DIVERSION PILL AND METHODS OF USING THE SAME

Abstract

The invention provides a method made of steps of method injecting into a wellbore, a composition comprising an aqueous solution, a viscosifying agent, a degradable material, and sized salt particulates; and allowing viscosity of the composition to increase and form a plug at dynamic reservoir conditions.

Description

FIELD OF THE INVENTION

The invention relates generally to the exploitation of hydrocarbon-containing formations or injection wells. More specifically, the invention relates to diverting agent and methods of diverting in subterranean formations.

BACKGROUND

The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.

Hydrocarbons (oil, condensate, and gas) are typically produced from wells that are drilled into the formations containing them. For a variety of reasons, such as inherently low permeability of the reservoirs or damage to the formation caused by drilling and completion of the well, the flow of hydrocarbons into the well is undesirably low. In this case, the well is “stimulated,” for example using hydraulic fracturing, chemical (usually acid) stimulation, or a combination of the two (called acid fracturing or fracture acidizing).

Hydraulic fracturing involves injecting fluids into a formation at high pressures and rates such that the reservoir rock fails and forms a fracture (or fracture network). Proppants are typically injected in fracturing fluids after the pad to hold the fracture(s) open after the pressures are released. In chemical (acid) stimulation treatments, flow capacity is improved by dissolving materials in the formation.

In hydraulic and acid fracturing, a first, viscous fluid called a “pad” is typically injected into the formation to initiate and propagate the fracture. This is followed by a second fluid that contains a proppant to keep the fracture open after the pumping pressure is released. Granular proppant materials may include sand, ceramic beads, or other materials. In “acid” fracturing, the second fluid contains an acid or other chemical such as a chelating agent that can dissolve part of the rock, causing irregular etching of the fracture face and removal of some of the mineral matter, resulting in the fracture not completely closing when the pumping is stopped. Occasionally, hydraulic fracturing is done without a highly viscosified fluid (i.e., slick water) to minimize the damage caused by polymers or the cost of other viscosifiers.

When multiple hydrocarbon-bearing zones are stimulated by hydraulic fracturing or chemical stimulation, it is desirable to treat the multiple zones in multiple stages. In multiple zone fracturing, a first pay zone is fractured. Then, the fracturing fluid is diverted to the next stage to fracture the next pay zone. The process is repeated until all pay zones are fractured. Alternatively, several pay zones may be fractured at one time, if they are closely located with similar properties. Diversion may be achieved with various techniques including formation of a temporary plug using polymer gels or solid fluid loss materials.

Polymer gels have been widely used for conformance control of naturally fissured/fractured reservoirs. For an overview of existing polymer compositions, reference is made to the U.S. Pat. Nos. 5,486,312 and 5,203,834 which also list a number of patents and other sources related to gel-forming polymers.

Solid fluid loss materials can be used to plug up and isolate the zone that has been previously stimulated or intended to be omitted from treatment and divert treating fluids to the next zones. Once stimulated; however, these plugged zones will need to be accessible for production after the treatment is completed and hence will require dissolution and removal of the plug.

The applicants found a method of using sized sodium chloride salt as fluid loss additive/diverter, which is readily removed by dissolving in water either from the excess water available from the stimulation fluids returned during flowback of the stimulation treatment or from produced water. The fluid used in placing this diversion pill is solids-free VES fluid gelled in heavy brine which carries the sodium chloride salt particulate and ensures cleanup after the treatment.

SUMMARY

In a first aspect, a method is disclosed. The method comprises injecting into a wellbore, a composition comprising an aqueous solution, a viscosifying agent, a degradable material, and sized salt particulates; and allowing viscosity of the composition to increase and form a plug at dynamic reservoir conditions. By dynamic reservoir conditions it is hereby meant with shear such as for instance of above about 1 s⁻¹, or above about 10 s⁻¹.

In a second aspect, a method of diverting a treatment fluid in a wellbore is disclosed. The method comprises injecting into the wellbore the treatment fluid to treat a first zone; injecting into the wellbore, a composition comprising an aqueous solution, a viscosifying agent, a degradable material, and sized salt particulates; allowing viscosity of the composition to increase and form a plug at dynamic reservoir conditions; and diverting the treatment fluid from first zone to a second zone with the plug.

In a third aspect, a method of fracturing a subterranean formation in a wellbore is disclosed. The method comprises injecting into the wellbore a fracturing fluid to create a fracture in the subterranean formation; injecting into the wellbore, a composition comprising an aqueous solution, a viscosifying agent, a degradable material, and sized salt particulates; allowing viscosity of the composition to increase and form a plug at dynamic reservoir conditions; and diverting the fracturing fluid with the plug to create a second fracture in the subterranean formation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a graph showing solubility versus temperature for sodium chloride and potassium chloride.

FIG. 2 is a graph comparing viscosity (at 100/s) versus temperature for samples 1 and 2.

FIG. 3 is a graph showing shear sweep (increasing shear rate) at room temperature of sample from a relaxed state (first run) followed by a shear activated state (second run) using fluid Sample 3.

FIG. 4 is a graph showing viscosity measurement at 100/s at room temperature for a relaxed sample 3.

FIG. 5 is a graph showing viscosity relaxing progress at various shear rates at room temperature for sample 3 after sheared at 500/s for 2 minutes.

DETAILED DESCRIPTION

At the outset, it should be noted that in the development of any actual embodiments, numerous implementation-specific decisions must be made to achieve the developer's specific goals, such as compliance with system and business related constraints, which can vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure.

The description and examples are presented solely for the purpose of illustrating embodiments of the invention and should not be construed as a limitation to the scope and applicability of the invention. In the summary of the invention and this detailed description, each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. Also, in the summary of the invention and this detailed description, it should be understood that a concentration range listed or described as being useful, suitable, or the like, is intended that any and every concentration within the range, including the end points, is to be considered as having been stated. For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10. Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to only a few specific, it is to be understood that inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that inventors possession of the entire range and all points within the range disclosed and enabled the entire range and all points within the range.

The following definitions are provided in order to aid those skilled in the art in understanding the detailed description of the invention.

The term “fracturing” refers to the process and methods of breaking down a geological formation and creating a fracture, i.e. the rock formation around a well bore, by pumping fluid at very high pressures, in order to increase production rates from a hydrocarbon reservoir. The fracturing methods otherwise use conventional techniques known in the art.

The term “surfactant” refers to a soluble or partially soluble compound that reduces the surface tension of liquids, or reduces inter-facial tension between two liquids, or a liquid and a solid by congregating and orienting itself at these interfaces.

The term “viscoelastic” refers to those viscous fluids having elastic properties, i.e., the liquid at least partially returns to its original form when an applied stress is released.

The phrase “viscoelastic surfactant” or “VES” refers to that class of compounds which can form micelles (spherulitic, anisometric, lamellar, or liquid crystal) in the presence of counter ions in aqueous solutions, thereby imparting viscosity to the fluid. Anisometric micelles can be used, as their behavior in solution most closely resembles that of a polymer.

According to a first embodiment, the composition is made from: an aqueous solution, a viscosifying agent, a degradable material, and sized salt particulates.

The aqueous solution may be fresh water or an aqueous solution comprising mono, di or trivalent metal salts, ammonium or mixtures of these. The salt can be present naturally if brine is used, or can be added to the aqueous solution. For example, it is possible to add to water; any salt, such as an alkali metal or alkali earth metal salt (NaCO₃, NaCl, KCl, etc.). In one embodiment, the salt is generally present in weight percent concentration between about 0.1% to about 5%, from about 1% to about 3% by weight. One useful concentration is about 2% by weight. In a second embodiment, the salt is at saturation conditions of the respective brine. Effectively, if the aqueous solution is below saturation then the sized salt particulates may begin dissolving. For some applications, in particular where freezing might be expected, the aqueous solution may further comprises an alcohol such as methanol, ethanol, propanol or a polyalcohol such a glycol or polyglycols or mixture thereof.

The viscosifying agent may be any crosslinked polymers. The polymer viscosifier can be a metal-crosslinked polymer. Suitable polymers for making the metal-crosslinked polymer viscosifiers include, for example, polysaccharides such as substituted galactomannans, such as guar gums, high-molecular weight polysaccharides composed 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 make them better suited for use in high-temperature wells.

Other suitable classes of polymers effective as viscosifying agent include polyvinyl polymers, polymethacrylamides, cellulose ethers, lignosulfonates, and ammonium, alkali metal, and alkaline earth salts thereof. More specific examples of other typical water soluble polymers are acrylic acid-acrylamide copolymers, acrylic acid-methacrylamide copolymers, polyacrylamides, partially hydrolyzed polyacrylamides, partially hydrolyzed polymethacrylamides, polyvinyl alcohol, polyalkyleneoxides, other galactomannans, heteropolysaccharides obtained by the fermentation of starch-derived sugar and ammonium and alkali metal salts thereof.

Cellulose derivatives are used to a smaller extent, such as hydroxyethylcellulose (HEC) or hydroxypropylcellulose (HPC), carboxymethylhydroxyethylcellulose (CMHEC) and carboxymethycellulose (CMC), with or without crosslinkers. Xanthan, diutan, and scleroglucan, three biopolymers, have been shown to have excellent particulate-suspension ability even though they are more expensive than guar derivatives and therefore have been used less frequently, unless they can be used at lower concentrations.

In other embodiments, the viscosifying agent is made from a crosslinkable, hydratable polymer and a delayed crosslinking agent, wherein the crosslinking agent comprises a complex comprising a metal and a first ligand selected from the group consisting of amino acids, phosphono acids, and salts or derivatives thereof. Also the crosslinked polymer can be made from a polymer comprising pendant ionic moieties, a surfactant comprising oppositely charged moieties, a clay stabilizer, a borate source, and a metal crosslinker. Said embodiments are described in U.S. Patent Publications US2008-0280790 and US2008-0280788 respectively, each of which are incorporated herein by reference.

In other embodiments, the viscosifying agent may be a linear (not cross-linked) polymer system.

The viscosifying agent may be a viscoelastic surfactant. The viscoelastic surfactant is present in a low weight percent concentration. Some suitable concentrations of viscoelastic surfactant are about 0.001% to about 1.5% by weight, from about 0.01% to about 0.75% by weight, or even about 0.25%, about 0.5% or about 0.75% by weight. However, it should be noted the effect of increasing VES concentration is not limited to 1.5% by weight. The increase in viscosity due to the addition of VES appears to increase in an approximately linear manner with increasing concentration of VES up to 1.5%, the highest concentration tested. While economically it makes less sense to include higher VES concentrations it is reasonable to presume that the same linear increase in viscosity will occur with higher concentrations of VES.

The VES may be selected from the group consisting of cationic, anionic, zwitterionic, amphoteric, nonionic and combinations thereof. Some non-limiting examples are those cited in U.S. Pat. Nos. 6,435,277 (Qu et al.) and 6,703,352 (Dahayanake et al.), each of which are incorporated herein by reference. The viscoelastic surfactants, when used alone or in combination, are capable of forming micelles that form a structure in an aqueous environment that contribute to the increased viscosity of the fluid (also referred to as “viscosifying micelles”). These fluids are normally prepared by mixing in appropriate amounts of VES suitable to achieve the desired viscosity. The viscosity of VES fluids may be attributed to the three dimensional structure formed by the components in the fluids. When the concentration of surfactants in a viscoelastic fluid significantly exceeds a critical concentration, and in most cases in the presence of an electrolyte, surfactant molecules aggregate into species such as micelles, which can interact to form a network exhibiting viscous and elastic behavior.

In general, particularly suitable zwitterionic surfactants have the formula:

RCONH—(CH₂)_a(CH₂CH₂O)_m(CH₂)_b—N⁺(CH₃)₂—(CH₂)_a′(CH₂CH₂O)_m′(CH₂)_b′COO⁻

in which R is an alkyl group that contains from about 11 to about 23 carbon atoms which may be branched or straight chained and which may be saturated or unsaturated; a, b, a′, and b′ are each from 0 to 10 and m and m′ are each from 0 to 13; a and b are each 1 or 2 if m is not 0 and (a+b) is from 2 to 10 if m is 0; a′ and b′ are each 1 or 2 when m′ is not 0 and (a′+b′) is from 1 to 5 if m is 0; (m+m′) is from 0 to 14; and CH₂CH₂O may also be OCH₂CH₂.

In some embodiments, a zwitterionic surfactants of the family of betaine is used. Two suitable examples of betaines are BET-O and BET-E. The surfactant in BET-O-30 is shown below; one chemical name is oleylamidopropyl betaine. It is designated BET-O-30 because as obtained from the supplier (Rhodia, Inc. Cranbury, N.J., U.S. A.) it is called Mirataine BET-O-30 because it contains an oleyl acid amide group (including a C₁₇H₃₃ alkene tail group) and contains about 30% active surfactant; the remainder is substantially water, sodium chloride, and propylene glycol. An analogous material, BET-E-40, is also available from Rhodia and contains an erucic acid amide group (including a C₂₁H₄₁ alkene tail group) and is approximately 40% active ingredient, with the remainder being substantially water, sodium chloride, and isopropanol. VES systems, in particular BET-E-40, optionally contain about 1% of a condensation product of a naphthalene sulfonic acid, for example sodium polynaphthalene sulfonate, as a rheology modifier, as described in U.S. Patent Application Publication No. 2003-0134751. The surfactant in BET-E-40 is also shown below; one chemical name is erucylamidopropyl betaine. BET surfactants, and other VES's that are suitable for the embodiments are described in U.S. Pat. No. 6,258,859. According to that patent, BET surfactants make viscoelastic gels when in the presence of certain organic acids, organic acid salts, or inorganic salts; in that patent, the inorganic salts were present at a weight concentration up to about 30%. Co-surfactants may be useful in extending the brine tolerance, and to increase the gel strength and to reduce the shear sensitivity of the VES-fluid, in particular for BET-O-type surfactants. An example given in U.S. Pat. No. 6,258,859 is sodium dodecylbenzene sulfonate (SDBS), also shown below. Other suitable co-surfactants include, for example those having the SDBS-like structure in which x=5-15; other co-surfactants are those in which x=7-15. Still other suitable co-surfactants for BET-O-30 are certain chelating agents such as trisodium hydroxyethylethylenediamine triacetate. The composition may be used with viscoelastic surfactant fluid systems that contain such additives as co-surfactants, organic acids, organic acid salts, and/or inorganic salts.

• • Surfactant in BET-O-30 (when n=3 and p=1)

• • Surfactant in BET-E-40 (when n=3 and p=1)

• • SDBS (when x=11 and the counter-ion is Na⁺)

Some embodiments use betaines; for example BET-E-40. Although experiments have not been performed, it is believed that mixtures of betaines, especially BET-E-40, with other surfactants are also suitable.

Other betaines that are suitable include those in which the alkene side chain (tail group) contains 17-23 carbon atoms (not counting the carbonyl carbon atom) which may be branched or straight chained and which may be saturated or unsaturated, n=2-10, and p=1-5, and mixtures of these compounds. Some betaines are those in which the alkene side chain contains 17-21 carbon atoms (not counting the carbonyl carbon atom) which may be branched or straight chained and which may be saturated or unsaturated, n=3-5, and p=1-3, and mixtures of these compounds. These surfactants are used at a concentration of about 0.5 to about 10%, or from about 1 to about 5%, or even from about 1.5 to about 4.5%.

Exemplary cationic viscoelastic surfactants include the amine salts and quaternary amine salts disclosed in U.S. Pat. Nos. 5,979,557, and 6,435,277 which are hereby incorporated by reference. Examples of suitable cationic viscoelastic surfactants include cationic surfactants having the structure:

R₁N⁺(R₂)(R₃)(R₄)X⁻

in which R₁ has from about 14 to about 26 carbon atoms and may be branched or straight chained, aromatic, saturated or unsaturated, and may contain a carbonyl, an amide, a retroamide, an imide, a urea, or an amine; R₂, R₃, and R₄ are each independently hydrogen or a C₁ to about C₆ aliphatic group which may be the same or different, branched or straight chained, saturated or unsaturated and one or more than one of which may be substituted with a group that renders the R₂, R₃, and R₄ group more hydrophilic; the R₂, R₃ and R₄ groups may be incorporated into a heterocyclic 5- or 6-member ring structure which includes the nitrogen atom; the R₂, R₃ and R₄ groups may be the same or different; R₁, R₂, R₃ and/or R₄ 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, R₁ is from about 18 to about 22 carbon atoms and may contain a carbonyl, an amide, or an amine, and R₂, R₃, and R₄ are the same as one another and contain from 1 to about 3 carbon atoms.

Cationic surfactants having the structure R₁N⁺(R₂)(R₃)(R₄)X⁻ may optionally contain amines having the structure RiN(R₂)(R₃). It is well known that commercially available cationic quaternary amine surfactants often contain the corresponding amines (in which R₁, R₂, and R₃ in the cationic surfactant and in the amine have the same structure). As received commercially available VES surfactant concentrate formulations, for example cationic VES surfactant formulations, may also optionally contain one or more members of the group consisting of alcohols, glycols, organic salts, chelating agents, solvents, mutual solvents, organic acids, organic acid salts, inorganic salts, oligomers, polymers, co-polymers, and mixtures of these members. They may also contain performance enhancers, such as viscosity enhancers, for example polysulfonates, for example polysulfonic acids, as described in U.S. Pat. No. 7,084,095 which is hereby incorporated by reference.

Another suitable cationic VES is erucyl bis(2-hydroxyethyl)methyl ammonium chloride, also known as (Z)-13 docosenyl-N—N-bis(2-hydroxyethyl)methyl ammonium chloride. It is commonly obtained from manufacturers as a mixture containing about 60 weight percent surfactant in a mixture of isopropanol, ethylene glycol, and water. Other suitable amine salts and quaternary amine salts include (either alone or in combination in accordance with the invention), erucyl trimethyl ammonium chloride; N-methyl-N,N-bis(2-hydroxyethyl) rapeseed ammonium chloride; oleyl methyl bis(hydroxyethyl) ammonium chloride; erucylamidopropyltrimethylamine chloride, octadecyl methyl bis(hydroxyethyl)ammonium bromide; octadecyl tris(hydroxyethyl)ammonium bromide; octadecyl dimethyl hydroxyethyl ammonium bromide; cetyl dimethyl hydroxyethyl ammonium bromide; cetyl methyl bis(hydroxyethyl)ammonium salicylate; cetyl methyl bis(hydroxyethyl)ammonium 3,4,-dichlorobenzoate; cetyl tris(hydroxyethyl)ammonium iodide; cosyl dimethyl hydroxyethyl ammonium bromide; cosyl methyl bis(hydroxyethyl)ammonium chloride; cosyl tris(hydroxyethyl)ammonium bromide; dicosyl dimethyl hydroxyethyl ammonium bromide; dicosyl methyl bis(hydroxyethyl)ammonium chloride; dicosyl tris(hydroxyethyl)ammonium bromide; hexadecyl ethyl bis(hydroxyethyl)ammonium chloride; hexadecyl isopropyl bis(hydroxyethyl)ammonium iodide; and cetylamino, N-octadecyl pyridinium chloride.

Amphoteric viscoelastic surfactants are also suitable. Exemplary amphoteric viscoelastic surfactant systems include those described in U.S. Pat. No. 6,703,352, for example amine oxides. Other exemplary viscoelastic surfactant systems include those described in U.S. Pat. Nos. 6,239,183; 6,506,710; 7,060,661; 7,303,018; and 7,510,009 for example amidoamine oxides. These references are hereby incorporated in their entirety. 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.

The viscoelastic surfactant system may also be based upon any suitable anionic surfactant. In some embodiments, the anionic surfactant is an alkyl sarcosinate. The alkyl sarcosinate can generally have any number of carbon atoms. Alkyl sarcosinates can have about 12 to about 24 carbon atoms. The alkyl sarcosinate can have 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:

R₁CON(R₂)CH₂X

wherein R₁ is a hydrophobic chain having about 12 to about 24 carbon atoms, R₂ is hydrogen, methyl, ethyl, propyl, or butyl, and X is carboxyl or sulfonyl. The hydrophobic chain can 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 docosenoic group.

To provide the ionic strength for the desired micelle formation, in some cases, the composition may comprise water-soluble salts. Adding salt may help promote micelle formation for the viscosification of the fluid in some instances. Suitable water-soluble salts may comprise lithium, ammonium, sodium, potassium, cesium, magnesium, calcium, or zinc cations, and chloride, bromide, iodide, formate, nitrate, acetate, cyanate, or thiocyanate anions. Examples of suitable water-soluble salts that comprise the above-listed anions and cations include, but are not limited to, ammonium chloride, lithium bromide, lithium chloride, lithium formate, lithium nitrate, calcium bromide, calcium chloride, calcium nitrate, calcium formate, sodium bromide, sodium chloride, sodium formate, sodium nitrate, potassium chloride, potassium bromide, potassium nitrate, potassium formate, cesium nitrate, cesium formate, cesium chloride, cesium bromide, magnesium chloride, magnesium bromide, zinc chloride, and zinc bromide.

The degradable material may be degradable fibers, granular materials, particulates, flakes or particles made of degradable polymers. The differing molecular structures of the degradable materials that are suitable give a wide range of possibilities regarding regulating the degradation rate of the degradable material. In choosing the appropriate degradable material, one should consider the degradation products that will result. For instance, some may form an acid upon degradation, and the presence of the acid may be undesirable; others may form degradation products that would be insoluble, and these may be undesirable. Moreover, these degradation products should not adversely affect other operations or components.

The degradability of a polymer depends at least in part on its backbone structure. One of the more common structural characteristics is the presence of hydrolyzable and/or oxidizable linkages in the backbone. The rates of degradation of, for example, polyesters, are dependent on the type of repeat unit, composition, sequence, length, molecular geometry, molecular weight, morphology (e.g., crystallinity, size of spherulites, and orientation), hydrophilicity, surface area, and additives. Also, the environment to which the polymer is subjected may affect how the polymer degrades, e.g., temperature, presence of moisture, oxygen, microorganisms, enzymes, pH, and the like. One of ordinary skill in the art, with the benefit of this disclosure, will be able to determine what the optimum polymer would be for a given application considering the characteristics of the polymer utilized and the environment to which it will be subjected.

Suitable examples of polymers that may be used include, but are not limited to, homopolymers, random aliphatic polyester copolymers, block aliphatic polyester copolymers, star aliphatic polyester copolymers, or hyperbranched aliphatic polyester copolymers. Such suitable polymers may be prepared by polycondensation reactions, ring-opening polymerizations, free radical polymerizations, anionic polymerizations, carbocationic polymerizations, coordinative ring-opening polymerization for, such as, lactones, and any other suitable process. Specific examples of suitable polymers include polysaccharides such as dextran or cellulose; chitins; chitosans; proteins; aliphatic polyesters; poly(lactides); poly(glycolides); poly(8-caprolactones); poly(hydroxy ester ethers); poly(hydroxybutyrates); polyanhydrides; polycarbonates; poly(orthoesters); poly(acetals); poly(acrylates); poly(alkylacrylates); poly(amino acids); poly(ethylene oxide); poly ether esters; polyester amides; polyamides; polyphosphazenes; and copolymers or blends thereof. Other degradable polymers that are subject to hydrolytic degradation also may be suitable. One guideline for choosing which composite particles to use in a particular application is what degradation products will result. Another guideline is the conditions surrounding a particular application.

Of these suitable polymers, aliphatic polyesters are preferred. Of the suitable aliphatic polyesters, polyesters of α or β hydroxy acids are preferred. Poly(lactide) is most preferred. Poly(lactide) is synthesized either from lactic acid by a condensation reaction or more commonly by ring-opening polymerization of cyclic lactide monomer. The lactide monomer exists generally in three different forms: two stereoisomers L- and D-lactide; and D,L-lactide (meso-lactide). The chirality of the lactide units provides a means to adjust, inter alia, degradation rates, as well as the physical and mechanical properties after the lactide is polymerized. Poly(L-lactide), for instance, is a semicrystalline polymer with a relatively slow hydrolysis rate. This could be desirable in applications where slow degradation of the degradable material is desired. Poly(D,L-lactide) is an amorphous polymer with a much faster hydrolysis rate. The stereoisomers of lactic acid may be used individually or combined for use in the compositions and methods of the present embodiments. Additionally, they may be copolymerized with, for example, glycolide or other monomers like ε-caprolactone, 1,5-dioxepan-2-one, trimethylene carbonate, or other suitable monomers to obtain polymers with different properties or degradation times. Additionally, the lactic acid stereoisomers can be modified by blending high and low molecular weight polylactide or by blending polylactide with other aliphatic polyesters. For example, the degradation rate of polylactic acid may be affected by blending, for example, high and low molecular weight polylactides; mixtures of polylactide and lactide monomer; or by blending polylactide with other aliphatic polyesters.

The physical properties of degradable polymers may depend on several factors such as the composition of the repeat units, flexibility of the chain, presence of polar groups, molecular mass, degree of branching, crystallinity, orientation, etc. For example, short chain branches reduce the degree of crystallinity of polymers while long chain branches lower the melt viscosity and impart, inter alia, extensional viscosity with tension-stiffening behavior. The properties of the material utilized can be further tailored by blending, and copolymerizing it with another polymer, or by a change in the macromolecular architecture (e.g., hyper-branched polymers, star-shaped, or dendrimers, etc.). The properties of any such suitable degradable polymers (such as hydrophilicity, rate of biodegration, etc.) can be tailored by introducing functional groups along the polymer chains. One of ordinary skill in the art, with the benefit of this disclosure, will be able to determine the appropriate functional groups to introduce to the polymer chains to achieve the desired effect.

In an embodiment, the degradable material degrades after temporarily sealing during the treatment operation, and helps restore permeability and conductivity for reservoir fluid production. The delayed degradation of polyester generally includes hydrolysis of the ester moieties at downhole conditions of elevated temperature and an aqueous environment into hydrolysis such as carboxylic acid and hydroxyl moieties, for example. The hydrolysis in one embodiment can render the degradable material degradation products entirely soluble in the downhole and/or reservoir fluids. In an alternative or additional embodiment, the entire degradable material need not be entirely soluble following polyester degradation; it is sufficient only that enough hydrolysis occurs so as to allow the residue of the degraded or partially degraded degradable material to be lifted off of the sealed surface by a low backflow pressure from produced reservoir fluids.

In some embodiments, the degradable materials are in the form of beads, powder, spheres, ribbons, platelets, fibers, flakes, or any other shape with an aspect ratio equal to or greater than one. In some embodiments, the degradable materials include particles having an aspect ratio greater than 10, greater than 100, greater than 200, greater than 250 or the like, such as platelets or fibers or the like. The blended materials can take any form of composites, for example biodegradable material coatings or scaffolds with other materials dispersed therein. Further, the degradable particles can be nano-, micro-, or mesoporous structures that are fractal or non-fractal.

The sized salt particulates or graded salt particulates may comprise lithium, ammonium, sodium, potassium, cesium, magnesium, calcium, or zinc cations, and chloride, bromide, iodide, formate, nitrate, acetate, cyanate, or thiocyanate anions. Examples of suitable sized salt particulates that comprise the above-listed anions and cations include, but are not limited to, ammonium chloride, lithium bromide, lithium chloride, lithium formate, lithium nitrate, calcium bromide, calcium chloride, calcium nitrate, calcium formate, sodium bromide, sodium chloride, sodium formate, sodium nitrate, potassium chloride, potassium bromide, potassium nitrate, potassium formate, cesium nitrate, cesium formate, cesium chloride, cesium bromide, magnesium chloride, magnesium bromide, zinc chloride, and zinc bromide.

In one embodiment, the sized salt particulates are sized sodium chloride. Sodium chloride salt can easily be dissolved by water or unsaturated brines; using it as fluid loss/diverter solid makes it ideal for post treatment cleanup. When sodium chloride particles are used, the aqueous solution is preferably a brine near saturation condition or even at saturation condition. Effectively, the sodium chloride particles may begin dissolving in the aqueous solution and may not function as an effective diverter, if the brine is not near saturation condition. NaCl has a close to constant solubility in water with respect to temperature changes; therefore, is perfect to be used to formulate a diversion or fluid loss pill at different temperatures. Different brines can be selected to formulate this diversion pill with the solid NaCl salt.

NaCl is chosen as the solid salt fluid loss additive/diverter due to its relatively flat solubility curve with respect to the solution temperature. As shown in FIG. 1, NaCl solubility in both fresh water and 11.6 ppg CaCl₂ exhibits nominal change across a wide temperature range, while KCl on the other hand, solubility increases significantly with increases in temperature. This makes NaCl a preferred diverting particulate since it remains in a solid state in a saturated NaCl brine or CaCl₂ carrying medium while being pumped and placed.

According to a further embodiment, the composition may further comprise additives as surfactants, dispersants, breakers, anti-oxidants, corrosion inhibitors, delay agents, biocides, buffers, fluid loss additives, pH control agents, solid acids, solid acid precursors, organic scale inhibitors, inorganic scale inhibitors, demulsifying agents, paraffin inhibitors, corrosion inhibitors, gas hydrate inhibitors, asphaltene treating chemicals, foaming agents, fluid loss agents, water blocking agents, EOR enhancing agents, or the like. The additive may also be a biological agent.

The composition is compatible with other fluids or material as for example hydrocarbons such as mineral oil (only if non-VES fluids are used), proppants or additives normally found in well stimulation. Current embodiments can be used in various applications including temporary plugs formation, kill plugs, or multiple fracturing steps for to treating subterranean formations having a plurality of zones of differing permeabilities.

According to a first aspect, the method comprises injecting into a wellbore, the composition and allowing viscosity of the composition to increase and form a plug at dynamic reservoir conditions. By dynamic reservoir conditions it is hereby meant with shear such as for instance of above about 1 s⁻¹, or above about 10 s⁻¹. The composition is a shear thickening fluid, i.e. low viscosity at rest, but can be activated when enough shearing energy is applied. This behavior is useful in the diversion applications as it has low viscosity during pumping, but is shear activated when flowed through the high perm zone, natural fractures, or a previous fractured zone, where the flow rate there is high and hence shear rate is high. This activated fluid will have higher viscosity in blocking off or providing higher resistance to this zone or to perforations. Once the fluid is no longer sheared, it will gradually relax to low to no viscosity, facilitating the cleanup in flowback.

Application could be used for fracture stimulation treatments in new or refraced horizontal or vertical wells to achieve near-wellbore diversion by opening entirely new zones to the treatment or restimulation that effectively extends the former stimulation within an older pre-existing fractured zone. The combination of salt in a saturated or nonreactive brine along with fiber in a brine compatible VES fluid are used as the diverter pill that is placed to effect diversion. After the treatment the entire diverter pill is degradable and can be flowed back to surface.

To facilitate a better understanding of some embodiments, the following examples of embodiments are given. In no way should the following examples be read to limit, or define, the scope of the embodiments described herewith.

EXAMPLES

Series of experiments were conducted to demonstrate properties of compositions and methods as disclosed above.

Two kinds of fluid examples will be shown here. One is with CaCl₂ brine, and the other is using saturated NaCl brine. Shown in FIG. 2 are two viscosity (at 100 s⁻¹) versus temperature profiles for two different fluid samples. Both samples used 11.6 ppg CaCl₂ with no less than 20% solid NaCl added. Sample 1 has 0.67% of active BET-E surfactant and 0.11% copolymer of polyvinyl acetate/polyvinyl alcohol rheology modifier while sample 2 has 1.5% of active BET-E surfactant and 0.25% copolymer of polyvinyl acetate/polyvinyl alcohol rheology modifier. As can be seen from the figure, both fluid viscosities are maintained as temperatures are raised. In addition, as shown in table 1, the n′ of these two fluids are well below 1, indicating that the fluid is a viscoelastic fluid. The addition of the NaCl in this system did not impair the VES fluid performances.

TABLE 1
n′ of sample 1 and 2 at various temperatures
	Sample 1		Sample 2
	TEMP (degF.)	n′	TEMP (degF.)	n′
	77	0.375	76	0.406
	103	0.413	103	0.361
	122	0.482	123	0.26
	142	0.498	142	0.181
	166	0.461	167	0.196
	192	0.566	194	0.37
	216	0.432	219	0.177
	238	0.812	241	0.09
			261	0.176
			281	0.502

Another kind of fluid example is made with solid NaCl in a saturated NaCl brine. The sample 3 fluid contains 0.67% of active BET-E surfactant and 0.11% copolymer of polyvinyl acetate/polyvinyl alcohol rheology modifier.

Sample 3 was prepared in Waring blender then allowed to sit without disturbance in a relaxed state for a few minutes. The sample was then loaded to the Bohlin rheometer and sheared from low shear (0.1 s⁻¹) to high shear (500 s⁻¹) and then remained at high shear for 2 minutes. The same sample was then run for the same shear sweep again. As shown in FIG. 3, the second run after the fluid is shear activated gives much higher viscosity at low shear to about 10 s¹. In fact, it can be seen from the first run that the fluid follows a power law slope up to 10 s⁻¹ and then deviates from it indicating the fluid is shear thickening at this shear rate.

To further confirm this shear activation property, a relaxed sample 3 was sheared at 100 s⁻¹ shear rate and the viscosity profile was recorded (FIG. 4). The fluid viscosity for the first 2 minutes increased with time confirming that the fluid is being shear activated.

The activated fluid decay (relax) in viscosity can also be measured with the rheometer. Sample 3 was shear activated by applying 500 s⁻¹ shear for 2 minutes, then measured at 100, 10 and 1 s⁻¹ respectively for 20 minutes. The results are plotted in FIG. 5. For comparison, the viscosity decreases are normalized with the initial viscosity at that shear rate immediately after 500 s⁻¹ shear. At 100 s⁻¹, the shear energy is still high enough to keep the fluid at a shear activated state, so the viscosity trace basically remains flat throughout the measurement period. At 1 s⁻¹, the fluid is close to not being sheared; therefore, it relaxes rapidly in about 3 minutes. At 10 s¹ shear rate, the behavior is inbetween the other two shear rates since there is still some shear energy being put into the system and the fluid can not fully relax, therefore, it takes longer (−7 minutes) to relax than at 1 s⁻¹, and the final equilibrium viscosity is higher (−15% of fully shear activated viscosity). This behavior allows us to pick the right shear to tune the fluid viscosities.

The particular embodiments disclosed above are illustrative only, as the invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details herein shown, other than as described in the claims below. It is therefore evident that the particular embodiments disclosed above may be altered or modified and all such variations are considered within the scope of the embodiments described herewith. Accordingly, the protection sought herein is as set forth in the claims below.

Claims

1. A method comprising:

a. injecting into a wellbore, a composition comprising an aqueous solution, a viscosifying agent, a degradable material, and sized salt particulates; and

b. allowing viscosity of the composition to increase and form a plug at dynamic reservoir conditions.

2. The method of claim 1, wherein the aqueous solution is brine.

3. The method of claim 1, wherein the viscosifying agent is a viscoelastic surfactant.

4. The method of claim 3, wherein the viscoelastic surfactant is a mixture of erucylamidopropyl betaine and copolymer of polyvinyl acetate/polyvinyl alcohol.

5. The method of claim 1, wherein the degradable material is degradable fiber.

6. The method of claim 5, wherein the degradable fiber is a PLA fiber.

7. The method of claim 1, wherein the sized salt particulates are sized sodium chloride particulates.

8. The method of claim 1, wherein the sized salt particulates are present in an amount of about 5% to about 30% by weight of the composition.

9. The method of claim 8, wherein the sized salt particulates are present in an amount of about 10% to about 20% by weight of the composition.

10. The method of claim 1, wherein the dynamic reservoir conditions include a shear rate above about 1 s−1.

11. The method of claim 10, wherein the dynamic reservoir conditions include a shear rate above about 10 s−1.

12. The method of claim 1, wherein the composition further comprises a breaker.

13. A method of diverting a treatment fluid in a wellbore comprising:

a. injecting into the wellbore the treatment fluid to treat a first zone;

b. injecting into the wellbore, a composition comprising an aqueous solution, a viscosifying agent, a degradable material, and sized salt particulates;

c. allowing viscosity of the composition to increase and form a plug at dynamic reservoir conditions; and

d. diverting the treatment fluid from first zone to a second zone with the plug.

14. The method of claim 13, wherein formation of the plug is done during continuous injection of the treatment fluid.

15. The method of claim 13, wherein the treatment fluid is a fracturing fluid.

16. The method of claim 13, wherein the aqueous solution is brine.

17. The method of claim 16, wherein the brine is near saturation.

18. The method of claim 16, wherein the brine is saturated.

19. The method of claim 13, wherein the viscosifying agent is a viscoelastic surfactant.

20. The method of claim 19, wherein the viscoelastic surfactant is a mixture of erucylamidopropyl betaine and copolymer of polyvinyl acetate/polyvinyl alcohol.

21. The method of claim 13, wherein the degradable material is degradable fiber.

22. The method of claim 21, wherein the degradable fiber is a PLA fiber.

23. The method of claim 13, wherein the sized salt particulates are sized sodium chloride particulates.

24. The method of claim 13, wherein the sized salt particulates are present in an amount of about 5% to about 30% by weight of the composition.

25. The method of claim 24, wherein the sized salt particulates are present in an amount of about 10% to about 20% by weight of the composition.

26. The method of claim 13, wherein the dynamic reservoir conditions include a shear rate above about 1 s−1.

27. The method of claim 26, wherein the dynamic reservoir conditions include a shear rate above about 10 s−1.

28. A method of fracturing a subterranean formation in a wellbore comprising:

a. injecting into the wellbore a fracturing fluid to create a fracture in the subterranean formation;

b. injecting into the wellbore, a composition comprising an aqueous solution, a viscosifying agent, a degradable material, and sized salt particulates;

c. allowing viscosity of the composition to increase and form a plug at dynamic reservoir conditions; and

d. diverting the fracturing fluid with the plug to create a second fracture in the subterranean formation.