RU2824615C1 - Methods and compositions involving use of soluble thickened materials for deflection - Google Patents

Abstract

FIELD: chemistry; mining.

SUBSTANCE: group of inventions relates to production of hydrocarbons. Method of zonal isolation of a subterranean formation for intensification of hydrocarbon production involves introduction into a wellbore of a liquid for treating a subterranean formation containing a carrier fluid and a soluble material capable of forming a gel during hydration and creating a plug in the subterranean formation using the subterranean formation treatment fluid. Soluble material contains particles of a copolymer of butenediol and vinyl alcohol, capable of forming a plug in the subterranean formation. Average particle size of the copolymer of butenediol and vinyl alcohol ranges from 2 mm to 2 cm, where the particle size is the diameter of the smallest sphere which can contain the particle.

EFFECT: expansion of temperature range of diversion operations, increase of efficiency of prevention of drilling mud leakage into formation, simplification of operations in connection with possibility of pumping of diverting material of only one type.

13 cl, 6 dwg

Description

[0001] This document is a regular application that claims priority to Provisional Patent Application No. 62/913,929, filed October 11, 2019.

State of the art

[0002] The statements in this section provide background information only relating to the present invention and do not necessarily constitute prior art.

[0003] Some embodiments relate to methods applicable to a wellbore penetrating a subterranean formation, and more particularly to zonal isolation methods.

[0004] Hydrocarbons (oil, condensate, and gas) are typically produced from wells that are drilled into the formations that contain them. For a variety of reasons, such as the inherent low permeability of the reservoirs or formation damage caused by drilling and completing the well, the flow of hydrocarbons into the well is undesirably low. In this case, the well is "stimulated", such as by hydraulic fracturing, chemical (usually acid) stimulation, or a combination of the two (called acid hydraulic fracturing or acid fracking).

[0005] In acid hydraulic fracturing, a viscous fluid called a pad is first injected into the formation to initiate and propagate a fracture. A second fluid is then injected that contains a proppant that holds the fracture open after the injection pressure is released. Granular proppant materials may include sand, ceramic beads, or other materials. These types of materials are well known to those skilled in the art. In "acid" fracturing, the second fluid, which contains acid or another chemical such as a chelating agent, may dissolve some of the rock, causing uneven erosion of the fracture surface and removal of some minerals, causing the fracture to not close completely when injection is stopped. Sometimes hydraulic fracturing can be accomplished without the use of high viscosity fluid (i.e., using a water-based agent) to minimize damage caused by polymers or the cost of other viscosity enhancers.

[0006] Hydraulic and acid fracturing of horizontal wells and multi-layer formations often require the use of diversion technologies to redirect the hydraulic fracture between different zones. In other cases, the formation of highly conductive fractures (natural or induced) during hydraulic fracturing may inhibit the formation of new fractures. Thus, fracturing fluids that include a diversion agent can temporarily or permanently seal (i.e., plug) existing fractures, diverting the flow of fracturing fluids from areas of high permeability to areas of lower permeability, such as where stimulation will be more effective. These diversion methods include, but are not limited to, the use of mechanical isolation devices such as packers and plugs, blind plug stacks, sealing ball injection, suspended benzoic acid flocs, and removable/degradable solids. In addition, other treatments may require the use of diversion technologies.

[0007] Solids diversion treatments typically rely on the formation of a dam of diversion material particles behind the casing and the formation of a plug by the accumulation of the remaining particles in the dam. Some typical problems associated with particulate diversion treatments include: reduced plugging capacity of the diversion solution during pumping due to dilution by the wellbore fluid (interfacial mixing), the need to use relatively large amounts of diversion materials, and low stability of some diversion agents during pumping and subsequent treatment.

[0008] In other cases, during drilling of a wellbore, various fluids are typically used to perform various functions in the wellbore. Fluids may circulate through the drill pipe and drill bit into the wellbore and may then flow further up through the wellbore to the surface. During this circulation, drilling fluid may be used to perform the following functions: removing cuttings from the bottom of the wellbore to the surface, maintaining cuttings and weighting material in suspension in the event of an interruption in circulation, controlling wellbore pressure, maintaining wellbore integrity until a wellbore segment is cased or cemented, isolating fluids from the formation by providing sufficient hydrostatic pressure to prevent formation fluids from entering the wellbore, cooling and lubricating the drill string and bit, and/or maximizing the rate of penetration.

[0009] In other aspects, lost circulation may be a recurring problem in drilling that is characterized by the leakage of drilling fluid into wellbore formations. This may occur naturally in fractured, highly permeable, porous, or vuggy formations. Such subsurface formations may include, but are not limited to, shales, sands, gravels, shells, reef deposits, limestone, dolomite, and chalk. Other problems encountered in drilling and producing oil and gas include stuck pipe, wellbore collapse, loss of well control, and loss or reduction in production.

[00010] Lost circulation can be controlled by including an additive in the fluids pumped into the wellbore. The most common additive used to control or stop lost circulation is bentonite, which seals small holes or fractures. At higher concentrations, bentonite increases viscosity and slows the flow of fluid into the surrounding formation. Other solids, such as shredded paper, crushed corn cobs, and sawdust, are also used to control fluid loss. Polymers are also sometimes used to increase the viscosity of the wellbore fluid and control fluid loss. However, polymer additives are generally more expensive than particulate materials such as bentonite.

[0010] The methods and compositions described herein relate to deflection, zonal isolation, or technologies thereof.

SUMMARY OF THE INVENTION

[0011] In one aspect, a method for zonal isolation of a subterranean formation for enhancing hydrocarbon production is described, comprising: a. introducing into a wellbore a fluid for treating a subterranean formation, the fluid comprising a carrier fluid and a soluble material capable of forming a gel upon hydration, wherein the soluble material comprises particles of a copolymer of butenediol and vinyl alcohol capable of forming a plug in the subterranean formation, wherein the average particle size of the copolymer of butenediol and vinyl alcohol is from 2 mm to 2 cm, wherein the particle size is the diameter of the smallest sphere that can enclose the particle; and b. creating a plug in the subterranean formation using the fluid for treating the subterranean formation. The method preferably further comprises removing the plug.

In another aspect, a fluid for treating a subterranean formation is described, comprising a carrier fluid and a soluble material capable of forming a gel upon hydration, wherein the soluble material comprises particles of a copolymer of butenediol and vinyl alcohol capable of forming a plug in the subterranean formation, the average particle size of the copolymer of butenediol and vinyl alcohol being from 2 mm to 2 cm, where the particle size is the diameter of the smallest sphere that can contain the particle.

The butenediol-vinyl alcohol copolymer particles preferably have a cylindrical or rod-shaped form.

The subsurface treatment fluid preferably contains thermoplastic starch (TPS).

The fluid for treating an underground formation preferably additionally contains fibers.

The fluid for treating a subterranean formation preferably additionally contains a viscosity increaser or a friction reducer.

The carrier fluid is preferably a fluid selected from the group consisting of a water-based reagent, a spacer fluid, a co-solvent, a drilling fluid, a formation dissolution fluid, a fracturing fluid, a scale dissolution fluid, a wax dissolution fluid, an asphaltene dissolution fluid, a diverting fluid, a water influx control agent, a chelating agent, a viscoelastic diverting acid, a self-diverting acid system, an acid, and a mixture thereof.

BRIEF DESCRIPTION OF GRAPHIC MATERIALS

[0012] FIG. 1 shows solid particles and flocs, including dimensions, in accordance with aspects of the present invention.

[0013] FIG. 2 shows shapes of perforation channels in accordance with aspects of the present invention.

[0014] FIG. 3 shows a particle size distribution for reducing plug permeability in accordance with aspects of the present invention.

[0015] FIG. 4 shows a diverter packing in a near-wellbore region of a wellbore in accordance with aspects of the present invention.

[0016] FIG. 5 illustrates a laboratory setup for creating a plug in accordance with aspects of the present invention.

[0017] FIG. 6 shows the result of a dissolution study of a butenediol-vinyl alcohol copolymer according to aspects of the present invention.

DETAILED DESCRIPTION OF THE ESSENCE OF THE INVENTION

[0018] It should be noted at the outset that in developing any effective embodiments, numerous implementation-dependent decisions must be made to achieve the developer's particular goals, such as meeting system and plant operating constraints, which may vary from one embodiment to another. It should also be appreciated that such development efforts may be complex and time-consuming, but will nonetheless be routine for one skilled in the art having the benefit of the present invention.

[0019] The description and examples are presented solely for the purpose of illustrating certain embodiments and are not to be construed as limiting the scope and applicability. In the Summary and Detailed Description sections, each numerical value is to be read as modified by the term "about" (except where it is already expressly so modified) and then read as not so modified unless the context otherwise requires. Furthermore, when reading the Summary and Detailed Description sections, it is to be understood that a concentration range listed or described as useful, suitable, etc., is intended to include any and every concentration within the stated range, including the extremes. For example, "a range of 1 to 10" should be taken to describe any and all possible numbers in the continuum from about 1 to about 10. Thus, even if certain values within a range, or none of the values within a range, are explicitly stated or referred to as several specific values, it should be understood that the inventors intend and understand that any and all values within the range are to be considered as stated, and that the inventors have in mind the entire range and all values within that described range, and the entire range and all values within the stated range are valid.

[0020] The following definitions are provided to assist those skilled in the art in understanding the detailed description.

[0021] The term "processing" or "to process" refers to any underground operation that employs a fluid in conjunction with a desired function and/or desired purpose. The term "processing" or "to process" does not imply any specific action of the fluid.

[0022] The term "hydraulic fracturing" refers to the process and methods of breaking a geological formation and creating a crack, i.e., the rock around a wellbore, by injecting fluid at very high pressures (pressures in excess of a certain closure pressure) in order to increase the rate of production from a hydrocarbon reservoir. Other hydraulic fracturing methods employ conventional techniques known in the art.

Vinyl alcohol copolymer

[0023] The present invention provides soluble materials for ultra-low temperature deflection in a hydraulic fracturing operation. As a temporary deflecting agent, such treatment fluids can comprise soluble particles based on a vinyl alcohol copolymer (e.g., a butenediol-vinyl alcohol copolymer). In one aspect, the treatment fluids can comprise at least about 0.5 wt. % of a butenediol-vinyl alcohol copolymer. In embodiments, the treatment fluids can comprise up to about 5.0 wt. % of a butenediol-vinyl alcohol copolymer. The biodegradable and environmentally friendly polymer butenediol-vinyl alcohol copolymer can be capable of bridging narrow fracture sections, such as those encountered during hydraulic fracturing operations. Typically, deflecting agents are capable of diverting a portion of the treatment fluids to a specific area of the subterranean zone. The diverting agents of the present invention may also be capable of bridging narrow fracture zones, such as those encountered during hydraulic fracturing or acidizing operations.

[0024] Since the vinyl alcohol copolymer particles are transported through fractures located in the near-wellbore region of the wellbore in this case, the particles can stick together and bridge the fracture(s). The soluble materials are capable of forming a low-permeability gel when hydrated and can also dissolve in a short period of time (about 8 hours) at ultra-low temperature (below 49 °C (120 °F)). In one embodiment, the soluble vinyl alcohol copolymer material can form a sticky gel or a swelling gel. The sticky (i.e., adhesive) properties or swelling ability of the hydrated particles can prevent the diverting material from spreading during transport, promote bridging and reduce permeability within the diverting pack. The hydrated particles can form a low permeability gel, which may not require the use of different particle sizes or fibrous materials to achieve said low permeability. In some embodiments, the degradation of the vinyl alcohol copolymer material can occur at a temperature of from about room temperature to 65 ° C (150 ° F). The soluble thickened material can extend the temperature range of deflection operations and improve the efficiency of the operation compared to the use of exclusively degradable materials, such as polylactide and the like, which take months to decompose at temperatures below 49 ° C (120 ° F). This material can also simplify the operation, since only one type of deflection material may need to be pumped during the operation.

[0025] The soluble vinyl alcohol copolymer diverting material may comprise one or more non-deformable bridging particles. The diverting mixture may or may not comprise degradable or non-degradable fibers. As the soluble diverting material is transported through the fractures of the near-wellbore region, larger particles may begin to bridging, triggering the accumulation of diverting particles. During this process, small particles may occupy the interstitial space between the larger particles, as shown in FIG. 4. As the large and small particles are packed, permeability may decrease, causing the near-wellbore region to divert. If a fibrous material is used, this may assist in the transport of the diverting material, prevent it from spreading during transport, assist in bridging, and/or reduce permeability within the diverting pack.

[0026] The soluble deflecting materials described herein may comprise poly(vinyl alcohol) (PVOH), such as a butenediol-vinyl alcohol copolymer and/or a thermoplastic starch blend, etc.

[0027] The particles of the present invention may have different sizes. In particular, the material based on a vinyl alcohol copolymer may have particles of different sizes, such as, for example, a cross-sectional diameter of about 4.5 mm, 2.5 mm, 1 mm, 0.6 mm, 200 microns.

[0028] The soluble diverting materials of the present invention may exist in the form of solid particles; the terms "particle" or "solid particle" as used herein may refer to a solid three-dimensional object with a maximum dimension that is, for example, significantly less than 1 meter. Furthermore, the "dimension" of an object refers to the distance between two arbitrary parallel planes, each of which touches the surface of the object at at least one point. The maximum or maximum dimension refers to the largest distance existing for said object between any two parallel planes, and the minimum or minimum dimension refers to the smallest distance existing for said object between any two parallel planes. In some embodiments, the particles used in the present invention may have a ratio between the maximum and minimum dimensions (particle size ratio x/y) of less than 5 or even less than 3, as shown in FIG. 1.

[0029] The term "flake" may refer to a type of solid particle as defined above. A flake particle may be a solid three-dimensional object whose thickness is smaller than its other dimensions, such as length and width. The aspect ratios of a flake particle (diameter/thickness, length/thickness, width/thickness) may be in the range of about 5 to about 50 or more, as shown in FIG. 1. With respect to a flake particle, the aspect ratio may be the ratio of the length or width to its thickness. Any suitable ratio of length and width may be used herein.

[0030] The terms "particle size," "solid particle size," or "flocculant particle size" may refer to the diameter of the smallest imaginary circumscribed sphere that can enclose such solid or flocculant particle.

[0031] For the purposes of the present invention, the components of the treatment fluid may comprise solid and flake-like particles having a uniform or non-uniform structure, made, for example, from porous or composite materials.

[0032] The particles or flakes of the present invention can be implemented as proppants. Such proppants can be natural or synthetic (including, but not limited to, glass beads, ceramic beads, sand and bauxite), can be coated or contain chemicals; and when more than one, they can be used sequentially or in mixtures of different sizes or different materials. The said proppant can be coated with a resin (curable), coated with a pre-cured resin, or can have a corrosion-resistant material applied. The proppants and gravel in the same or different wells or treatments can be the same material and/or can have the same size, and in the present invention the term "proppant" is intended to include gravel. In some embodiments, particles of any suitable shape can be used as proppants, such as rod-shaped particles, elongated particles, plate-shaped particles, and the like. Such particles may also have any suitable cross-sectional shape, such as cylindrical, etc. In one embodiment, the treatment fluids may comprise a mixture of soluble materials that are rod-shaped, flake-shaped, or cylindrical in cross-section. Improved overlapping properties have been demonstrated using a mixture of both flake-shaped and cylindrical in cross-section particles.

[0033] The term "average size" may refer to the average size of solid inclusions in a group of solid inclusions of each type. In each group j of particles or flakes, the average size may be calculated as a mass-weighted value.

where N is the number of particles or flakes in a group, , (i=1…N) - sizes of individual particles or flakes; m _i , (i=1…N) - masses of individual particles or flakes.

[0034] The term "hole" may refer to a two-dimensional object of any geometry that is limited only by its perimeter. The term "hole diameter" or "hole size" may refer to the diameter of the largest imaginary circle that is inscribed in such a hole.

[0035] Although embodiments described herein may relate to well treatment operations, they may also be applicable to any well operations where zonal isolation occurs, such as drilling operations, workover operations, etc.

[0036] A method of treatment for diversion or for temporary zonal isolation is described. The method uses a composition that may comprise mixtures of particles or mixtures of particles and flakes. According to one embodiment, the size(s) of the largest particles or flakes in the mixtures may be slightly smaller than the diameter of the perforations in the zone to be isolated or diverted. According to a further embodiment, the size of the particles or flakes in the mixtures may be larger than the average width of the void that is to be closed or temporarily isolated. The average width of the void may be the smallest width of the void after the perforation or other entrance to such a void, at a distance of 10 cm, 20 cm, 30 cm or 50 cm or 500 cm, for example, at the transition from the wellbore to the formation. Such voids may be a perforation tunnel, a hydraulic fracture or a wormhole channel, as shown in FIG. 2. The introduction of mixtures or compositions into perforations may cause the largest particles to become stuck in voids in the immediate vicinity of the wellbore. Other particles may then accumulate on the resulting plug. In one embodiment, the ratio of particles to flakes in the mixtures may be calculated to reduce the permeability of the plugs formed.

[0037] According to one aspect, the treatment fluids of the present invention can provide zonal isolation by creating plugs in the vicinity of the wellbore. Compared to traditional diversion treatment technologies, the compositions of the present invention may require a smaller amount of diverting material. The advantages of using the fluids of the present invention include a reduced risk of wellbore plugging, a reduced risk of formation damage, and improved cleaning. In an example where the diverting mixture is intended to seal perforation channels (e.g., when treating with water-based reagents), the amount of diverting material required for diverting between several perforation clusters may be as little as a few kilograms. The removal of the diverting material is ensured either by self-decomposition under wellbore conditions, or by the introduction of special chemical reagents, or by downhole operations.

Fibers

[0038] In some embodiments of the present invention, the treatment fluids may optionally comprise fibers (both degradable and non-degradable, together or separately). In embodiments, the fibers may assist in binding the polyvinyl alcohol particles. The fibers may be straight, curved, bent, or wavy. Other non-limiting shapes may include hollow, substantially spherical, rectangular, polygonal, etc. The fibers or elongated particles may be used in bundles. The fibers may have a length from less than about 1 mm to about 30 mm or more. In some embodiments, the fibers may have a length of 12 mm or less with a diameter or cross-sectional dimension of about 200 microns or less, typically from about 10 microns to about 200 microns. In the case of elongated materials, the materials may have a ratio between any two of the three dimensions of greater than 5:1. In some embodiments, the fibers or elongated materials may have a length greater than 1 mm, from about 1 mm to about 30 mm, from about 2 mm to about 25 mm, from about 3 mm to about 20 mm, which is typical. In certain applications, the fibers or elongated materials may have a length of from about 1 mm to about 10 mm (e.g., 6 mm). The fibers or elongated materials may have a diameter or cross-sectional dimension of from about 5 to 100 microns and/or fiber counts of from about 0.1 to about 20, more particularly, fiber counts of from about 0.15 to about 6.

[0039] The fiber may be formed from a degradable material or a non-degradable material. The fiber may be organic or inorganic. Non-degradable materials are materials in which the fiber remains substantially in its solid form within the wellbore fluids. Examples of such materials include glass, ceramics, basalt, carbon and carbon-based compounds, metals and metal alloys, etc. Polymers and plastics that do not degrade may also be used as non-degradable fibers. These may include high-density plastic materials that are resistant to acids and oils and have a crystallinity of greater than 10%. Other non-limiting examples of polymeric materials include nylons, acrylics, styrenes, polyesters, polyethylene, oil-resistant thermosetting resins, and combinations thereof.

[0040] Degradable fibers may include materials that can be softened, dissolved, reacted, or otherwise caused to degrade in wellbore fluids. Such materials may be soluble in aqueous fluids or hydrocarbon fluids. Oil-degradable materials in the form of solid particles that degrade in produced fluids may be used. Non-limiting examples of degradable materials may include, but are not limited to, polyvinyl alcohol, polyethylene terephthalate (PET), polyethylene, soluble salts, polysaccharides, waxes, benzoic acid, naphthalene-based materials, magnesium oxide, sodium bicarbonate, calcium carbonate, sodium chloride, calcium chloride, ammonium sulfate, soluble resins, and the like, as well as combinations thereof. Degradable materials may also include materials that are formed from solid acid precursor materials. These materials may include polylactic acid (PLA), polyglycolic acid (PGA), carboxylic acid, lactide, glycolide, PLA or PGA copolymers, etc., and combinations thereof. Such materials may also further assist in formation dissolution during acid fracturing treatment.

[0041] Additionally, the fibers may be any fibrous material such as, but not limited to, natural organic fibers, ground plant materials, synthetic polymer fibers (a non-limiting example being polyester, polyaramid, polyamide, novoloid, or novoloid-type polymer), fibrillated synthetic organic fibers, ceramic fibers, inorganic fibers, metal fibers, metal threads, carbon fibers, glass fibers, ceramic fibers, natural polymer fibers, and any mixtures thereof. Particularly useful fibers are coated polyester fibers that provide high hydrophilicity, such as, but not limited to, DACRON® polyethylene terephthalate (PET) fibers available from Invista Corp., Wichita, Kansas, U.S.A. 67220. Other examples of useful fibers include, but are not limited to, polylactic acid polyester fibers, polyglycolic acid polyester fibers, polyvinyl alcohol fibers, and the like.

[0042] The polymer fibers comprise polyesters obtained by polymerization of hydroxycarboxylic acids, such as aliphatic polyester of lactic acid, called polylactic acid; glycolic acid, called polyglycolic acid; 3-hydroxybutyric acid, called polyhydroxybutyrate; 2-hydroxyvaleric acid, called polyhydroxyvaleric acid; epsilon-caprolactone, called polypsilon-caprolactone or polyprolactone; polyesters obtained by esterification of hydroxylamine acids, such as serine, threonine and tyrosine; and copolymers obtained from mixtures of the monomers listed above. The homopolyesters described above have the following general structure:

H- {O-[C(R1,R2)] _x -[C(R3,R4)] _y -C=O} _z -OH

Where

R1, R2, R3, R4 are either H, a linear alkyl _such as _CH3 , _CH2CH3 , _{( CH2} ) _nCH3 , a branched alkyl, aryl, alkylaryl, an alkyl functional group (bearing carboxylic acid groups, amino groups, hydroxyl groups, thiol groups or other groups), or an aryl functional group (bearing carboxylic acid groups, amino groups, hydroxyl groups, thiol groups or other groups);

x is an integer between 1 and 11;

y is an integer between 0 and 10; and

z is an integer between 2 and 50,000.

[0043] Under appropriate conditions (e.g. pH, temperature, water content), the polyesters described herein can hydrolyze and decompose to form hydroxycarboxylic acid and compounds that are related to those acids referred to above as "monomeric acids."

[0044] One example of a suitable polymeric acid precursor, as mentioned above, is a polymer of lactic acid, sometimes referred to as polylactic acid, "PLA", polylactate or polylactide. Lactic acid is a chiral molecule and has two optical isomers. These are D-lactic acid and L-lactic acid. The poly(L-lactic acid) and poly(D-lactic acid) forms are substantially crystalline in nature. Polymerization of a mixture of L- and D-lactic acids to poly(DL-lactic acid) results in the formation of a polymer that is more amorphous in nature. The polymers described herein are substantially linear. The degree of polymerization of linear polylactic acid can range from a few units (2-10 units) (oligomers) to several thousand (e.g., 2,000-5,000). Cyclic structures can also be used. The degree of polymerization of these cyclic structures may be lower than that of linear polymers. These cyclic structures may include cyclic dimers.

[0045] Another example is a polymer of glycolic acid (hydroxyacetic acid), also known as polyglycolic acid (PGA) or polyglycolide. Other materials suitable as polymeric acid precursors are all of these polymers of glycolic acid alone or with other hydroxy acid-containing moieties.

[0046] Both polylactic acid and polyglycolic acid can be used as homopolymers, which can contain less than about 0.1% by weight of other comonomers. As used with respect to polylactic acid, the term "homopolymer(s)" is intended to include polymers of D-lactic acid, L-lactic acid, and/or blends or copolymers of pure D-lactic acid and pure L-lactic acid. In addition, random copolymers of lactic acid and glycolic acid and block copolymers of polylactic acid and polyglycolic acid can be used. Combinations of the described homopolymers and/or the above-described copolymers can also be used. Random, block, graft, star, and hyperbranched aliphatic polyesters can also be used.

[0047] Other examples of polyesters of hydroxycarboxylic acids that can be used as precursors of polymeric acids can include polymers of hydroxyvaleric acid (polyhydroxyvalerate), hydroxybutyric acid (polyhydroxybutyrate), and copolymers thereof with other hydroxycarboxylic acids. Polyesters obtained by ring-opening polymerization of lactones, such as epsiloncaprolactone (polypsiloncaprolactone) or copolymers of hydroxy acids and lactones, can also be used as precursors of polymeric acids.

[0048] Polyesters obtained by esterification of other hydroxyl-containing acid-containing monomers, such as hydroxyamino acids, can be used as precursors of polymeric acids. Naturally occurring amino acids are L-amino acids. Among the 20 most common amino acids, the three containing hydroxyl groups are L-serine, L-threonine and L-tyrosine. These amino acids can be polymerized to obtain polyesters at the appropriate temperature and using appropriate catalysts by reacting their alcohol and their carboxylic acid group. D-amino acids are less common in nature, but their polymers and copolymers can also be used as precursors of polymeric acids.

[0049] NatureWorks, LLC, Minnetonka, Minnesota, U.S.A., produces a solid dimer of cyclic lactic acid called "lactide" and from it polymers or polylactates of lactic acid of various molecular weights and degrees of crystallinity are prepared under the general trade name NATUREWORKS™ PLA. The PLAs currently available from NatureWorks, LLC have number average molecular weights (Mn) up to about 100,000 and weight average molecular weights (Mw) up to about 200,000, although any polylactide (produced by any process by any manufacturer) may be used. The materials listed as available from NatureWorks, LLC typically have crystalline melting points of about 120 °C to about 170 °C, but other materials are available. Poly(d, l-lactide) of various molecular weights is also commercially available from Bio-Invigor, Beijing and Taiwan. In addition, Bio-Invigor supplies polyglycolic acid (also known as polyglycolide) and various copolymers of lactic acid and glycolic acid, often referred to as "polyglactin" or poly(lactide-coglycolide).

[0050] The polymers of the present invention may be in crystalline form, wherein the degree of crystallinity can be controlled by the method of production of homopolymers, as well as the method of production, ratio and distribution of lactide and glycolide for copolymers. In addition, the chirality of the lactic acid used also affects the crystallinity of the polymer. Polyglycolide can be made in a porous form. Some polymers dissolve very slowly in water before hydrolysis.

[0051] Amorphous polymers may be useful in certain applications. An example of a commercially available amorphous polymer is NATUREWORKS™ 4060D PLA polymer, available from NatureWorks, LLC, which is a poly(DL-lactic acid) and contains approximately 12 wt.% D-lactic acid and has a number average molecular weight (Mn) of approximately 98,000 g/mol and a weight average molecular weight (Mw) of approximately 186,000 g/mol.

[0052] Other polymeric materials that may be useful are polyesters obtained by polymerizing polycarboxylic acid derivatives, such as dicarboxylic acid derivatives, with polyhydroxy-containing compounds, in particular dihydroxy-containing compounds. Polycarboxylic acid derivatives that can be used are dicarboxylic acids such as oxalic acid, propanedioic acid, malonic acid, fumaric acid, maleic acid, succinic acid, glutaric acid, pentanedioic acid, adipic acid, phthalic acid, isophthalic acid, terephthalic acid, aspartic acid or glutamic acid; polycarboxylic acid derivatives such as citric acid, copolymers of poly- and oligoacrylic acid and methacrylic acid; dicarboxylic acid anhydrides such as maleic anhydride, succinic anhydride, pentanedioic anhydride, adipic anhydride, phthalic anhydride; dicarboxylic acid halides, especially dicarboxylic acid chlorides such as propanedioacyl chloride, malonyl chloride, fumaroyl chloride, maleyl chloride, succinyl chloride, glutaroyl chloride, adipoyl chloride, phthaloyl chloride. Suitable polyhydroxy-containing compounds are dihydroxy compounds such as ethylene glycol, propylene glycol, 1,4-butanediol, 1,5-pentanediol, 1,6-hexanediol, hydroquinone, resorcinol, bisphenols such as bisphenol acetone (bisphenol A) or bisphenol formaldehyde (bisphenol F); polyols such as glycerol. When both a dicarboxylic acid derivative and a dihydroxy compound are used, a linear polyester is obtained. It should be understood that when one type of dicarboxylic acid and one type of dihydroxy compound are used, a linear homopolyester is obtained. When several types of polycarboxylic acids and/or a polyhydroxyl-containing monomer are used, copolyesters are obtained. According to Flory-Stockmayer kinetics, the "functionality" of the polycarboxylic acid monomers (the number of acid groups per monomer molecule) and the "functionality" of the polyhydroxyl-containing monomers (the number of hydroxyl groups per monomer molecule) and their respective concentrations will determine the configuration of the polymer (linear, branched, star-shaped, lightly crosslinked or fully crosslinked). All of these configurations can be hydrolyzed or "decomposed" to carboxylic acid monomers and can therefore be considered as precursors to polymeric acids. As a particular example, without giving an exhaustive list of all possible polyester structures that could be considered, but just to give a general structure of a case that might occur, the general structure of linear monopolyesters could be as follows:

H- {O-R1-OC=O-R2-C=O} _z -OH

Where

R1 and R2 represent linear alkyl, branched alkyl, aryl, alkylaryl groups; and

z is an integer between 2 and 50,000.

[0053] Other examples of suitable polymeric acid precursors are polyesters derived from phthalic acid derivatives, such as polyethylene terephthalate (PET), polybutylene terephthalate (PBT), polyethylene enphthalate (PEN), etc.

[0054] The compositions of the present invention can be made from mixtures of particles or mixtures of particles and flocs in a carrier fluid. The carrier fluid can be water, including fresh water, formation water, sea water. Other non-limiting examples of carrier fluids include hydratable gels (e.g., guar gums, polysaccharides, xanthan, hydroxyethyl cellulose, etc.), a cross-linked hydratable gel, a thickened acid (e.g., gel-based), an emulsified acid (e.g., an oil external phase), an activated fluid (e.g., a foam based on N ₂ or CO ₂ ), and an oil-based drilling mud containing gelled, foamed, or otherwise thickened oil. In addition, the carrier fluid can be a brine and/or can contain a brine. The carrier fluid may include an acid, including, but not limited to, hydrochloric acid, hydrofluoric acid, ammonium bifluoride, formic acid, acetic acid, lactic acid, glycolic acid, maleic acid, tartaric acid, sulfamic acid, malic acid, citric acid, methylsulfamic acid, chloroacetic acid, aminopolycarboxylic acid, 3-hydroxypropionic acid, polyaminopolycarboxylic acid, and/or a salt of any acid. In certain embodiments, the carrier fluid may include polyaminopolycarboxylic acid, trisodium hydroxylethylethylenediamine triacetate, monoammonium salts of hydroxylethylethylenediamine triacetate, and/or monosodium salts of hydroxylethylethylenediaminetetraacetate.

[0055] Such a solid polymeric acid precursor material may undergo irreversible degradation downhole into primary acid products. As referred to herein, the term "irreversible" shall mean that the solid polymeric acid precursor material, once degraded downhole, shall not be recovered downhole, e.g., the material shall degrade in situ but shall not be recovered in situ. The term "degradation" refers to both the two relatively extreme cases of hydrolytic degradation that the solid polymeric acid precursor material may undergo, e.g., bulk erosion and surface erosion, and to any stage of degradation between these two states. This degradation may be the result of, among other things, a chemical reaction. The rate at which the chemical reaction occurs may depend on, among other things, the added chemicals, temperature, and time. The degradation of the solid polymeric acid precursor materials may or may not depend, at least in part, on its structure. For example, the presence of hydrolyzable and/or oxidizable bonds in the backbone often results in a material that will degrade as described herein. The rate of degradation of such polymers depends on factors such as, but not limited to, the repeat unit type, composition, sequence, length, molecular geometry, molecular weight, morphology (e.g., crystallinity, spherulite size, and orientation), hydrophilicity, hydrophobicity, surface area, and additives. The mode of degradation of the polymer can also be affected by the environment to which the polymer is exposed, such as temperature, presence of moisture, oxygen, microorganisms, enzymes, pH, etc.

[0056] Another class of suitable solid polymeric acid precursor material that can be used includes polyamides and polyimides. Such polymers can contain hydrolyzable groups in the polymer backbone that can hydrolyze under the conditions found in cement slurries and in the hardened cement matrix. Such polymers can also form by-products that can be sorbed by the cement matrix. Calcium salts are a non-limiting example of such by-products. Non-limiting examples of suitable polyamides include proteins, polyamino acids, nylon, and poly(caprolactam). Another class of polymers that may be suitable for use are polymers that can contain hydrolyzable groups not in the polymer backbone, but as pendant groups. Hydrolysis of the pendant groups can result in the formation of a water-soluble polymer and other by-products that can be sorbed by the cement composition. A non-limiting example of such a polymer includes polyvinyl acetate, which upon hydrolysis forms water-soluble salts of polyvinyl alcohol and acetate.

[0057] The particle(s) or flakes may be embodied in the form of a material that reacts with chemical agents. Some examples of materials that can be removed by reacting with other agents are carbonates, including calcium and magnesium carbonates and mixtures thereof (reacting with acids and chelates); acid-soluble cement (capable of reacting with acids); polyesters, including lactic hydroxycarboxylic acid esters and their copolymers (capable of hydrolyzing by acids and bases); active metals such as magnesium, aluminum, zinc and their alloys (capable of reacting with water, acids and bases), etc. The particles and flakes may also be embodied in the form of a material that accelerates the destruction of other components of the formed plug. Some non-limiting examples of this are the use of metal oxides (e.g. MgO) or bases (e.g. Mg(OH) ₂ ; Ca(OH) ₂ ) or salts of weak acids (e.g. _CaCO3 ) to accelerate the hydrolysis of polyesters such as polylactic or polyglycolic acids.

[0058] The particle(s) or flakes can be implemented as fusible materials. Examples of fusible materials that can be melted at downhole conditions are hydrocarbons with a carbon number greater than 30, including, but not limited to, polycaprolactones, paraffin, waxes or carboxylic acids such as benzoic acid and its derivatives, etc. Wax particles can be used. These particles are solid at the temperature of the injected fluid, and this fluid cools the formation sufficiently so that the particles enter the formation and remain solid. Hydrous wax can typically be used in wood coatings, wood processing, paper and cardboard processing, protective coatings for architectural and industrial applications, paper coatings, rubber and plastics, inks, textiles, ceramics, etc. They are manufactured by companies such as Hercules Incorporated, Wilmington, Delaware, U.S.A., under the trade name PARACOL®, Michelman, Cincinnati, Ohio, U.S.A., under the trade name MICHEM®, and ChemCor, Chester, New York, U.S.A. Particularly suitable waxes include those commonly used in commercial car washes. In addition to paraffin waxes, other waxes such as polyethylenes and polypropylenes may also be used.

[0059] The particle(s) or flakes can be implemented in the form of a water-soluble material or a hydrocarbon-soluble material. The list of materials that can be used for dissolution in water can include water-soluble polymers, water-soluble elastomers, carbonic acids, rock salt, amines, inorganic salts. The list of materials that can be used for dissolution in oil includes oil-soluble polymers, oil-soluble resins, oil-soluble elastomers, polyethylene, carbonic acids, amines, waxes.

[0060] The size of the particle(s) and flakes may be selected such that the size of the largest particles or flakes is slightly smaller than the diameter of the perforations in the casing and larger than the average width of the voids behind the casing (perforations, fractures or wormholes). A perforation is any type of hole in the casing. Such a hole may be a perforation, a hole from a jetter, a hole from a slotted liner, a port or any hole in a completion tool, a point of exit of the casing fluid. According to another embodiment, the size of the particles or flakes in the mixture is designed to reduce the permeability of the plugs in narrow voids behind the casing (perforations, fractures or wormholes). Typically, the particles or flakes used will have an average size of less than a few centimeters, preferably less than 2 cm, and more preferably less than 1 cm. In one embodiment, some of the particles or flakes will have an average size of from about 0.2 mm to about 4.76 mm, preferably from about 0.5 mm to about 4.76 mm, more preferably from about 1 mm to about 4.76 mm, and other particles will have an average particle size of from 0.04 mm to about 2 mm, preferably from 0.04 mm to about 1.5 mm, more preferably from 0.1 mm to 1 mm.

[0061] According to a further embodiment, said compositions may comprise particles or flakes with different particle/fake size distributions. In one embodiment, said composition comprises solid particle materials with a given particle size distribution.

[0062] In some embodiments, the selection of the size of the first amount of solid particles depends on the characteristics of the perforated hole, as described above: the size of the largest particles or flakes is slightly smaller than the diameter of the perforations in the casing. In some additional embodiments, the selection of the size of the first amount of particles depends on the voids behind the casing: the size of the particles is greater than the average width of the voids behind the casing (perforations, cracks or wormholes). In some additional embodiments, the selection of the size of the first amount of particles depends on the characteristics of the perforated hole and the voids behind the casing: the size of the largest particles or flakes is slightly smaller than the diameter of the perforations in the casing and greater than the average width of the voids behind the casing (perforations, cracks or wormholes). In some additional embodiments, the selection of the size of the first amount of solid particles depends on the desired fluid loss control characteristics of the first amount of solid particles used as a fluid loss control agent, the pore size of the formation, and/or commercially available sizes of solid particles of the type contained in the first amount of solid particles.

[0063] In some embodiments, the selection of the size of the second amount of solid particles depends on the desired fluid loss control characteristics of the second amount of solid particles used as a fluid loss control agent, the pore size of the formation, and/or the commercially available sizes of solid particles of the type contained in the second amount of solid particles.

[0064] In some embodiments, the selection of the size of the second amount of solid particles depends on the desired fluid loss control characteristics of the second amount of solid particles used as a fluid loss control agent, the pore size of the formation, and/or commercially available sizes of solid particles of the type contained in the second amount of solid particles. The particle size is in the range of 10-100% of the size of the first amount of solid particles, more preferably 20-80% of the size of the first amount of solid particles.

[0065] In some embodiments, the selection of the particle size of the solid particles depends on maximizing or optimizing the packed volume fraction (PVF) of the mixture of the first amount of solid particles and the second amount of solid particles. The PVF or packed volume fraction is the volume fraction of the solid content relative to the total volume of the content. The particle size distribution required to maximize the PVF in a narrow gap may differ from the particle size distribution required to maximize the PVF in a continuous system. Therefore, in some embodiments, the selection of the particle size of the solid particles depends on maximizing or optimizing the PVF of the mixture of the first amount of particles and the second amount of particles in narrow voids of between 2 mm and 2 cm. In some embodiments, the selection of the particle size of the solid particles depends on maximizing or optimizing the PVF of the mixture of the first amount of particles and the second amount of particles in a crack or crevice of less than 20 mm in width. In some embodiments, the solid particles as a whole have a PVF greater than 0.74, or 0.75, or greater than 0.80. In some further embodiments, the solid particles may have a much higher PVF value, approaching 0.95.

[0066] In some additional embodiments, the composition may further comprise a third number of particles/flakes having a third average particle size that is smaller than the second average particle size/flakes. In some additional embodiments, the same chemical composition may be used for the second, third, fourth, or fifth average particle size/flakes. In order to improve the PVF composition, additional particles may be added for other reasons, such as the chemical composition of the additional particles, ease of production of certain materials for the same particles versus different particles, commercial availability of particles having certain properties, and other reasons understood in the art.

[0067] In some additional embodiments, the composition may further comprise a viscosity enhancer. The viscosity enhancer may be any cross-linked polymer. The polymeric viscosity enhancer may be a metal-cross-linked polymer. Suitable polymers for making metal-cross-linked polymeric viscosity enhancers include, for example, polysaccharides such as substituted galactomannans such as guar gums, high molecular weight polysaccharides consisting of mannose and galactose sugars, or guar derivatives such as hydroxypropyl guar (HPG), carboxymethylhydroxypropyl guar (CMHPG), and carboxymethyl guar (CMG), hydrophobically modified guars, guar-containing compounds, and synthetic polymers. Crosslinking agents based on boron, titanium, zirconium or aluminum complexes are typically used to increase the effective molecular weight of the polymer and improve their suitability for use in high-temperature wells.

[0068] Other suitable classes of polymers effective as viscosity enhancers include polyvinyl polymers, polymethacrylamides, cellulose ethers, lignosulfonates, and their ammonium, alkali metal, and alkaline earth metal salts. More specific examples of other typical water-soluble polymers are copolymers of acrylic acid and acrylamide, copolymers of acrylic acid and methacrylamide, polyacrylamides, partially hydrolyzed polyacrylamides, partially hydrolyzed polymethacrylamides, polyvinyl alcohol, polyalkylene oxides, other galactomannans, heteropolysaccharides obtained by sugar fermentation, and their ammonium and alkali metal salts.

[0069] To a lesser extent, cellulose derivatives such as hydroxyethyl cellulose (HEC) or hydroxypropyl cellulose (HPC), carboxymethyl hydroxyethyl cellulose (CMHEC), and carboxymethyl cellulose (CMC), with or without crosslinkers, are used. Xanthan, diutan, and scleroglucan, three biopolymers, have been shown to have superior particle suspending ability, even though they are more expensive than guar derivatives and are therefore used less frequently unless they cannot be used at lower concentrations.

[0070] In other embodiments, the viscosity enhancer is obtained from a crosslinkable, hydratable polymer and a crosslinking retarder, wherein the crosslinking agent comprises a complex containing a metal and a first ligand selected from the group consisting of amino acids, phosphonic acids and salts or derivatives thereof. Also, the crosslinked polymer can be obtained from a polymer containing pendant ionic moieties, a surfactant containing oppositely charged moieties, a clay stabilizer, a borate source and a metal-based crosslinking agent.

[0071] The viscosity enhancer may be a viscoelastic surfactant (VES). The VES may be selected from the group consisting of cationic, anionic, zwitterionic, amphoteric, nonionic substances and combinations thereof. Viscoelastic surfactants, when used alone or in combination, are capable of forming micelles that form a structure in an aqueous medium that contributes to an increase in the viscosity of the fluid (also called "viscosity-increasing micelles"). These fluids are typically prepared by mixing appropriate amounts of VES suitable for achieving the desired viscosity. The viscosity of VES fluids can be attributed to the three-dimensional structure formed by the components of said fluids. When the concentration of surfactants in a viscoelastic fluid greatly exceeds the critical concentration, and in most cases in the presence of an electrolyte, the surfactant molecules aggregate into particles such as micelles, which can interact to form a network with viscous and elastic properties.

[0072] Typically, particularly suitable zwitterionic surfactants have the formula:

RCONH-(CH ₂ ) _a (CH ₂ CH ₂ O) _m (CH ₂ ) _b -N ⁺ (CH ₃ ) ₂ -(CH ₂ ) _a' (CH ₂ CH ₂ O) _m' (CH ₂ ) _b' COO

wherein R is an alkyl group containing from about 11 to about 23 carbon atoms, which may be branched or straight and may be saturated or unsaturated; each of a, b, a' and b' is from 0 to 10, and each of m and m' is from 0 to 13; each of a and b is 1 or 2 if m is not 0, and (a+b) is from 2 to 10 if m is 0; each of a' and b' is 1 or 2 if m' is not 0, and (a' + b') is from 1 to 5 if m is 0; (m+m') is from 0 to 14; and CH ₂ CH ₂ O may also be OCH ₂ CH ₂ . In some embodiments of the invention, zwitterionic surfactants from the betaine family are used.

[0073] Examples of suitable cationic VES include cationic surfactants having the structure:

R ₁ N ⁺ (R ₂ )(R ₃ )(R ₄ ) X ^-

wherein R ₁ has from about 14 to about 26 carbon atoms and may be branched or unbranched, aromatic, saturated or unsaturated and may contain a carbonyl, amide, retroamide, imide, urea or amine; each of R ₂ , R ₃ and R ₄ independently represents hydrogen or an aliphatic group from C ₁ to about C ₆ , which may be the same or different, branched or straight chain, saturated or unsaturated, wherein one or more of them may be substituted with a group that makes the groups R ₂ , R ₃ and R ₄ more hydrophilic; wherein the groups R ₂ , R ₃ and R ₄ may be included in a heterocyclic 5- or 6-membered ring structure that contains a nitrogen atom; the groups R ₂ , R ₃ and R ₄ may be the same or different; R ₁ , R ₂ , R ₃ and/or R ₄ may contain one or more ethylene oxide and/or propylene oxide units; and X ^is an anion. Mixtures of such compounds are also suitable. As a further example, R ₁ contains from about 18 to about 22 carbon atoms and may contain a carbonyl, amide or amine, and R ₂ , R ₃ and R ₄ are the same and contain from 1 to about 3 carbon atoms.

[0074] Amphoteric VES are also suitable. Exemplary amphoteric VES systems may include amine oxides, amidoamine oxides, and the like. Mixtures of zwitterionic surfactants and amphoteric surfactants are suitable. An example is a mixture of about 13% isopropanol, about 5% 1-butanol, about 15% ethylene glycol monobutyl ether, about 4% sodium chloride, about 30% water, about 30% cocoamidopropyl betaine, and about 2% cocoamidopropylamine oxide.

[0075] The VES system may also be based on any suitable anionic surfactant. In some embodiments of the present invention, the anionic surfactant is an alkyl sarcosinate. The alkyl sarcosinate may have substantially any number of carbon atoms. Alkyl sarcosinates may have from about 12 to about 24 carbon atoms. The alkyl sarcosinate may have from about 14 to about 18 carbon atoms. Specific examples of the number of carbon atoms include 12, 14, 16, 18, 20, 22, and 24 carbon atoms. The anionic surfactant is represented by the chemical formula:

R ₁ CON(R ₂ )CH ₂ X

wherein R ₁ is a hydrophobic chain containing from about 12 to about 24 carbon atoms, R ₂ is hydrogen, methyl, ethyl, propyl or butyl, and X is carboxyl or sulfonyl. The hydrophobic chain may be an alkyl group, an alkenyl group, an alkylarylalkyl group or an alkoxyalkyl group. Specific examples of the hydrophobic chain include a tetradecyl group, a hexadecyl group, an octadecentyl group, an octadecyl group and a docosene group.

[0076] In some embodiments, the carrier fluid may optionally further comprise additional additives, including, but not limited to, acids, fluid loss additives, gas, corrosion inhibitors, scale inhibitors, catalysts, clay stabilizing agents, biocides, friction reducers, combinations thereof, and the like. For example, in some embodiments of the present invention, it may be desirable to foam the composition using a gas such as air, nitrogen, or carbon dioxide.

[0077] The composition can be used to perform various subterranean treatment operations, including, but not limited to, drilling operations, fracturing treatments, diverting treatments, zonal isolation treatments, and completion operations (e.g., gravel packing). In some embodiments, the composition can be used to treat a portion of a subterranean formation. In some embodiments, the composition can be introduced into a wellbore that penetrates the subterranean formation as a treatment fluid. For example, the treatment fluid can be allowed to contact the subterranean formation for a period of time. In some embodiments, the treatment fluid can be allowed to react with hydrocarbons, formation fluids, and/or subsequently injected treatment fluids. After a selected period of time, the treatment fluid can be withdrawn through the wellbore.

[0078] The methods for delivering the composition to the near-wellbore region and into the wellbore are the same as for existing particulate diverting materials. Typically, such particulate materials are introduced into the fluid being pumped and then expelled through perforations at a high pumping rate. The list of injection equipment may include various dry additive systems, flow mixers, etc. In one embodiment, the particle mixtures may be mixed in batches and then injected into the fluid for treatment as a slurry. Simple flow injection devices, the schematic of which is shown in FIG. 5, may also be used. In one embodiment, the composition may be delivered into the wellbore in a conventional bailer or in a tool comprising a bailer and a perforator. Another method of delivering said composition may be envisaged, for example, by means of a wireline tool, a drill string, a wireline, coiled tubing (CT) or microtubing, by means of a downhole tool or any other device introduced into the well and capable of delivering the composition to a specific location. Microtubing or a drilling rig with coiled tubing of small diameter (MCTR - English: Microhole Coiled Tubing Drilling Rig) is a tool capable of performing a full range of operations in the vertical depth range from 0 to 5,000 feet, including drilling and casing of surface, intermediate, production and liner holes.

[0079] Since the volume of diversion mixture required for the treatment is relatively small, there is a risk that the particles of the mixture will separate while being pumped through the wellbore. This may result in poor diversion treatment due to the formation of plugs with higher permeability than expected. To avoid this situation, long phase plugs with a low concentration of diversion mixtures may be introduced into the treatment fluid to minimize the risk of particles separating from the main body of the injected mixture. Alternatively, to avoid this situation, the diversion mixtures may be injected as long phase plugs with low concentrations, making the volume of the diversion phase comparable to the wellbore volume. For example, for wells with a wellbore volume of 32 ^m3 (200 barrels), the volumes of diversion phase that minimize the risk of particle separation may be in the range of 3.2-16 ^m3 (20-100 barrels). For 5-25 kg of deflecting material this corresponds to a concentration range of 0.3-8 kg/ ^m3 .

[0080] The creation of plugs from the proposed diverting mixtures occurs due to the accumulation of particles in the void space behind the casing. Examples of such voids can be perforation channels, cracks from hydraulic fracturing or wormholes. The creation of a plug consists of two stages. In the first stage, some of the largest particles of the diverting mixture get stuck in the void, forming a bridge. In the next stage, other particles accumulate near the formed bridge, which leads to the formation of a plug.

[0081] After processing, the created plugs are removed. There are several methods that can be used to remove the created plugs. If the said composition contains decomposable materials, self-decomposition will occur. If the said composition contains a material that reacts with chemical agents, they are removed by interaction with other agents. If the said composition contains a fusible material, melting can lead to a decrease in the mechanical stability of the plug. If the said composition contains water-soluble or hydrocarbon-soluble materials, the removal of the plug can be achieved by physical dissolution of at least one of the components of the diverting mixture in the surrounding fluid. The solubility of the mentioned components can be significantly dependent on temperature. In this situation, the recovery of the temperature after processing in the sealed area can initiate the removal of the sealant. Disintegration of at least one component of the composition can occur. The removal of the plug can also be achieved by disintegration of the sealant into smaller particles, which will then be washed away. The list of possible materials that may have the property of decomposition includes plastics such as PLA, polyamides and composite materials containing decomposable plastics and non-decomposable small solid particles. It is worth mentioning that some decomposable material undergoes a decomposition stage during the decomposition process. Purely as an example, PLA may turn into brittle materials before it completely decomposes.

[0082] The vinyl alcohol copolymers used in the present invention, such as butenediol-vinyl alcohol copolymers, can extend the temperature range of deflection operations and possibly improve operational efficiency compared to the use of exclusively polylactide-based materials, which can take months to decompose at temperatures below 49 °C (120 °F). In addition to the relatively high dissolution rate of the vinyl alcohol copolymers of the present invention, such as butenediol-vinyl alcohol copolymers, the relative simplicity of the design of the operations can also improve efficiency during the operations. The vinyl alcohol copolymers used in the present invention, such as butenediol-vinyl alcohol copolymers, can also simplify the operations since only one type of deflection material can be pumped during the operation.

[0083] To facilitate a better understanding, the following examples of embodiments are provided. In no case should the following examples be considered to limit or define the scope of the invention as a whole.

Examples

[0084] Experiments were conducted to demonstrate the processing methods discussed in this document.

Example 1

[0085] This example is a study of the dissolution of a butenediol-vinyl alcohol copolymer in distilled water (DI). 1 g of the test material (e.g., vinyl alcohol copolymer) was added to 100 ml of distilled water and placed in a heat source (e.g., an oven) at a temperature of about 100 °C. After a certain period of time, the test material was filtered, dried, and weighed. The mass of the test material was recorded to plot the dissolution rate characteristic, as shown in FIG. 6.

[0086] The soluble materials of the present invention, such as vinyl alcohol copolymer-based materials, including butenediol-vinyl alcohol copolymer, can provide a solution for ultra-low temperature deviation in hydraulic fracturing. The relatively high dissolution rate of such vinyl alcohol copolymer-based materials can improve the operating efficiency during operations, and the dissolution rate can be improved by adding an acid, such as HCl.

Example 2

[0087] In the present study, thermoplastic starch (TPS) and plasticized butenediol vinyl alcohol (P-BVOH) were prepared by melt blending techniques, and the plasticizing effect of glycerol on starch and BVOH with different compositions was observed under optimized processing conditions. Based on the preliminary study, TPS was blended with different amounts of P-BVOH, such as in weight ratios including 100:0, 90:10, 80:20, 70:30, 60:40, and 50:50.

[0088] The above invention and description are illustrative and explanatory, and it will be readily apparent to those skilled in the art that various changes in size, shape, materials, and details of the illustrated structure or combinations of elements described herein may be made without departing from the spirit of the present invention.

Claims (17)

1. A method for zonal isolation of an underground formation to intensify hydrocarbon production, including: a. introducing into the wellbore a fluid for treating a subsurface formation, containing a carrier fluid and a soluble material capable of forming a gel upon hydration, wherein the soluble material comprises particles of a copolymer of butenediol and vinyl alcohol capable of forming a plug in a subterranean formation, wherein the average particle size of the copolymer of butenediol and vinyl alcohol is from 2 mm to 2 cm, where the particle size is the diameter of the smallest sphere that can contain the particle; and b. creating a plug in an underground formation using a formation treatment fluid. 2. The method according to claim 1, characterized in that the particles of the butenediol and vinyl alcohol copolymer have a cylindrical or rod-shaped form. 3. The method according to claim 1, characterized in that the liquid for treating the underground formation contains thermoplastic starch (TPS). 4. The method according to claim 1, characterized in that the liquid for treating the underground formation additionally contains fibers. 5. The method according to paragraph 1, characterized in that the liquid for treating the underground formation additionally contains a viscosity increaser or friction reducer. 6. The method according to claim 1, characterized in that the carrier fluid is a liquid selected from the group consisting of a water-based reagent, a spacer fluid, a co-solvent, a drilling fluid, a formation dissolution fluid, a fracturing fluid, a scale dissolution fluid, a paraffin dissolution fluid, an asphaltene dissolution fluid, a diverting fluid, a water influx control agent, a chelating agent, a viscoelastic diverting acid, a self-diverting acid system, an acid, and a mixture thereof. 7. The method according to claim 1, further comprising removing the plug. 8. A fluid for treating a subsurface formation, comprising a carrier fluid and a soluble material capable of forming a gel upon hydration, wherein the soluble material contains particles of a copolymer of butenediol and vinyl alcohol capable of forming a plug in an underground formation, the average particle size of the copolymer of butenediol and vinyl alcohol being from 2 mm to 2 cm, where the particle size is the diameter of the smallest sphere that can contain the particle. 9. The liquid according to item 8, characterized in that the particles of the butenediol and vinyl alcohol copolymer have a cylindrical or rod-shaped form. 10. The liquid according to item 8, characterized in that it additionally contains thermoplastic starch (TPS). 11. The liquid according to item 8, additionally containing fibers. 12. The liquid according to item 8, characterized in that it additionally contains a viscosity increaser or friction reducer. 13. The fluid of claim 8, wherein the carrier fluid is a fluid selected from the group consisting of a water-based reagent, a spacer fluid, a co-solvent, a drilling fluid, a formation dissolution fluid, a fracturing fluid, a scale dissolution fluid, a paraffin dissolution fluid, an asphaltene dissolution fluid, a diverting fluid, a water influx control agent, a chelating agent, a viscoelastic diverting acid, a self-diverting acid system, an acid, and a mixture thereof.