonly used deviation techniques can be costly and / or can only lead to limited success. In this regard, mechanical deflection techniques are usually complex and expensive. In addition, mechanical deflection methods are usually limited to cased borehole environments and depend on proper formation separation using cement and tools when the deviation is achieved.

Thus, for many years, the problem of stimulating inflow into a borehole has been the effective and simultaneous processing of several sets of perforations within an extended vertical section. For treating several zones with a wide range of efficiencies, many rejection methods have been used, such as using oil soluble calcium soap, sulfuric acid, and Dowell's Fixafrac (a mixture of lime, kerosene, soap containing sorted calcium chloride, and a gel) and Dowell's FLAX-2 ™ product, as described by Harrison in his comprehensive review of the Journal of Petroleum Technology , pp. 593-598 (1972). A wide range of chemical-based deflecting agents has been used in attempts to block holes in the formation and divert the flow of working fluids for processing to other zones of the formation. For example, wax granules were used as deflecting agents. However, wax granules are characterized by limited melting points, ranging from about 138 ° F to about 192 ° F, which makes them useless when the temperature of the formation exceeds their melting temperature.

As described, particles of naphthalene (naphthalene beads) and sodium chloride are also suitable for use as effective deflecting agents. Naphthalene particles readily dissolve in oil, but melt at approximately 180 ° F, thereby limiting their use for lower-temperature formations. Sodium chloride, characterized by a melting point of approximately 1470 ° F and suitable for use at high temperatures, requires cleaning the borehole with water or dilute acid after treatment of the formation in order to completely remove particles of sodium chloride. In addition, sodium chloride cannot be used together with hydrofluoric acid to treat underground boreholes due to the formation of insoluble sediments, which can clog the borehole in a problematic manner.

Alternatively, during simultaneous processing of several intervals characterized by different injectivity, deflecting agents such as polymers, suspended solid materials and / or foam were used. Such diverting agents are typically injected into the subterranean formation in front of the borehole treatment fluid in order to plug the intervals with increased permeability and to divert the flow of the borehole treatment fluid into the intervals with reduced permeability. However, the action of selective deviation in the case of such deflecting agents is often difficult to predict and track, and if the flow of the working fluid for processing is deviated at all desired intervals, it may not lead to success. These problems can be further exacerbated by the completion of open-hole boreholes, especially in the case of completions with a large inclination of the trunk, characterized by the presence of large areas of the reservoir exposed for the borehole. The presence of natural cracks can also make deflection more difficult.

Over the years, several attempts have been made to solve problems associated with areas in the borehole characterized by different permeabilities. US Pat. No. 2,803,306 to Hower provides a method for increasing the permeability of a subterranean formation by turning off several zones with different permeabilities. The steps described included the introduction of a treatment fluid containing hydrochloric acid into the borehole of the borehole, which included oil-soluble particles dispersed in it, the material being selected from gilsonite, naphthalene, para-dichlorobenzene, anthracene and β-naphthol. After processing, the particles provide partial blockage of the more permeable zones of the subterranean formation, making it possible for the working fluid to enter the less permeable zones.

US Pat. No. 3,797,575, assigned to Halliburton, describes additives that form selective plugging of the formation and are formed with a relatively water-insoluble solid material dissolved in a solvent such as methanol or isopropanol. When the additive is combined with an aqueous working fluid for processing, the solid material dissolved in the additive is deposited in the aqueous working fluid for processing with the formation of ultimately ground form, which then acts as a deflecting agent. US Pat. No. 3,724,549, also assigned to Halliburton, describes a diverting agent material designed to divert the flow of aqueous working fluids for processing into successively less permeable subterranean formations. The material is formed by a carrier fluid and sorted particles of cyclic or linear hydrocarbon resins containing from about 20 to about 1400 carbon atoms and having a melting point of about 200 ° F. This material is described as being mostly insoluble in water and acid, but soluble in oil, so that the resin can be removed by the extracted oil after completion of the oil treatment operation.

The use of polymers prepared by the radiation polymerization method as deflecting agents, either temporary or permanent, has been described by Knight, et al. in US patent No. 3872923. In accordance with the description of the invention, a temporary or permanent decrease in permeability can be achieved by injection of an aqueous solution containing a water-soluble polymer obtained by the radiation polymerization of acrylamide and / or methacrylamide and acrylic acid, methacrylic acid and / or alkali salts metals derived from such acids. The resulting polymer deflecting agent has properties, such as resistance to temperature and pH, which allow a reduction in the permeability of the porous medium. Permeability in the formation can be restored as a result of subsequent treatment with a chemical agent that destroys the polymer, such as a solution of hydrazine hypochlorite or strong mineral acids.

US Pat. Nos. 3,954,629 and 4,005,753 to Scheffel, et al. polymer deflecting agents and methods for treating subterranean formations with such polymer deflecting agents, respectively, are provided. As described, the polymer composition contains solid particles of a homogeneous mixture of polyethylene, a copolymer of ethylene-vinyl acetate, a polyamide and a softener, such as long chain aliphatic diamides. It is reported that these polymeric diverting agents are suitable for use in underground formations where formation temperatures are 350 ° F or more.

Methods for temporarily plugging a subterranean formation using a diverting material including an aqueous carrier fluid and a diverting agent containing an azo solid component and a methylene component are described by Dill, et a1. in US Pat. No. 4,527,628, diverting agents are preferably Hansa Yellow G dyes (Fanchon Yellow YH-5707 pigment) or Fast Yellow 4RLF dyes, both of which contain an azo component and a methylene component, and are further characterized by a melting point of at least 332.6 ° F, a certain degree of solubility in water at a water temperature in the range of from about 200 to about 425 ° F and a certain degree of solubility in kerosene at a temperature in the range of from about 200 ° F to about 425 ° F.

In US patent No. 6367548 authors Purvis, et al. describe methods and compositions designed to intensify the inflow at multiple intervals in underground boreholes as a result of the deviation of the flow of working fluids for processing the borehole at multiple intervals. In accordance with the description of the invention, this is achieved by alternately displacing into the subterranean formation an agent for selective plugging of the formation from the annulus of the borehole and displacing the working fluid into the subterranean formation for processing from the tubing string.

Other deviation methods during hydraulic fracturing treatments include the limited input technique described by LaGrone, et al., SPE 530, pp. 695-702 (1963), and a hydraulic fracturing technique with the formation of several fractures using a diverting agent (TMFUD), proposed by Dingxiang, et al., SPE 30816, pp. 80-86 (1988), the last of which, as was shown, provides an average improvement in oil production equal to 15.0 tons / day for each borehole, and an improvement in cumulative production equal to 340.3 x 10 ⁴ tons. Also described (Alleman, D., et al., SPE 80222 (2003)) a viscoelastic surfactant-based diverting agent for use in stimulating an influx by an acid treatment, which is a WUPAV gel (polyQuat), characterized by the presence of a distinct vesicular structure exhibiting stability at high pH and thermal stability of approximately 250 ° F. This gel type deflecting agent is typically pumped into the subterranean formation prior to the working fluid to intensify the inflow into the borehole in order to plug high-permeability intervals and to divert the flow of the working fluid for treating the borehole into low-permeability intervals.

In the light of all these successes and new techniques, the deviation action in the case of deflecting agents is often difficult to predict and monitor, and if the flow of the working fluid for processing is deviated at all desired intervals, it may not lead to success, thereby not maximizing the benefits of the technique hydraulic fracturing.

These problems can be further exacerbated by the completion of open-hole boreholes, especially in the case of completions with a large inclination of the trunk, characterized by the presence of large areas of the reservoir exposed for the borehole. The presence of natural fractures in the subterranean formation can also make deviation more difficult. Thus, there is a need for new compositions and methods designed to divert the flow of working fluids for treating a borehole at multiple intervals in a subterranean formation characterized by different permeabilities.

SUMMARY OF THE INVENTION

The present invention provides a method of using particles having a soluble external coating as diverting agents in subterranean formations. The soluble external coating will dissolve after a desired period of time at downhole temperatures and pressures in the presence of standard working fluids for hydraulic fracturing inside the well and thinner compositions. Examples of a soluble external coating include collagen, poly (alkylene) oxides, poly (lactic acid), polyvinyl acetate, polyvinyl alcohol, polyvinyl acetate / polyvinyl alcohol, polylactone, polyacrylate, latex, polyester, polymer silicate of Group I or II elements, or mixtures thereof.

The present invention provides proppants with a water-soluble polymer coating applied as diverting agents and methods for using such diverting agents in treating a subterranean formation. The diverting agent, together with the carrier fluid, is injected into the subterranean formation. The fluid carrier flows into cracks and / or intervals in the subterranean formation. Cracks or intervals exhibit varying degrees of permeability. In accordance with the methods of the present invention, the liquid carrier together with the deflecting agent will flow first to the most permeable interval. The temperature of the formation will lead to softening and swelling of the water-soluble polymer coating of the deflecting agent, thereby blocking the crack.

In one embodiment, a diverting agent is described that is suitable for use in diverting a flow of fluid for treating a borehole at one or a plurality of intervals where the diverting agent is formed by substrate particles and a water-soluble outer layer. Examples of such a polymer of a water-soluble outer layer without limitation are collagen, poly (alkylene) oxides, poly (lactic acid), polyvinyl acetate, polyvinyl alcohols, polyvinyl acetate / polyvinyl alcohol, polymer lactones, water-soluble acrylic resins, latex, polyester, polymer silicate of group I elements or II and mixtures thereof.

In a further embodiment, a diverting agent is described which is suitable for use in diverting a flow of working fluids for treating a borehole in one or a plurality of intervals, where the diverting agent is formed by substrate particles, an intermediate water-insoluble layer and a water-soluble polymer outer layer. Examples of a polymer of a water-soluble outer layer include, but are not limited to collagen, poly (alkylene) oxides, poly (lactic acid), polyvinyl acetate, polyvinyl alcohols, polyvinyl acetate / polyvinyl alcohol, polymer lactones, water-soluble acrylic resins, latex, polyester, polymer silicate of group I or II and mixtures thereof. Examples of a water-insoluble intermediate layer are phenolaldehyde novolac polymers and phenolaldehyde resole polymers.

In yet another embodiment, a diverting agent is described which is suitable for use in diverting a flow of working fluids for treating a borehole at one or multiple intervals in a borehole, where the diverting agent is essentially water-soluble polymer particles, such as collagen granules or granular poly particles ( alkylene) oxide, poly (lactic acid), polyvinyl acetate, polyvinyl alcohol, polyvinyl acetate / polyvinyl alcohol, polymer lactones, water-soluble acrylic resins, latex, polyester, polymer silicate of elements of group I or II or mixtures thereof.

In an additional embodiment, a method for stimulating inflow into individual intervals of a subterranean formation is described, the method comprising the steps of introducing a diverting agent containing a water-soluble component on its outer layer into the inner pipe of a borehole in combination with a low viscosity hydraulic fluid or hydraulic fracturing fluid ; ousting the diverting agent and hydraulic fluid for fracturing into the subterranean formation, providing consistent plugging with the diverting agent to be treated; and repeating the implementation of the method as necessary, adding a deflecting agent to the carrier working fluid in batches during the hydraulic fracturing operation.

DESCRIPTION OF DRAWINGS

The following drawings form part of the present description of the invention and are included to further demonstrate certain aspects of the present invention. The invention may be better understood by reference to one or more of these figures in combination with a detailed description of the specific embodiments presented herein.

FIG. 1 shows a vertical cross-sectional view for a downhole portion of a subterranean formation including a vertical casing and one treatment interval where diverging agents with various coatings are injected into the reservoir in accordance with one aspect of the present disclosure.

FIG. 2 illustrates a vertical cross-sectional view for the subterranean formation of FIG. 1, where proppants are injected into a producing formation subjected to injection of deflecting agents of the present invention.

Figure 3 in accordance with one aspect of the present description shows a borehole comprising a vertical casing and several intervals for processing 58, 60 and 62 and injection deflecting agents coated with various coatings.

DEFINITIONS

The following definitions are provided to assist those skilled in the art from understanding the detailed description of the present invention.

The term “carrier fluid” as used herein refers to oil-based or water-based fluids that are capable of transporting particles (eg, proppant) that form a suspension. Low-viscosity carrier fluids are characterized by a lower bearing capacity, and particles can be affected by gravity, so that they will either float if they are less dense when compared to liquids, or they will sink if they are more dense when compared with liquids. Highly viscous liquids can carry particles at lower degrees of sedimentation or floating, since viscosity counteracts the effects of gravity.

The term “crosslinker” or “crosslinking agent” as used herein refers to those compounds that are used to covalently modify proteins, such as collagen, and include both homobifunctional crosslinkers that have two identical reactive groups and heterobifunctional crosslinkers that have two different reactive groups.

The term “diverting agent” as used herein generally refers to and characterizes an agent whose function is to prevent, either temporary or permanent, fluid flow to a specific location, usually located in an underground formation, where the agent serves to plug in this place and thereby causes a "deviation" of the fluid flow to another place.

The term “proppant,” as used herein, refers to those particles sorted by particle size that are used in repairs and treatments of a borehole, such as hydraulic fracturing, to prevent fractures from closing after treatment. In order to keep cracks from closing after treatment for hydraulic fracturing or similar downhole treatment of a borehole, such particle-sized particles are often mixed with hydraulic fluids (hydraulic fluid) for hydraulic fracturing. In addition to naturally occurring sand grains and nutshells, the term “proppant” includes synthetic or specially designed proppants, such as resin coated sand or high strength ceramic materials like sintered bauxite. Resin coated proppants are typically those that are coated with phenolaldehyde novolac polymers or phenolaldehyde resole polymers. Usually, but not necessarily, proppant materials are carefully sorted by size and sphericity, providing an efficient channel for producing fluid from the reservoir into the borehole of the well.

In the embodiments described and disclosed herein, the use of the term “injection” includes pumping, pumping, pouring, releasing, displacing, installing a bath, circulating or otherwise placing a working fluid or material in a borehole, borehole or subterranean formation when used any suitable method known in the art. Similarly, as used herein, the terms “combining,” “contacting,” and “applying” include any known suitable methods of mixing, exhibiting, or otherwise stimulating two or more materials, compounds or components to combine with each other in a way that will be sufficient to stimulate the passage between the materials, compounds or components of at least a partial reaction or other interaction.

The term “water soluble” as used herein refers to resins, polymers or coatings that are stable (not soluble) under ambient conditions on the surface, but which become soluble after a predetermined period of time (usually after several hours or several days) if placed in an underground environment.

The term “treatment” as used herein refers to any of the numerous downhole operations on the surface or in the volume of a borehole, borehole or reservoir, including, but not limited to, the following: treatment related to the type of repair, processing, related to the type of stimulation of the influx, such as hydraulic fracturing treatment or acid treatment, isolation treatments, control of treatment fluids or other recovery Specific types of treatments to improve overall well operation and productivity.

The term "stimulation of flow" as used herein refers to operations to improve productivity or restore working capacity for a borehole as a result of hydraulic fracturing, acid hydraulic fracturing, acid treatment under pressure less than hydraulic fracturing, sand treatment, or another type of treatment designed to increase and / or maximize the productivity of the borehole or its lgovechnosti, often as a result of the creation of highly conductive lines of the current collector.

DETAILED DESCRIPTION OF THE INVENTION

In embodiments of the described diverting agent, the treatment or stimulation of the influx in the case of one and many intervals of the subterranean formation can be carried out stepwise by sequentially introducing the diverting agent, including particles of the substrate and slowly dissolving in water, an external coating containing collagen or a combination of collagen and slowly dissolving in water non-collagen material.

The invention provides particle compositions having coatings of soluble material containing collagen, as well as methods for producing such compositions. These compositions are suitable for use in underground formations during a hydraulic fracturing operation when the flow of working fluids for treating a borehole deviates in one interval in order to increase the length of a fracture or in many intervals of an underground formation characterized by different permeability and / or injectivity. When using the diverting agents of the present invention in hydraulic fracturing methods, a proppant (or substrate particles) coated with a slowly water-soluble coating, such as collagen alone or in combination with a non-collagen water-soluble plastic coating material, has an effect in deflecting the direction of growth of the crack, since proppant coatings act as determinants of the initial crack boundaries. After treatment for hydraulic fracturing, the coating can be removed due to the presence of slow dissolution characteristics of the coating while maintaining the flow of a standard proppant with high permeability and its proppant function.

Although the compositions and methods are described as “including” various components or steps, the compositions and methods can also “essentially consist” or “consist” of various components and steps.

A. Substrate

Particles of material, also referred to herein as substrate material suitable for use in the present invention, include a wide range of particles of materials known for their suitability or potential suitability for use as proppants that can be used in downhole operations. In accordance with the present invention, particles of material (or substrate material) that can be used include any proppant suitable for use in hydraulic fracturing and known in the art. Examples of such material particles include, but are not limited to, particles of natural materials, silica proppants, ceramic proppants, metal proppants, synthetic organic proppants, mixtures thereof, and the like.

Natural products suitable for use as proppants include, but are not limited to: walnut shells, such as walnut shells, Brazil nuts, and Australian walnuts, as well as fruit kernels such as peach kernels, apricot kernels, olive kernels , and any option from the data after impregnation with resin or applying a resin coating. Typical coating or impregnation resins include bisphenols, bisphenol homopolymers, mixtures of bisphenol homopolymers with a phenolaldehyde polymer, bisphenol aldehyde resins and / or polymers, phenolaldehyde polymers and homopolymers, modified and unmodified resole resins, phenolic materials, alkylene phenols, alkylene phenols, alkylene phenols resorcinol resins, epoxies, novolac resins, novolac bisphenolaldehyde polymers and waxes, as well as curing or curable variants of such resin coatings.

Silica proppants suitable for use in the present invention include, but are not limited to: glass beads and glass microspheres, glass beads, silica silica sand, and all types of sand, such as silica sand or brown sand. Common siliceous sands suitable for use include Northern White Sands (Fairmount Minerals, Chardon, Ohio), Ottawa, Jordan, Brady, Hickory, Arizona, St. Peter, Wonowoc and Chalfort, as well as any variation of these resin coated sands. In the case of using silica fiber, the fiber may be straight, curved, crimped or spiral and may refer to any brand, such as grades E-grade, S-grade and AR-grade. Examples of resin coated silica proppants suitable for use in the present invention include deformable proppants such as FLEXSAND LS ™ and FLEXSAND MS ™ (available from BJ Services, Inc., Houston, Texas) and proppants heat-treated fillers Tempered HS®, Tempered LC®, Tempered DC® and Tempered TF®, all of which are available from Santrol, Fresno, Texas.

Ceramic proppants suitable for use in the methods of the present invention include, but are not limited to: ceramic granules; spent fluidized bed cracking catalysts (FCCs), such as those described in US Pat. No. 6,373,378, which is incorporated herein in its entirety; ultra-lightweight porous ceramics; economical lightweight ceramics such as ECONOPROP ™ (Carbo Ceramics, Inc., Irving, Texas); lightweight ceramics such as "CARBOLITE ™"; medium strength ceramics such as CARBOPROP ™ (available from Carbo Ceramics, Inc., Irving, Texas); high strength ceramics such as CARBOHSP ™ and Sintered Bauxite (Carbo Ceramics, Inc., Irving, Texas), and HYPERPROP G2 ™, DYNAPROP G2 ™ or OPTIPROP ™ encapsulated curable ceramic proppants (available from Santrol, Fresno , Texas), as well as any of their variants after applying the resin coating or impregnation with resin, such as those described above.

Metal proppants suitable for use in embodiments of the present invention include, but are not limited to: aluminum shot, aluminum pellets, needle-shaped aluminum particles, aluminum wire, cast iron shot, steel shot and the like, as well as any variations of these metallic resin coated proppants.

Synthetic proppants are also suitable for use in the present invention. Examples of suitable synthetic proppants include, but are not limited to: plastic particles or granules, nylon granules, nylon beads, SDVB (styrene-divinylbenzene polymer) granules, carbon fibers such as PANEX ™ carbon fibers from Zoltek Corporation ( Van Nuys, Calif.), And resin agglomerate particles similar to the FLEXSAND MS ™ product (BJ Services Company, Houston, Texas), as well as resin coated variants thereof.

In addition, soluble materials suitable for use as proppants are also contemplated for use in the methods of the present invention. For example, soluble proppants that are placed in the channels of the formed perforations include, but are not limited to: fragments of marble or limestone or particles of any other suitable carbonates. In addition, particles suitable for use as proppants in the present invention are wax, plastic or resin particles, either coated or uncoated, which are either soluble in contact with the processing reagent, or may melt and be removed from a crack to a borehole.

Proppants suitable for use in the present invention are typically used with concentrations in the range of about 1 to about 18 pounds per gallon (about 120 g / l to about 2160 g / l) hydraulic fracturing fluid composition, but also if necessary larger or lower concentrations may be used.

Similarly, substrate particles suitable for use in the present invention have a particle size in the range of US standard laboratory sieve numbers from about 4 to about 200 (i.e., holes in sieves in the range of about 0.18 inch to about 0.003 inch) . More specifically, substrate particle sizes suitable for use in the present invention include size ranges from about 4 mesh (4750 microns) to about 200 mesh (75 microns). Also suitable for use in the present invention are particles of materials or proppants, characterized by designations of sizes 6/12, 8/16, 12/18, 12/20, 16/20, 16/30, 20/40, 30/50, 40/70 and 70/140, although any desired particle size distribution can be used, such as 10/40, 14/20, 14/30, 14/40, 18/40 and the like, as well as any combination thereof (e.g. a mixture of 10/40 and 14/40). In accordance with the present invention, the preferred sieve number is 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 slowly dissolve inside the well in subterranean formations over a period of time. Soluble polymeric materials used in accordance with the present invention should be soluble (i.e., capable of dissolving) in brines, water, oil, organic solvents, acid or acidic environments and / or in working fluids characterized by a pH in the range from about 1 to about 14, as well as their mixtures under conditions existing inside the well in the subterranean formation.

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 collagen originating in a marine environment. The latter type of collagen can be extracted from fish, algae, plankton, microplankton and the like. More preferably, the soluble coating is collagen, including type I collagen, type II collagen, type III collagen, type IV or type V collagen, and combinations thereof. In accordance with the present invention, most preferably the soluble coating is type I collagen or atelocollagen.

Type I collagen or atelocollagen suitable for use as soluble coatings in accordance with the present invention are those collagens that contain at least one hydroxyproline residue. Such type I collagen or atelocollagen include collagen found in tendons, skin, bone, scar tissue and the like, such as tropocollagen, as well as products obtained by controlled enzymatic or chemical cleavage of collagen proteins. Such collagens are preferably characterized by a molecular weight ranging 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 are 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, and molecular weights in the range between any two of these values, for example collagen with a molecular weight in the range of from about 225,000 to about 275,000 daltons. For example, a preferred type I collagen suitable for use in the present invention is tropocollagen, having a molecular weight of approximately 250,000, supplied by Milligans and Higgins, Inc. (Johnstown, New York).

Collagens suitable for use in the present invention show a Bloom strength of from about 100 lb / ⁱⁿ² and about 900 lb / ^in2, more preferably from about 300 lb / ⁱⁿ² and about 700 lb / ^in2. Most preferably, collagens suitable for use in the present invention are characterized by Bloom strengths from about 400 lb / ⁱⁿ² and about 600 lb / ^in2. In accordance with the present invention suitable strength Bloom is a value equal to about 400 lb / ^in2, approximately 410 lb / ^in2, approximately 420 lb / ^in2, approximately 430 lb / ^in2, approximately 440 lb / ⁱⁿ² approximately 450 lbs / ^in2, approximately 460 lb / ^in2, approximately 470 lb / ^in2, approximately 480 lb / ^in2, approximately 490 lb / ^in2, approximately 500 lb / ^in2, approximately 510 lb / ⁱⁿ² approximately 520 lb / ^in2, approximately 530 lb / ⁱⁿ² approximately 540 lb / ^in2, approximately 550 lb / ^in2, approximately 560 lb / ^in2, approximately 570 lb / ^in2, approximately 580 lb / ^in2, approximately 590 lb / ⁱⁿ² and about 600 lb / ⁱⁿ² and strength Bloom in the range between any two of these values, for example from about 400 lb / ⁱⁿ² and about 520 lb / ^in2, such as 512 lbs / ^in2.

Bloom jelly strength as used herein refers to the strength and / or stiffness of a gel-like substance, such as collagen, obtained using a standard solution of a certain concentration, which was held at a constant temperature for a specified period of time, measured in accordance with standardized methods conducting Bloom jelly strength tests, such as in BS757: 1975, GMIA Testing Standard B5757, International Standard ISO9665 for testing adhesive animal glues, or the like s standards described in «Official Methods of Analysis of AOAC INTERNATIONAL (OMA)», 17th Edition, Volume II; AOAC International Publications (2003). Bloom jelly strengths are typically given in “pounds per square inch” (pounds / inch ² ) or grams, which reflects the force required to push a selected portion of the sample surface 4 mm apart. In a typical procedure, a gel-like product, such as collagen or gelatin, with the indicated consistency (for example, a solution with a concentration of 6 and 2/3%) is obtained and it is kept at a constant temperature in a thermostatic bath at 10 ° C for 18 hours. After that, a device called a Texture Analyzer (for example, the TA.XT2i Texture Analyzer, Scarsdale, NY) measures the mass in grams (or pressure in pounds per inch ² ) needed to press a standard AOAC® gel meter plunger into the gel [Association of Official Analytical Chemists], having a sharp lower edge of 4 mm; alternatively, a BS plunger may be used as the plunger, which has a bottom face rounded with a radius of 0.4 mm. For example, if in this technique 200 g is required to push the plunger in, then the gelatin will be characterized by the strength of the jelly according to Bloom 200.

Type I collagens suitable for use in the present invention are characterized by particle size distribution determined by the scattering on the sieve / designation of the sieve size 6/12, 8/16, 12/18, 12/20, 16/20, 16/30, 20/40 , 30/50, 40/70 and 70/140, as well as particle size determinations determined by the scattering on a sieve, in the range between any two of these designations, although any desired particle size distribution, such as 8/40, 10/40, 14/20, 14/30, 14/40, 18/40 and the like, as well as any combination thereof (e.g., a mixture of 10/40 and 14/40). In accordance with the present invention, the preferred sieve number is 8/40 mesh.

The collagens used as soluble coatings in the present invention can be either crosslinked or non-crosslinked, or a combination of both, and the type and degree of crosslinking will depend on the particular application of the collagen-based soluble coating. There are four fundamental strategies for fixing collagen materials and materials made from recycled collagen fibrils or purified collagen. These include exogenous chemical crosslinking using agents that covalently bind adjacent collagen fibrils using targeted reactive fragments in the collagen fibrillar system and the crosslinking molecules themselves; physicochemical crosslinking techniques, such as photooxidation, microwave irradiation, dehydration and dehydrothermal treatment, which covalently connect collagen fibrils through naturally occurring reactive amino acid side chains; chemical catalysis of intramolecular crosslinking between amino acid side chains on collagen fibrils; and polymerizing compounds miscible with collagen structures and forming polymeric non-covalent or covalent interactions that do not chemically react with collagen fibrils [Koob, TJ, “Collagen Fixation”, in Encyclopedia of Biomaterials and Biomedical Engineering, Wnek, GE, Bowlin, GL , Eds., 2004]. In accordance with the present invention, collagen used as a soluble coating is preferably crosslinked using chemical crosslinking techniques. These include, but are not limited to: aldehyde-based crosslinking techniques, polyepoxy compounds based crosslinking techniques, isocyanates use, carbodiimide crosslinking and acylazide crosslinking. More preferably, collagen is crosslinked using aldehyde based crosslinking techniques, such as glutaraldehyde or formaldehyde.

Aldehyde-based crosslinking techniques include those that use a reagent having two reactive aldehyde groups to produce covalent crosslinkings between adjacent collagen proteins, especially between the ε-amino groups of lysine residues in collagen [Khor, E., Biomaterials , Vol. 18: pp. 95-105 (1997)]. Aldehydes suitable for use in the present invention include, but are not limited to, glutaraldehyde, formaldehyde, propionic aldehyde, and butyraldehyde.

Crosslinking techniques and crosslinking agents based on the use of polyepoxy compounds include the use of compounds, such as short branched polymers having terminal reactive epoxy functional groups. Polyepoxy compounds suitable for use as crosslinkers in the present invention include, but are not limited to: glycerol ethers, glycol and glycerol polyglycidyl ethers.

Isocyanates are also suitable for use as crosslinkers in the present invention. Generally, isocyanates (R-NCO) react with primary amines to form a urea bond (R-H-CO-NH-R); therefore, bifunctional isocyanates have the ability to cross-link collagen through its lysine side chains. Isocyanates suitable for use as crosslinkers in the present invention are preferably diisocyanates, including biphenyl diisocyanate, dimethoxy-4,4'-biphenyldiisocyanate, dimethyl-4,4'-biphenyl diisocyanate, 1,3-bis (isocyanatomethyl) benzene, phenyl diisocyanate, toluene diisocyanate, toluene diisocyanate, diisocyanatohexane, diisocyanato-octane, diisocyanatobutane, isophorondiisocyanate, xylene diisocyanate, hexamethylenediisocyanate, octamethylene diisocyanate phenethyl isocyanate. Preferably, the isocyanate used as a crosslinker for the collagen molecules of the present invention is hexamethylene diisocyanate.

Carbodiimide crosslinkers and carbodiimide crosslinking techniques can also be used within the scope of the present invention. These agents react with the carboxyl groups of the side chains formed by aspartic and glutamic acids in collagen to form isoacylurea derivatives / isopeptide bonds [Khor, E., ibid.]. Carbodiimides suitable for use as crosslinkers in the case of the collagen of the present invention include, but are not limited to: N, N'-dicyclohexylcarbodiimide (DCC); N, N'-diisopropylcarbodiimide (DIC); N, N'-di-tert-butylcarbodiimide; 1-ethyl-3- (3-dimethylaminopropyl) carbodiimide (EDC; EDAC); water soluble EDC (WSC); 1-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 described in US Pat. No. 5,602,264); N-cyclohexyl-N ' - (2-morpholinoethyl) carbodiimide; N, N'-diethylcarbodiimide (DEC); 1-cyclohexyl-3- (2-morpholinoethyl) carbodiimide methyl p-toluenesulfonate [e.g., Sheehan, JC, et al., J. Org. Chem . , Vol. 21: pp. 439-441 (1956)]; oligomeric alkylcyclohexylcarbodiimides, such as those described by Zhang, et al. [J. Org. Chem . , Vol. 69: pp. 8340-8344 (2004)]; polymer bound DCC; and polymer bound EDC, such as crosslinked N-ethyl-N '- (3-dimethylaminopropyl) carbodiimide on JANDAJEL ™. In addition, N-hydroxysuccinimide (NHS), 1-hydroxy-7-azabenzotriazole (HOAt) or similar reagents can be used to minimize the internal rearrangement of the activated isoacylurea derivative and to provide more efficient crosslinking in combination with carbodiimide.

As with carbodiimide treatment, acylazide crosslinkers result in covalent bonds between carboxylic acid groups of side chains formed by aspartic acid and glutamic acids and the ε-amino groups of collagen lysines [Petit, H., et al., J. Biomed . Mater. Res . , Vol. 24: pp. 179-187 (1990)]. After the esterification of carboxyl groups, in which a methyl group is attached to the acid, the biomaterial is subjected to hydrazine treatment to obtain the corresponding hydrazide; then sodium nitride is added to undergo a reaction with hydrazide and form an acylazide. In this method, it is possible to use any number of hydrazines known in the art, including maleimidopropionic acid hydrazide (MPH).

Other chemical crosslinkers suitable for use in the present invention in the preparation of crosslinked collagen molecules that act as soluble coatings on proppant particles include, but are not limited to: homobifunctional crosslinkers such as BMME (bis (maleimidomethyl ether)), BSOCOES (bis [2- (succinimidyloxycarbonyloxy) ethyl] sulfone), DSP (dithiobissuccinimidyl propionate) (thio-cleavable crosslinker), DSS (disuccinimidyl suberinate), EGS (ethylene glycol succinimidyl succinate) soluble EGS and SATA (N-succinimidyl-S-acetylthioacetate), as well as heterobifunctional crosslinkers, including GMB (gamma-maleimido-n-butyric acid), MBS (m-maleimidobenzoyl-N-hydroxysuccinimide ester), PMP I (p maleimidophenyl isocyanate), SMCC (succinimidyl-4- [N-maleimidomethyl] cyclohexane-1-carboxylate), SPDP (N-succinimidyl-3- (2-pyridyldithio) propionate) and MPH (maleimidopropionic acid hydrazide hydride), MSH , EMSN (ε-maleimidocaproic acid hydrazide), KMUH (N- (k-maleimidoundecanoic acid hydrazide)) and MRVN (hydrazide 4- (4-N-maleimidophenyl) butyric acid), all of which are available from Interchim (Cedex, France).

Other techniques suitable for use in crosslinking collagen fibers intended to be used as proppant soluble coatings include, but are not limited to, dehydration crosslinking, UV crosslinking at 254 nm, glucose crosslinking (glycation ) in combination with UV radiation and biological crosslinking. The latter technique involves 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 thus can react with ε-amino groups on the lysine side chains of neighboring molecules collagen with the formation of crosslinking. Other biological crosslinking systems suitable for use in the present invention include catechin-quinone tanning systems, such as 3,4-dihydroxytyramine and nordigidrohvayaretnoy acid (NDGA), isolated from the creosote bush, which acts as a crosslinker due to the presence of two catechins on NDGA [ Koob, TJ, Comp. Biochem . Physiol . , Part A, Vol. 133: pp. 1171-1192 (2002)].

In accordance with the present description, slowly dissolving in water coatings on the particles of the substrates can also be non-collagen materials, such as synthetic polymers, which are slowly soluble in water. Such non-collagen materials include, but are not limited to, the following: polyethylene oxides, polypropylene oxides, polycaprolactones; grafted copolymers of polyethylene / polypropylene and polycaprolactones; grafted copolymers of polyethylene / polypropylene oxides and polycaprolactones; water soluble and waterborne acrylic polymers; water borne phenoxy resin; latex; polyesters; soluble block copolymers; grafted copolymers of polyvinyl alcohol (PVA) and polyvinyl acetates; polylactides and derivatives of polylactic acid; polyglycolic acid (PGC); polyglycolic-lactic acid (PHMK). Polymer silicates of elements of groups I or II of the periodic table of elements (alkali metal or alkaline earth metal), for example SOLOSIL (Foseco International, Ltd., Great Britain), polymeric sodium silicate are also suitable for use in a water-soluble coating.

C. Method of use

In embodiments of the described method, the treatment or stimulation of the inflow in the case of one and many intervals of the subterranean formation can be carried out in stages by sequentially introducing the diverting agent of the present invention into the formation and then introducing the working fluid for processing the borehole into the formation. As used herein, a “borehole” includes cased and / or uncased sections of a borehole, it being understood that the borehole may be vertical, horizontal, or a combination thereof. The term "pipe string" refers to any channel suitable for use in the placement and transportation of working fluids into the wellbore, including the following, but not limited to: lift string, casting string, drill string, small diameter flexible tubing and things like that. In addition, using the benefits of reading this description, it should be understood that the described deflecting agents and deviation techniques are suitable for use with any type of borehole treatment fluid, including but not limited to the following: acidic treatment fluid condensate treatments, hydraulic fracturing treatments and the like. In addition, it is necessary to understand that the benefits of the described methods and compositions can be realized by treatment of the borehole, carried out at pressures less than, equal to or greater than the pressure of hydraulic fracturing.

First: USE IN THE BOREHOLE OF THE DRILLING WELL.

This aspect of the invention describes the use of completely soluble particles in a borehole (such as collagen or other water-soluble polymer plastics or mixtures thereof) to deflect the flow of working fluid from one zone to another zone, and after this dissolution. The use of collagen (both in uncrosslinked and crosslinked form) and soluble plastics is useful in deflecting the flow of working fluids in a borehole. These deflecting materials should have a sieve number in the range from 1 to 100, preferably a sieve number in the range from 4 to 50, and can be used in combination with other additives or plastic materials to improve the operational characteristics of the borehole as a result of deviation of the flow of working fluids from one zone to another.

These materials were used as sealing balls of perforations for selective plugging of the formation, but recent tests have shown that the material can also be used as a deflecting agent, which prevents the flow of the working fluid into one zone and deflects it into another, characterized by either increased pore pressure, or low permeability.

The present invention provides a method for processing a cased hole in a borehole to deflect a flow of working fluids from one zone to another. The method includes injecting into the borehole of the borehole a deflecting liquid, which is formed by an aqueous carrier fluid, comprising a particulate water-soluble polymer dispersed in it, and where the polymer particles are characterized by a density greater or lower than the density of the carrier fluid. As the diverting fluid is pumped into the borehole of the borehole, polymer particles will collect in the borehole zones of the borehole and thus deflect the flow of the processing fluid from one zone to another. In the General case, the flow of the working fluid for processing is deviated or blocked, falling into the zone, characterized by increased pore pressure or low permeability.

In the methods of this invention related to the use in a borehole of a well, the particles of water-soluble polymer are particles of collagen, poly (alkylene) oxide, poly (lactic acid), polyvinyl acetate, polyvinyl alcohol, polyvinyl acetate / polyvinyl alcohol, polylactone, polyacrylate, latex, complex polyester, polymer silicate of elements of group I or II of the periodic table of elements (alkali metal or alkaline earth metal) or mixtures thereof. Typically, polymer particles are present in the carrier fluid in an amount ranging from about 0.001 pounds per gallon to about 10 pounds per gallon of carrier fluid. In a favorable case, the polymer particles are characterized by different densities, greater or lower than the density of the carrier fluid. Typically, the carrier fluid is water, brine, aqueous acid solutions, or gel acid solutions.

Second: USE IN FORMED CRACK.

In this aspect of the invention, particles of various coated proppants (coated with either completely soluble coatings or coatings from a mixture of soluble and insoluble collagen or polymer plastic materials) can be pumped into the hydraulic fractured formations to prevent deviation of the direction of crack growth from the productive zone. For example, dense particles of sintered bauxite coated with a soluble or partially soluble coating will sink to the bottom of the crack and deviate the direction of growth of the crack from the bottom layer or water zone. In addition, a low-density walnut shell coated with a soluble or partially soluble coating will tend to float inside the crack, diverting the direction of crack growth from the gas or water zone located above. The coating can be either completely or partially soluble, since the proppant will remain in the fracture at its location and provide conduction in the fracture after the hydraulic fracturing operation is completed. Some of the coating on the proppant must be soluble, but a mixture of both soluble and insoluble plastics or collagen is desirable to prevent the proppant from moving in the crack.

The use of deflecting agents in cracks consists in applying a soluble or partially soluble coating to the proppant or proppant — using a collagen based coating material and / or polymer plastic or any mixture thereof. The direction of crack growth will deviate due to the use of these soluble coatings on proppants as determinants of the boundaries of the initial crack. After treatment for hydraulic fracturing, the coating will disappear, and particles with the coating applied before will turn into a regular proppant, which is characterized by high permeability. Coatings on proppants of various densities can lead to the definition of fracture boundaries in the early stages of the hydraulic fracturing process, since a low-viscosity working fluid will allow proppant with a high-density coating to settle or lower inside the crack, forming the lower boundary of the crack and deviating its growth direction from the trunk borehole, which makes the crack longer and increases the productivity of the borehole. Similarly, a proppant with a low density coating will tend to float to the top of the growing crack, forming an upper boundary and diverting the direction of crack growth from the upper zones, which may impair the productivity of the borehole. By restricting the fracture from above and below, the fracture can grow from the inside out and the longer, limited fracture will improve the potential productivity of the borehole.

FIG. 1 illustrates a borehole including a vertical section of a cased hole in a borehole and one formation interval that needs to be processed in accordance with one embodiment of the present disclosure. The borehole 10 of FIG. 1 has a casing 12 extending from the wellhead of the borehole 11 and located over at least a portion of its length, which is cemented on the outside with a cement sheath 14 to hold the casing 12 in place and separate the drilled formation or intervals. The cement sheath 14 extends upward from the bottom of the borehole in the annulus between the outer side of the casing 12 and the inner wall of the borehole, at least to a point located above the reservoir / reservoir 18. There are many reasons for including this shell, but essentially the cement sheath 14 helps to ensure the integrity of the borehole (that is, that it does not collapse) or the separation of specific different geological zones (i.e. oil bearing us and the (unwanted) water-bearing zone). The borehole of the well is optionally also equipped with a shoe of the casing or liner 16 in order to facilitate the direction of the casing string 12 past the protrusions or obstacles during its placement in the borehole. In order to produce hydrocarbons in the production layer 18, it is necessary to provide a hydraulic connection between the production layer 18 and the interior of the casing 12. This is achieved by forming perforations 15 through the casing 12 and the cement sheath 14 using methods known to those skilled in the art. Such methods include, but are not limited to, the following: the use of bullet punchers, cumulative punchers and cumulative punchers with simultaneous detonation of a group of charges, such as those described in US patent No. 6755249, 5095099 and 5816343; Horizontal Oriented Perforation Systems (HOPS), such as those manufactured by Owen Oil Tubes, Inc. (Fort Worth, Texas); mechanical punching devices, such as side-drills (US Pat. No. 2,488,213), needle punchers, and perforating cones, such as those described in US Pat. No. 4,220,201; and shear plugs, such as those described in US Pat. No. 4,498,543. Perforations 15 form a streamline for the fluid from the formation to the casing 12 and in the opposite direction.

Hydrocarbons flowing from the production layer 18 through the perforations 15 into the interior of the casing 12 can be transported to the surface through the production lift string 20. Near the lower end of the production lift string 20 and above the highest perforation, the production packer 22 can optionally be installed so that obtain a tight seal between the production lift string 20 and the casing 12. Optional and equally acceptable in accordance with the present invention This is an option when production elevator columns 20 are not needed, and in this case, the entire volume of the casing 12 is used to remove hydrocarbons to the earth's surface.

If selective plugging of the formation is required during the borehole treatment operation, then for essentially blocking the upper and lower sections of the productive layer 18, deflecting agents including heavy proppant 26a and / or deflectors including light proppant 26b will be used on both of which essentially apply a soluble coating in accordance with the present invention (that is, get a collagen-containing coating). Such essentially blockage or formation of boundaries will occur when, during processing at a predetermined point in time, deflecting temporary agents 26a and / or 26b are introduced into the casing 12. When deflecting agents 26a and / or 26b are introduced into the working fluid upstream of the perforated portions of the casing 12, the agents will be carried into the production lift string 20 or casing 12 by the flow of working fluid 24 to be processed. Once the working fluid for processing 24 enters the casing the pipe in the perforated interval, it will flow out through the perforations 15 into the layer 18 to be processed. The flow of the working fluid for processing 24 through the perforations 15 will transfer the temporary deflecting agents 26a and / or 26b through the perforations outward to the layer 18. At the moment, the deflecting agents including heavy proppant 26a with a density higher than the density of the working fluid for processing 24 will settle into the lower part of the formed crack (as indicated by arrows), forming a temporary “lower boundary” between the crack and, for example, a layer of sand, slate or clay 19 or another area that it is desirable to plug from eliv from the producing strata. Similarly, deflecting agents, including a light proppant 26a with a density lower than the density of the working fluid for treatment 24, will float to the top of the formed crack (as indicated by arrows), thereby forming another temporary “upper boundary” between the crack and the unwanted layer such as a shale or clay interlayer.

Figure 2 illustrates the next step of this aspect of the present invention. As soon as the temporary deflecting agents 26a and 26b are located in the upper and / or lower parts of the formed crack, respectively, the flow rate of the working fluid and the viscosity of the working fluid for processing 24 containing conventional proppant particles 28 are increased. Thus, the crack can grow from the inside out, away from the borehole of the borehole (in the direction of the arrow), and as a result increase the total length of the crack, thereby contributing to even greater intensification of the inflow into the borehole and / or to increase its durability. Upon completion of the borehole treatment, the soluble coating on the temporary deflecting agents 26a and 26b will dissolve, which makes it possible to remove the remaining proppant particles together with the working fluid 24 through the perforations 15 or to keep them in place and to act as additional proppants while holding cracks from closing in the layer subjected to hydraulic fracturing.

Figure 3 illustrates a further embodiment of the present invention. A borehole 50 having a vertical cased borehole including a casing 54 extending from the wellhead bore 52 and extending over at least a portion of the length of the borehole and a cement sheath 56 extending upward from the bottom of the borehole wells in the annulus between the outer side of the casing 54 and the inner wall of the borehole, at least to a point located above the existing layer, similar to that shown in figure 1. In an uncased section of a borehole, an underground formation is exposed, including several processing intervals 58, 60 and 62. Despite the fact that the illustration of figure 3 shows three separated intervals, taking advantage of the familiarity with this description, it is necessary to understand that using the methods and compositions described herein, any number of processing intervals can be processed in a range from two processing intervals to any number intervals for processing. In addition, it must be understood that such processing intervals may be adjacent to each other, and not separated by relatively impermeable regions such as clay interlayers. Although FIG. 3 illustrates a borehole with a full-length casing, it must also be understood that the described processing methods can be used in almost any type of borehole completion scenario. For example, the described methods can be advantageously used for processing borehole configurations, including the following, but not limited to: vertical boreholes, boreholes with full-length casing, horizontal boreholes, boreholes with several lateral bends , and boreholes that simultaneously demonstrate the presence of one or more of these characteristics.

In figure 3, the intervals for processing 58, 60 and 62 are the selected intervals of the subterranean formation that were allocated for processing. In this regard, in this way, any number of intervals or only part of the interval existing in the subterranean formation can be distinguished. Alternatively, such intervals may also be perforated intervals in the cased hole of the borehole. As shown in FIG. 3, the perforations 66 pass through the casing 54 and the cement sheath 56 according to embodiments known to those skilled in the art, and as a result, a streamline is formed for the fluid from the formation to the casing 54 and in the opposite direction.

Hydrocarbons flowing out of the productive layer at processing intervals 58, 60 and 62 through perforations 66 into the interior of the casing can be transported to the surface via production lift 64. In addition, and as illustrated in FIG. 3, substantially close to the bottom the end of the production lift 64 and above the uppermost perforation 66, it is optionally possible to install the production packer 68 in order to obtain a tight seal between the production lift 64 and the casing minutes 54. The operational tubing 64 need not always be used, and in these cases, removal of hydrocarbons to the surface to the wellhead bore the borehole 52 using the entire internal volume of the casing 54.

If deviations are necessary during borehole treatment, deflecting agents 72 are used to substantially block some perforations 66. Essentially, blockage occurs when the flow through the perforation 66 is significantly reduced, often indicated by an increase in pressure in the well when the deflecting agent 72 plugs one or more perforations 66. In accordance with this aspect of the present invention, it is preferred that the deflecting agents 72 have a substantially spherical shape y, although other geometries are also possible. The use of deflecting agents 72 of the present invention for blocking certain perforations 66 is accomplished by introducing deflecting agents 72 into the casing 12 at a predetermined point in time during processing. When deflecting agents 72 are introduced into the working fluid upstream of the perforated portions (66) of the casing 12, the agents will be carried into the production lift string 64 or casing 12 by the fluid flow for hydraulic fracturing 70. Once the hydraulic fluid for hydraulic fracturing 70 in the casing reaches the perforated interval, it will flow out through the perforations 66 into the processing intervals 58, 60 and 62. The flow of hydraulic fracturing fluid 70 through the perforations 66 will transfer the deflecting agents 72 to the perforations 66, leading to their placement in the perforations 66. After being placed in the perforations 66, the deflecting agents 72 are held in the perforations 66 due to the presence of a working fluid pressure gradient that exists between the inner side of the casing 54 and the intervals for processing 58, 60 and 62 on the outer side of the casing 54. Deflecting agents 72 preferably have a size that provides essentially clogging Forac 66 when placed in them. The diverting agents for selective plugging of the formation 72 after the aforementioned placement thus effectively close these perforations 66 up to the point in time when the pressure gradient reverses and the diverting agents are released, or when the diverting agents 72 dissolve after a certain period of time due to changes in their environment environment (for example, when entering water).

Deflecting agents 72 will tend to first plug perforations 66 through which hydraulic fracturing fluid 70 flows most rapidly. The preferred closure of perforations 66, characterized by high flow rate, 66 tends to align the processing intervals for processing 58, 60 and 62 throughout the perforated interval. To ensure maximum efficiency when placed in perforations 66, the deflecting agents 72 should be characterized by a density lower than the density of the working fluid for processing 70 in the borehole of the borehole under conditions of temperature and pressure encountered inside the borehole in the perforated region. In the General case and in accordance with this aspect of the present invention, the deflecting agent 72 will have at least essentially an external surface formed by collagen or a mixture of collagen. The number of deflecting agents 72 required during the repair or treatment of a borehole depends on the goals and characteristics of the individual borehole and the treatment used to stimulate the inflow and can be determined by a person skilled in the relevant field of technology.

In the practice of the described methods, the used diverting agent or a medium suitable for diverting the flow of working fluids to the designated treatment intervals is the diverting agent of the present invention, comprising substrate particles and a collagen outer layer slowly dissolving in water. In one embodiment, in order to reduce the likelihood of separation of the deflecting agent and the working fluid carrying particles of the deflecting agent, a variant of this collagen-containing deflecting system with neutral buoyancy can be used. A “neutral buoyancy” deflecting system is a system in which particles of the deflecting agent are suspended in a carrier working fluid when they have a sufficiently close density or specific gravity to obtain a mixture in which the solid components of the deflecting agent in the system are essentially, do not settle and do not float under static conditions. Such delamination may result, for example, in the accumulation of a deflecting agent in one or more places in the borehole and in blockage of the pipe string in sections of the borehole. In addition, delamination as a result may lead to a loss of deflection due to movement of the deflecting agent from the intervals to be processed. Deflecting systems with neutral buoyancy can be particularly advantageous in boreholes with a large inclination of the bore or with a horizontal wellbore, where gravity separation in a deflecting system with non-neutral buoyancy may not allow effective blockage or reduction of permeability around the entire circumference of the reservoir surface exposed in the borehole wells, due to, for example, migration of a deflecting agent up or down in a section with a large inclination of the barrel or in a horizontal section of the barrel b rovoy well.

Directional agents that can be used include the diverting agents of the present invention, having a slowly water-soluble external coating, individually or in combination with any selective plugging agent (e.g., oil soluble, acid soluble, etc.) suitable for use with the deviation of subsequent working fluids for processing at intervals with reduced throttle response. One suitable diverting agent for use in accordance with the present invention is a diverting agent, which is essentially collagen. Examples of suitable diverting agents that can be combined with the diverting agent of the present invention include, but are not limited to: benzoic acid flakes, wax (such as "Divert VI" available from BJ Services), cement grade gilsonite or uintaite polymers (including the following, but not limited to: natural polymers such as guar gum, or synthetic polymers such as polyacrylate), rock salt and the like. Other types of suitable selective plugging agents that can be used include, but are not limited to: acid-soluble selective plugging agents, such as those described in US Pat. No. 3,353,874, and phthalimide particles such as those described in US patent No. 4444264.

In one embodiment of the present invention, any type of carrier fluid may be used having a density suitable for use in preparing a neutral buoyancy diverting agent system, including natural or synthetic brines (such as KCl-water and the like) and carrier fluids liquids including gelling agents (such as conventional or synthetic polymers) or other weighting agents known in the art. Cement grade gilsonite (also known as “Uintate”) is a natural assortment of asphalts that are crushed and sorted into multi-fraction particles. This diverting agent composition at the wellsite can be mixed with special chemically modified fresh water (water containing, for example, from about 0.05% to about 1% wetting surfactant) to disperse gilsonite and optionally with a weighting agent (including the following, but not limited to them only: salts, such as KCl, NH ₄ Cl, NaCl, CaCl ₂ and the like) to control the density and / or stabilization of clays in the formation and with a gelling agent (polymer, such as guar gum, hydroxypropyl guar gum derivative, carboxymethyl hydroxypropyl guar gum derivative, carboxymethyl hydroxyethyl cellulose derivative, xanthan gum, carboxymethyl cellulose derivative and the like) to control viscosity and / or reduce flow resistance.

The diverting agent of the present invention is preferably present in a carrier fluid with concentrations ranging from about 0.001 pounds per gallon to about 10 pounds per gallon of carrier fluid, but concentrations outside this range can also be used. Most preferred concentrations of deflecting agents are in the range of from about 0.01 to about 6 pounds per gallon of carrier fluid. Concentrations of diverting agents of less than approximately 0.001 pounds per gallon will not provide for easy plugging of reservoirs when used in bulk carrier fluids that are typically available at an oil well borehole. To ensure proper plugging of formations at concentrations less than 0.001 pounds per gallon, progressively larger volumes of carrier fluid will be required.

Concentrations of a deflecting agent in excess of about 10 pounds per gallon will not appreciably increase the efficiency of the deflection of the treatment fluid and are therefore not particularly desirable in the practice of the present invention.

The carrier fluid is usually formed from water, brine, aqueous acid solutions or gel acid solutions. Gelation in acid solutions can be caused by celluloses, gums, polysaccharides, polyacrylamides, alkoxylated fatty amines and mixtures thereof.

When treatment is started, the deflecting agent can be added continuously to the carrier working fluid as the treatment fluid is pumped into the borehole of the borehole, or it can be added to the carrier working fluid at intervals between processing steps. For example, in acid treatment techniques, a diverting agent can be added to the acid treatment fluid continuously. In this way, the diverting agent will sequentially plug parts of the formation being treated, thereby preventing acid from flowing only into the most permeable parts of the formation, and instead forming the formation subjected to uniform acid treatment. In the case of stepwise injection of the working fluid for processing, the first stage is followed by the input of the volume of the deflecting material formed by the carrier working fluid, usually gelled or emulsified water, or an acid containing a plugging agent. The diverting agent clogs the portion of the formation into which the working fluid has penetrated to treat the first stage. After that, in another part of the reservoir pumped working fluid for processing the second stage. To obtain a formation subjected to uniform acid treatment, it is possible to continue the alternation of volumes of the working fluid for processing and material for selective plugging of the formation. Although hydraulic fracturing treatments can use the same technique for continuously injecting the diverting agent into the carrier fluid, during the fracturing operations, the diverting agent is usually added in batches to the carrier fluid.

Fluid for hydraulic fracturing, as you know, mainly flows into the part of the underground reservoir, which is easiest to receive fluid. After hydraulic fracturing of a given part of the formation, a plugging agent may be added to the hydraulic fracturing fluid to clog a portion of the formation already subjected to hydraulic fracturing. Since the hydraulic fracturing fluid mainly flows into the fracture zone, it will carry the plugging agent along with it. Thus, the area subjected to hydraulic fracturing will be blocked, and the flow of hydraulic fluid for hydraulic fracturing will be deflected from the most permeable part of the reservoir, which will still receive working fluids.

The implementation of this method of hydraulic fracturing and selective plugging of the reservoir in one aspect of the present invention can be repeated to obtain several cracks.

The diverting agent is removed from the formation by sublimation of the diverting agent or by solubilization of the diverting agent under the action of produced fluids. An increase in formation temperature results in a higher dissolution or sublimation rate of the diverting agent. For example, it was found that at approximately 250 ° F, approximately 80 weight percent of collagen slightly soluble in water will sublimate within 24 hours, while at 300 ° F approximately 95 weight percent will be sublimated within 24 hours, and at temperature equal to approximately 400 ° F, approximately 99% of slightly water-soluble collagen will sublimate / dissolve within approximately 24 hours. This demonstrates an increase in the rate of sublimation / dissolution of the diverting agent with increasing formation temperature.

The following examples are included to demonstrate preferred embodiments of the invention. Specialists in the relevant field of technology should understand that the methods described in the examples that follow are methods that, as discovered by the inventors, work well in the practical implementation of the invention, and thus they can be considered as forming the preferred options for its implementation on practice. However, in the light of the present description, specialists in the relevant field of technology should understand that many specific changes can be made to the specific embodiments that are described, which will still lead to a similar or similar result without deviating from the scope of the invention.

EXAMPLES

Example 1: Predictive Example

The following prognostic example describes a method of how a proppant soluble coating or fillers of the present invention can be used to divert the direction of crack growth and to increase cracks in a productive zone of an oil or gas well. The primary purpose of a proppant with a soluble coating is to determine the upper and lower boundaries in the vertical fracture resulting from hydraulic fracturing so that the main direction of growth continues to correspond to the direction in length from the inside out to the borehole. This additional length of the conductive crack contributes to the drainage of additional areas of the reservoir, which, as a result of the greater length of the crack, makes it possible to improve oil, gas and / or water utilization and the formation of more significant costs.

When using proppant materials with a soluble coating applied to the present invention, the following steps can be carried out.

1. When using a low-viscosity hydraulic fluid for hydraulic fracturing, the flow rate for injection for hydraulic fracturing is established.

2. Soluble coated proppants, such as crosslinked collagen coated walnuts, crosslinked collagen coated bauxite, or a combination of both of these options, are added to the mixer bath to form a slurry in hydraulic fracturing fluid layer.

3. Hydraulic fracturing fluid, including a proppant with a soluble coating, is pumped into the well. The first part of the suspension enters the initial crack, taking the main part of the working fluid. As a result, the liquid slowly clogs the boundaries of the formed crack through the use of a soluble deflecting agent, such as collagen, which slowly softens and swells in the working fluid.

4. As soon as the flow rate in the first crack decreases or decreases significantly, pressure begins to build up until the moment when another flow line, crack or zone begins to receive a suspension containing proppant with a soluble coating.

5. In the case where the proppant with the applied soluble coating should be limited to both the upper and lower parts of the crack, it will be preferable to use two different densities of the proppant. For example, a soluble collagen coating is applied to high-density bauxite particles, which slowly softens and swells when they drop into the lower part of the formed vertical fracture during hydraulic fracturing. To slow growth in a vertical crack upwards, a second low density proppant, such as a walnut shell with a coated coating, is added to the injected working fluid. When the injected working fluid reaches the formation, a proppant coated with a low-density soluble material will float in a vertical crack and reduce the loss of working fluid and growth from the bottom up.

6. Since the injection of fluid is still continued at a flow rate and pressure exceeding the flow rate and pressure for hydraulic fracturing, the fracture will continue to grow away from the borehole, and the growth of the fracture will be controlled by adjusting the flow rate of hydraulic fracturing . The injection is continued until the conventional proppant fills the crack, the pressure reaches a predetermined limit, or until they achieve the injection of the total planned volume.

7. Once growth is reduced up and down, standard proppants with an insoluble coating such as Ottawa Sand (20/40) sand, ceramic, or any number of resin proppants begin to be injected into the formation. Injection is continued until the entire amount of said proppant (or proppants) is placed in the formed cracks.

8. The borehole is stopped, and the pumping equipment is removed.

9. The borehole is returned to operation, and the soluble collagen coating on the walnut shell or bauxite is removed, since the soluble coating on the proppant dissolves the water in the formation over time.

Example 2: Methodology for determining the rate and degree of dissolution of the polymer

Coatings of various water-soluble polymers were applied to the sandy substrate:

Chemical name Trade name Provider Poly (ethylene) oxide WSR 80 Dow chemicals Poly (propylene) oxide WSRN 750 Dow chemicals Poly (propylene) oxide UCAR309 Dow chemicals Poly (lactic acid) PLA6551-D E&M specialties Poly (lactic acid) PLA5600 E&M specialties Poly (vinyl acetate / vinyl alcohol) PVA / Hydrolene Idroplax Inc. Collagen 1 Glue 512 Milligans and Higgins Collagen 2 GM bond Hormel foods

After that, the following test procedure was used to determine the rate and degree of solubility.

Determine the total mass of the polymer in the sand using the usual IFR technique. To 1 liter of water add 500 grams of coated sand. Take 400 mm of filter paper and weigh it on an analytical balance up to 4 decimal places. An apparatus for vacuum filtration is prepared using 400 mm filter paper, a perforated ceramic funnel, a 2-liter Erlenmeyer flask with a side opening connected to a vacuum pump by a rubber tube. The suspension, including coated sand and water, is filtered through 400 mm of filter paper after each interval of one minute. Sand with the coating do not forget to add back to the "filtered" water. After filtering is complete, the filter paper from the perforated funnel is removed and allowed to dry, storing it in a desiccator. Filter paper is weighed. This is the combined mass of dissolved polymer and filter paper, and thus it must exceed the mass of filter paper before it is used in the filtering process. % dissolved polymer is calculated using the following formula:

X = ((C-B) / A) x100,

where X = the percentage of dissolved polymer,

A = mass (g) of polymer on grains of sand,

B = mass (g) of the filter before the filtering process,

C = mass (g) of the filter after the filtering process.

Particles that swell and then dissolve Particles that dissolve without swelling UCAR309 WSR 80 COLLAGEN 1 WSRN750 COLLAGEN 2 PLA 6551-D PLA 5600

The results of this test procedure were that polyethylene oxide (WSR 80 from Dow Chemical) achieves complete dissolution at 80 ° F for approximately 300 minutes, at 150 ° F it takes approximately 180 minutes, and at 200 ° F it requires about 90 minutes.

The same test was carried out using another polymer. These results demonstrate that polymer polypropylene oxide (WSRN 750 from Dow Chemical) achieves complete dissolution at 80 ° F for approximately 390 minutes, at 150 ° F it takes approximately 320 minutes, and at 200 ° F approximately 245 minutes.

Polymers that swell show 100% solubility within 30 minutes, but microscopic analysis revealed retention on filter paper due to swelling rather than dissolution. The formation of a gel-like mass and a noticeable increase in the volume of the sand / water suspension indicate the swelling of the polymer, and not the dissolution of the polymer.

In the light of the present description, all compositions, methods and / or methods described and claimed in this document can be implemented and implemented without undue experimentation. While the compositions and methods of the present invention have been described using preferred embodiments as an example, it should be obvious to a person skilled in the art that without deviating from the concept and scope of the invention, the compositions, methods and / or methods and in the step or sequence stages of the methods described herein are subject to change. More specifically, it should be obvious that the agents described herein can be replaced by certain agents that are related to them both chemically and physiologically, while obtaining the same or similar results. All such similar substitutions and modifications, obvious to a person skilled in the relevant field of technology, are considered to fall within the scope and concept of the invention.

Claims (16)

1. Deflecting fluid for temporarily blocking the upper and lower parts of the treated interval in the subterranean formation by supplying the deflecting fluid to the holes defined by the borehole, which are in fluid communication with the treated interval, the deflecting fluid comprising an aqueous carrier fluid essentially consisting of water, in which the particles of the first deflecting agent and the particles of the second deflecting agent are dispersed, where the particles of each of the first and second deflecting agents include particles proppant substrates having a water-soluble polymer coating, wherein the particles of the first deflecting agent have a density greater than that of the aqueous carrier fluid, while the particles of the second deflecting agent have a density lower than the density of the aqueous carrier fluid, where water-soluble polymers of the particles of each of the first and the second deflecting agents are independently selected from the group consisting of type I collagen, type II collagen, type III collagen, type IV collagen, type V collagen, and mixtures thereof. 2. The diverting liquid according to claim 1, where the carrier liquid is at least one of water, brine, an aqueous acid solution and a gel-like acid solution. 3. The deflecting working fluid according to claim 1 or 2, where the particle density of the first deflecting agent is sufficiently higher than the density of the carrier fluid so that the particles of the first deflecting agent introduced into the treatment interval from the borehole can settle to the lower part of the treatment interval, forming a temporary lower boundary, essentially clogging the lower part of the treated interval with respect to the fluid flow through this lower boundary, and the particle density of the second deflecting agent is sufficiently m lower than the density of the carrier fluid, so that the particles of the first deflecting agent introduced into the treatment interval from the borehole can rise to the upper part of the treated interval, forming a temporary upper boundary, essentially clogging the upper part of the treated interval with respect to the fluid flow through this upper the border. 4. The deflecting liquid according to claim 1, where the particles of the proppant substrate of each of the first and second deflecting agents are independently selected from the group consisting of proppants from natural material, silica proppants, ceramic proppants, metal organic proppants and mixtures thereof, and substrates of proppant particles of the first and second deflecting agents are different from others ha. 5. Deflecting liquid according to claim 1, where the particles of the substrate proppant, at least one of the deflecting agents are proppants with a resin coating. 6. The deflecting liquid according to claim 1, wherein the proppant substrate particles of each of the first and second deflecting agents have a particle size in the range of from about 3 mesh to about 200 mesh. 7. Deflecting liquid according to claim 1, where the particles of at least one of the first and second deflecting agents further comprise a water-insoluble polymer. 8. The diverting liquid according to claim 7, where the water-insoluble polymer is selected from phenol-aldehyde novolac polymers and phenol-aldehyde resole polymers. 9. The diverting liquid according to claim 1, where the interval may be a single interval or multiple intervals. 10. The method of preparing the treated interval in the underground reservoir for hydraulic fracturing to increase the intensification of the inflow from the treated interval by hydraulic fracturing, including pumping the deflecting fluid according to claim 1 into the processed interval, which leads to the fact that
(a) particles of the first deflecting agent settle to the lower part of the treated interval, forming a temporary lower boundary, essentially clogging the lower part of the treated interval with respect to the fluid flow through this lower boundary,
(b) and the particles of the second deflecting agent rise to the upper part of the treatment interval, forming a temporary upper boundary, essentially clogging the upper part of the treatment interval with respect to the fluid flow through this upper boundary. 11. The method of claim 10, where the particles of the proppant substrate of each of the first and second deflecting agents are independently selected from the group consisting of proppants from natural material, silica proppants, ceramic proppants, synthetic organic proppants, and mixtures thereof, and substrates of proppant particles of the first and second deflecting agents are different from each other. 12. The method according to claim 11, where the particles of the substrate proppant, at least one of the deflecting agents are proppant with a resin coating. 13. The method of claim 10, where the proppant substrate particles of each of the first and second deflecting agents have a particle size in the range of from about 3 mesh to about 200 mesh. 14. The method of claim 10, where the particles of at least one of the first and second deflecting agents further comprise a water-insoluble polymer. 15. The method of claim 14, wherein the water-insoluble polymer is selected from phenol-aldehyde novolac polymers and phenol-aldehyde resole polymers. 16. The method of claim 10, where the interval may be a single interval or multiple intervals.

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