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Publication numberUS20080006405 A1
Publication typeApplication
Application numberUS 11/482,601
Publication dateJan 10, 2008
Filing dateJul 6, 2006
Priority dateJul 6, 2006
Publication number11482601, 482601, US 2008/0006405 A1, US 2008/006405 A1, US 20080006405 A1, US 20080006405A1, US 2008006405 A1, US 2008006405A1, US-A1-20080006405, US-A1-2008006405, US2008/0006405A1, US2008/006405A1, US20080006405 A1, US20080006405A1, US2008006405 A1, US2008006405A1
InventorsRichard Rickman, Philip Nguyen
Original AssigneeHalliburton Energy Services, Inc.
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Methods and compositions for enhancing proppant pack conductivity and strength
US 20080006405 A1
Abstract
Methods comprising providing a curable resin composition that comprises a curable resin and at least a plurality of filler particles; and coating at least a plurality of particulates with the curable resin composition on-the-fly to form curable resin coated particulates. The curable resin coated particulates may be suspended in a treatment fluid and placed into at least a portion of a subterranean formation.
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Claims(20)
1. A method comprising:
providing at least a plurality of particulates;
providing a curable resin composition comprising a curable resin and at least a plurality of filler particles;
coating the particulates with the curable resin composition on-the-fly to form curable resin coated particulates;
suspending the curable resin coated particulates in a treatment fluid; and
placing the treatment fluid into at least a portion of a subterranean formation.
2. The method of claim 1 wherein the filler particles comprise at least one filler particle selected from the group consisting of silica, glass, clay, alumina, fumed carbon, carbon black, graphite, mica, meta-silicate, calcium silicate, calcine, kaoline, talc, zirconia, titanium dioxide, fly ash, boron, and any combination thereof.
3. The method of claim 1 wherein the size of the filler particles is from about 0.01 μm to about 100 μm.
4. The method of claim 1 wherein the curable resin comprises at least one curable resin selected from the group consisting of a two component epoxy based resin, a novolak resin, a polyepoxide resin, a phenol aldehyde resin, a urea aldehyde resin, a urethane resin, a phenolic resin, a furan resin, a furan/furfuryl alcohol resin, a phenolic/latex resin, a phenol formaldehyde resin, a polyester resin and any hybrid or copolymer thereof, a polyurethane resin and any hybrid or copolymer thereof, an acrylate resin, and any combination thereof.
5. The method of claim 1 wherein the curable resin composition is coated on the curable resin coated particulates in an amount in the range of from about 0.1% to about 25% by weight of the particulates.
6. The method of claim 1 wherein the filler particles are included in the curable resin composition in an amount in the range of from about 1% to about 70% by weight of the curable resin composition.
7. A method comprising:
providing a curable resin composition that comprises a curable resin and at least a plurality of filler particles; and
coating at least a plurality of particulates with the curable resin composition on-the-fly to form curable resin coated particulates.
8. The method of claim 7 further comprising the steps of suspending the curable resin coated particulates in a treatment fluid and placing the treatment fluid into at least a portion of a subterranean formation.
9. The method of claim 7 wherein the filler particles comprise at least one filler particle selected from the group consisting of silica, glass, clay, alumina, fumed carbon, carbon black, graphite, mica, meta-silicate, calcium silicate, calcine, kaoline, talc, zirconia, titanium dioxide, fly ash, boron, and an y combination thereof.
10. The method of claim 7 wherein the size of the filler particles is from about 0.01 μm to about 100 μm.
11. The method of claim 7 wherein the curable resin comprises at least one curable resin is selected from the group consisting of a two component epoxy based resin, a novolak resin, a polyepoxide resin, a phenol aldehyde resin, a urea aldehyde resin, a urethane resin, a phenolic resin, a furan resin, a furan/furfuryl alcohol resin, a phenolic/latex resin, a phenol formaldehyde resin, a polyester resin and any hybrid or copolymer thereof, a polyurethane resin and any hybrid or copolymer thereof, an acrylate resin, and any combination thereof.
12. The method of claim 7 wherein the curable resin composition is coated on the curable resin coated particulates in an amount in the range of from about 0.1% to about 25% by weight of the particulates.
13. The method of claim 7 wherein the filler particles are included in the curable resin composition in an amount in the range of from about 1% to about 70% by weight of the curable resin composition.
14. A method comprising:
providing a curable resin and at least a plurality of filler particles;
combining the curable resin and the filler particles at the well site to form a curable resin composition; and
coating at least a plurality of particulates with the curable resin composition on-the-fly to form curable resin coated particulates.
15. The method of claim 14 further comprising the steps of suspending the curable resin coated particulates in a treatment fluid and placing the treatment fluid into at least a portion of a subterranean formation.
16. The method of claim 14 wherein the filler particles comprise at least one particle selected from the group consisting of silica, glass, clay, alumina, fumed carbon, carbon black, graphite, mica, meta-silicate, calcium silicate, calcine, kaoline, talc, zirconia, titanium dioxide, fly ash, boron, and an y combination thereof.
17. The method of claim 14 wherein the size of the filler particles is from about 0.01 μm to about 100 μm.
18. The method of claim 14 wherein the curable resin is comprises at least one curable resin selected from the group consisting of a two component epoxy based resin, a novolak resin, a polyepoxide resin, a phenol aldehyde resin, a urea aldehyde resin, a urethane resin, a phenolic resin, a furan resin, a furan/furfuryl alcohol resin, a phenolic/latex resin, a phenol formaldehyde resin, a polyester resin and any hybrid or copolymer thereof, a polyurethane resin and any hybrid or copolymer thereof, an acrylate resin, and any combination thereof.
19. The method of claim 14 wherein the curable resin composition is coated on the curable resin coated particulates in an amount in the range of from about 0.1% to about 25% by weight of the particulates.
20. The method of claim 14 wherein the filler particles are included in the curable resin composition in an amount in the range of from about 1% to about 70% by weight of the curable resin composition.
Description
BACKGROUND

The present invention relates to the treatment of subterranean formations. More particularly, the present invention relates to methods and compositions for enhancing proppant pack conductivity and strength.

Hydrocarbon-producing wells are often stimulated by hydraulic fracturing treatments. Hydraulic fracturing operations generally involve pumping a treatment fluid (e.g., a fracturing fluid or a “pad” fluid) into a well bore that penetrates a subterranean formation at a hydraulic pressure sufficient to create or enhance at least one or more fractures in the subterranean formation. The fluid used in the treatment may comprise particulates, which are often referred to as “proppant particulates,” that are deposited in the resultant fractures. The proppant particulates are thought to prevent the fractures from fully closing upon the release of hydraulic pressure, forming conductive channels through which fluids may flow to a well bore to ultimately be produced. The term “propped fracture” as used herein refers to a fracture (naturally-occurring or otherwise) in a portion of a subterranean formation that contains at least a plurality of proppant particulates. The term “proppant pack” refers to a collection of proppant particulates within a fracture.

Hydrocarbon-producing wells also may undergo gravel packing treatments, inter alia, to reduce the migration of unconsolidated formation particulates into the well bore. In gravel packing operations, particulates, often referred to in the art as gravel, are suspended in a treatment fluid, which may be viscosified, and the treatment fluid is pumped into a well bore in which the gravel pack is to be placed. As the particulates are placed in or near a subterranean zone, the treatment fluid is either returned to the surface or leaks off into the zone. The resultant gravel pack acts as a filter to prevent the production of the formation solids with the produced fluids. Traditional gravel pack operations may involve placing a gravel pack screen in the well bore and then packing the surrounding annulus between the screen and the well bore with gravel. The gravel pack screen is generally a filter assembly used to support and retain the gravel placed during the gravel pack operation. A wide range of sizes and screen configurations is available to suit the characteristics of a well bore, the production fluid, and any particulates in the subterranean formation.

In some situations, hydraulic fracturing and gravel packing operations may be combined into a single treatment. Such treatments are often referred to as “frac pack” operations. In some cases, the treatments are generally completed with a gravel pack screen assembly in place with the hydraulic fracturing treatment being pumped through the annular space between the casing and screen. In this situation, the hydraulic fracturing treatment ends in a screen-out condition, creating an annular gravel pack between the screen and casing. In other cases, the fracturing treatment may be performed prior to installing the screen and placing a gravel pack.

Particulates (such as proppant or gravel) used in subterranean operations are often coated with resins to facilitate consolidation of the particulates and/or to prevent their subsequent flow-back through the conductive channels in the subterranean formation, which can, for example, clog the conductive channels and/or damage the interior of the formation or equipment. The term “resin” as used herein refers to any of numerous physically similar polymerized synthetics or chemically modified natural resins including thermoplastic materials and thermosetting materials.

Generally, resin coated proppants are either precured or curable. Precured resin coated proppants comprise a proppant coated with a resin that has been significantly crosslinked. This precured resin coating provides crush resistance to the proppant. The resin coating is already cured before it is introduced into the well and therefore, the proppant does not agglomerate. However, in some instances, precured proppants may flow back from a propped fracture, especially during clean up or production in oil and gas wells, because they are mainly held in the fracture by stress.

In contrast, curable resin coated proppants comprise a proppant coated with a resin which has not been significantly crosslinked before being placed in a subterranean formation. Curable resins include (i) resins which are cured entirely in the subterranean formation and (ii) resins which are partially cured prior to injection into the subterranean formation with the remainder of curing occurring in the subterranean formation. Curing occurs as a result of the crosslinking of the resin, which may occur as a result of the stress and temperature conditions existing in the subterranean formation, and/or as a result of an activator and/or catalyst. This is believed to cause the proppant to bond together and form a 3-dimensional matrix and thereby prevent proppant flow-back. However, curable resins may be expensive. Therefore, any filler medium that can be admixed with a resin composition to enhance the consolidation performance of coating on particulates, allowing a reduced amount of resin coating on proppant, is economically desirable.

SUMMARY

The present invention relates to the treatment of subterranean formations. More particularly, the present invention relates to methods and compositions for enhancing proppant pack conductivity and strength.

One embodiment of the present invention is a method comprising: providing at least a plurality of particulates; providing a curable resin composition comprising a curable resin and at least a plurality of filler particles; coating the particulates with the curable resin composition on-the-fly to form curable resin coated particulates; suspending the curable resin coated particulates in a treatment fluid; and placing the treatment fluid into at least a portion of a subterranean formation.

Another embodiment of the present invention is a method comprising: providing a curable resin composition that comprises a curable resin and at least a plurality of filler particles; and coating at least a plurality of particulates with the curable resin composition on-the-fly.

Another embodiment of the present invention is a method comprising: providing a curable resin and at least a plurality of filler particles; combining the curable resin and the filler particles at the well site to form a curable resin composition; and coating at least a plurality of particulates with the curable resin composition on-the-fly.

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

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention relates to the treatment of subterranean formations. More particularly, the present invention relates to methods and compositions for enhancing proppant pack conductivity and strength.

In accordance with the methods and compositions of the present invention, at least a plurality of particulates may be at least partially coated with a curable resin composition that comprises a curable resin and at least a plurality of filler particles. These particulates may be referred to herein as “coated particulates.” In some embodiments, these coated particulates may be used, inter alia, to facilitate the consolidation of the particulates into a permeable mass that may improve the resiliency, crush resistance, and/or conductivity of a resulting particulate pack. Additionally, in some embodiments, these coated particulates may be 100% curable within the subterranean formation, so as to form a permeable mass of high compressive strength. The term “coated” as used herein does not imply any particular degree of coverage of the particulates with a curable resin composition.

In certain embodiments, the particulates may be coated with the curable resin composition in an amount of from about 0.1% to about 25% by weight of the particulates. In other embodiments, particulates may be coated with the curable resin composition in an amount of from about 1% to about 5% by weight of the particulates.

The particulates may be coated by any suitable method as recognized by one skilled in the art with the benefit of this disclosure. In some embodiments, the particulates may be coated with the curable resin composition on-the-fly and then introduced into a subterranean formation. As used herein, the term “on-the-fly” is used to mean that a flowing stream is continuously introduced into another flowing stream so that the streams are combined and mixed while continuing to flow as a single stream as part of an on-going treatment. Some potential advantages that may be achieved by coating particulates with the curable resin composition on-the-fly is that the amount or type of filler particles included in the curable resin composition may be adjusted immediately prior to the proppants being coated and introduced into the formation.

In certain embodiments, the coated particulates may be suspended in a treatment fluid and this treatment fluid may be placed into a subterranean formation. The coated particulates may be suspended in the treatment fluid by any suitable method as recognized by one skilled in the art with the benefit of this disclosure.

A wide variety of particulate materials may be used in accordance with the present invention, including, but not limited to, sand, bauxite, ceramic materials, glass materials, resin precoated proppant (e.g., commercially available from Borden Chemicals and Santrol, for example, both from Houston, Tex.), polymer materials, “TEFLON™” (tetrafluoroethylene) materials, nut shells, ground or crushed nut shells, seed shells, ground or crushed seed shells, fruit pit pieces, ground or crushed fruit pits, processed wood, composite particulates prepared from a binder with filler particulate including silica, alumina, fumed silica, carbon black, graphite, mica, titanium dioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash, hollow glass microspheres, and solid glass; or mixtures thereof. The particulate material used may have a particle size in the range of from about 2 to about 400 mesh, U.S. Sieve Series. Preferably, the particulate material is graded sand having a particle size in the range of from about 10 to about 70 mesh, U.S. Sieve Series. Preferred sand particle size distribution ranges are one or more of 10-20 mesh, 20-40 mesh, 40-60 mesh or 50-70 mesh, depending on the particle size and distribution of the formation particulates to be screened out by the particulate materials. It should be understood that the term “particulate,” as used in this disclosure, includes all known shapes of materials including substantially spherical materials, fibrous materials, polygonal materials (such as cubic materials) and mixtures thereof. It should also be understood that the term “proppant,” as used in this disclosure, includes all known shapes of materials including substantially spherical materials, fibrous materials, polygonal materials (such as cubic materials) and mixtures thereof.

Curable resins suitable for use in the methods and compositions of the present invention include any resin that is capable of forming a hardened, consolidated mass. The term “resin” as used herein includes any of numerous physically similar polymerized synthetics or chemically modified natural resins, including but not limited to thermoplastic materials and thermosetting materials. Many such resins are commonly used in subterranean consolidation operations, and some suitable resins include two component epoxy based resins, novolak resins, polyepoxide resins, phenol-aldehyde resins, urea-aldehyde resins, urethane resins, phenolic resins, furan resins, furan/furfuryl alcohol resins, phenolic/latex resins, phenol formaldehyde resins, polyester resins and hybrids and copolymers thereof, polyurethane resins and hybrids and copolymers thereof, acrylate resins, and mixtures thereof. Some suitable resins, such as epoxy resins, may be cured with an internal catalyst or activator so that when pumped downhole, they may be cured using only time and temperature. Other suitable resins, such as furan resins generally require a time-delayed catalyst or an external catalyst to help activate the polymerization of the resins if the cure temperature is low (i.e., less than 250° F.) but will cure under the effect of time and temperature if the formation temperature is above about 250° F., preferably above about 300° F. It is within the ability of one skilled in the art, with the benefit of this disclosure, to select a suitable resin for use in embodiments of the present invention and to determine whether a catalyst is required to trigger curing.

Selection of a suitable curable resin may be affected by the temperature of the subterranean formation to which the fluid will be introduced. By way of example, for subterranean formations having a bottom hole static temperature (“BHST”) ranging from about 60° F. to about 250° F., two component epoxy based resins comprising a hardenable resin component and a hardening agent component containing specific hardening agents may be preferred. For subterranean formations having a BHST ranging from about 300° F. to about 600° F., a furan based resin may be preferred. For subterranean formations having a BHST ranging from about 200° F. to about 400° F., either a phenolic based resin or a one component HT epoxy based resin may be suitable. For subterranean formations having a BHST of at least about 175° F., a phenol/phenol formaldehyde/furfuryl alcohol resin may also be suitable.

Any solvent that is compatible with the chosen resin and achieves the desired viscosity effect is suitable for use in the present invention. Some preferred solvents are those having high flash points (e.g., about 125° F.) because of, among other things, environmental and safety concerns; such solvents include butyl lactate, butylglycidyl ether, dipropylene glycol methyl ether, dipropylene glycol dimethyl ether, dimethyl formamide, diethyleneglycol methyl ether, ethyleneglycol butyl ether, diethyleneglycol butyl ether, propylene carbonate, methanol, butyl alcohol, d-limonene, fatty acid methyl esters, and combinations thereof. Other preferred solvents include aqueous dissolvable solvents such as, methanol, isopropanol, butanol, glycol ether solvents, and combinations thereof. Suitable glycol ether solvents include, but are not limited to, diethylene glycol methyl ether, dipropylene glycol methyl ether, 2-butoxy ethanol, ethers of a C2 to C6 dihydric alkanol containing at least one C1 to C6 alkyl group, mono ethers of dihydric alkanols, methoxypropanol, butoxyethanol, hexoxyethanol, and isomers thereof. Selection of an appropriate solvent is dependent on the resin chosen and is within the ability of one skilled in the art with the benefit of this disclosure.

Suitable filler particles for use in the present invention include any particle that does not adversely react with the other components used in accordance with this invention or with the subterranean formation. Examples of suitable filler particles include silica, glass, clay, alumina, fumed silica, carbon black, graphite, mica, meta-silicate, calcium silicate, calcine, kaoline, talc, zirconia, titanium dioxide, fly ash, boron, and combinations thereof. In some embodiments, the filler particles may range in size from about 0.01 μm to about 100 μm. As will be understood by one skilled in the art, particles of smaller average size may be particularly useful in situations where it is desirable to obtain high proppant pack permeability (i.e., conductivity), and/or high consolidation strength. In certain embodiments, the filler particles may be included in the curable resin compositions of the present invention in an amount of about 1% to about 70% by weight of the curable resin composition.

Generally, the filler particles may be admixed with a resin by any suitable method as recognized by one skilled in the art with the benefit of this disclosure. In some embodiments of the present invention, the filler particles may be admixed with the curable resin well in advance of the curable resin composition being coated onto particulates to be introduced into a subterranean formation, creating a curable resin composition that may be used at some time in the future. In other embodiments, the filler particles may be admixed with the curable resin at the well site.

In certain embodiments, the particulates may be at least partially coated with the curable resin composition and introduced into a treatment fluid, which acts as the aqueous medium, directly prior to being introduced into a subterranean formation in an on-the-fly treatment. For instance, the curable resin composition coated particulates may be mixed with an aqueous liquid (such as a treatment fluid) on-the-fly to form a treatment slurry. Such mixing can also be described as “real-time” mixing. One advantage of using on-the-fly mixing in the methods of the present invention is that it may allow for reduced waste in the event the treatment needs to be immediately shut down. As is well understood by those skilled in the art, mixing may also be accomplished by batch or partial batch mixing.

Generally, any treatment fluid suitable for a subterranean operation may be used in accordance with the methods of the present invention, including aqueous gels, viscoelastic surfactant gels, foamed gels and emulsions. Suitable aqueous gels are generally comprised of water and one or more gelling agents. Suitable emulsions can be comprised of two immiscible liquids such as an aqueous liquid or gelled liquid and a hydrocarbon. Foams can be created by the addition of a gas, such as carbon dioxide or nitrogen. In certain embodiments of the present invention, the treatment fluids are aqueous gels comprised of water, a gelling agent for gelling the water and increasing its viscosity, and, optionally, a crosslinking agent for crosslinking the gel and further increasing the viscosity of the fluid. The increased viscosity of the gelled, or gelled and cross-linked, treatment fluid, inter alia, reduces fluid loss and allows the treatment fluid to transport significant quantities of suspended particulates. The water used to form the treatment fluid may be fresh water, salt water, brine, sea water, or any other aqueous liquid that does not adversely react with the other components. The density of the water can be increased to provide additional particle transport and suspension in the present invention.

A variety of gelling agents may be used, including hydratable polymers that contain one or more functional groups such as hydroxyl, carboxyl, sulfate, sulfonate, amino, or amide groups. Suitable gelling agents typically comprise polymers, synthetic polymers, or a combination thereof. A variety of gelling agents may be used in conjunction with the methods of the present invention, including, but not limited to, hydratable polymers that contain one or more functional groups such as hydroxyl, cis-hydroxyl, carboxylic acids, derivatives of carboxylic acids, sulfate, sulfonate, phosphate, phosphonate, amino, or amide. In some embodiments, the gelling agents may be polymers comprising polysaccharides, and derivatives thereof that contain one or more of these monosaccharide units: galactose, mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronic acid, or pyranosyl sulfate. Examples of suitable polymers include, but are not limited to, guar gum and derivatives thereof, such as hydroxypropyl guar and carboxymethylhydroxypropyl guar, and cellulose derivatives, such as hydroxyethyl cellulose. Additionally, synthetic polymers and copolymers that contain the above-mentioned functional groups may be used. Examples of such synthetic polymers include, but are not limited to, polyacrylate, polymethacrylate, polyacrylamide, polyvinyl alcohol, and polyvinylpyrrolidone. In other embodiments, the gelling agent molecule may be depolymerized. The term “depolymerized,” as used herein, generally refers to a decrease in the molecular weight of the gelling agent molecule. Depolymerized gelling agent molecules are described in U.S. Pat. No. 6,488,091 issued Dec. 3, 2002 to Weaver, et al., the relevant disclosure of which is incorporated herein by reference. Suitable gelling agents that may be used in conjunction with the methods of the present invention may be present in the treatment fluid in an amount in the range of from about 0.01% to about 5% by weight of the water therein. In some embodiments, the gelling agents may be present in the treatment fluid in an amount in the range of from about 0.01% to about 2% by weight of the water therein.

Crosslinking agents may be used to crosslink gelling agent molecules to form crosslinked gelling agents. Crosslinkers typically comprise at least one metal ion that is capable of crosslinking molecules. Examples of suitable crosslinkers include, but are not limited to, zirconium compounds (such as, for example, zirconium lactate, zirconium lactate triethanolamine, zirconium acetylacetonate, zirconium citrate, and zirconium diisopropylamine lactate); titanium compounds (such as, for example, titanium lactate, titanium citrate, titanium ammonium lactate, titanium triethanolamine, and titanium acetylacetonate); aluminum compounds (such as, for example, aluminum lactate or aluminum citrate); antimony compounds; chromium compounds; iron compounds; copper compounds; zinc compounds; or a combination thereof. An example of a suitable commercially available zirconium-based crosslinker is “CL-24” available from Halliburton Energy Services, Inc., Duncan, Okla. An example of a suitable commercially available titanium-based crosslinker is “CL-39” available from Halliburton Energy Services, Inc., Duncan, Okla. Suitable crosslinkers that may be used in conjunction with the methods of the present invention may be present in the treatment fluid in an amount sufficient to provide, inter alia, the desired degree of crosslinking between gelling agent molecules. In some embodiments of the present invention, the crosslinkers may be present in the treatment fluid in an amount in the range from about 0.001% to about 10% by weight of the water therein. In other embodiments of the present invention, the crosslinkers may be present in the treatment fluid in an amount in the range from about 0.01% to about 1% by weight of the water therein. Individuals skilled in the art, with the benefit of this disclosure, will recognize the exact type and amount of crosslinker to use depending on factors such as the specific gelling agent, desired viscosity, and formation conditions.

The gelled or gelled and cross-linked treatment fluids may also include internal delayed gel breakers such as enzyme, oxidizing, acid buffer, or temperature-activated gel breakers. The gel breakers cause the viscous treatment fluids to revert to thin fluids that can be produced back to the surface after they have been used to place particulates in subterranean fractures. The gel breaker used is typically present in the treatment fluid in an amount in the range of from about 0.05% to about 10% by weight of the gelling agent. The treatment fluids may also include one or more of a variety of well-known additives, such as gel stabilizers, fluid loss control additives, clay stabilizers, bactericides, and the like.

To facilitate a better understanding of the present invention, the following examples of certain aspects of some embodiments are given. In no way should the following examples be read to limit, or define, the entire scope of the invention.

Example 1

Consolidation strength testing was performed using a commercially available curable resin available under the trade name “EXPEDITE 225” from Halliburton Energy Services. Sample portions of equal volumes of 20/40 Brady sand were each coated with 3% of the curable resin composition containing variable amounts of silica flour as the filler particles. Sample 1 was the control and did not contain any silica flour. Sample 2 contained 5% silica flour. Sample 3 contained 10% silica flour. Sample 4 contained 20% silica flour. Sample 5 contained 40% silica flour.

The resulting unconfined compressive strengths of the proppant are given below in Table 1.

TABLE 1
Compressive Strength
Sample % Silica Flour (psi)
1 0 1664
2 5 1546
3 10 1215
4 20 1526
5 40 1096

From Table 1, it is evident that the resin-treated proppants achieve unconfined compressive strengths.

Example 2

Consolidation strength testing was performed using a commercially available curable resin available under the trade name “EXPEDITE 225” from Halliburton Energy Services. In addition to filler particulates, a silane coupling agent was added to the curable resin composition. Sample portions of equal volumes of 20/40 Brady sand were each coated with 3% of the curable resin composition containing 40% silica flour, and variable amounts of a silane coupling agent. Sample 1 contained 1% of the silane coupling agent. Sample 2 contained 2% of the silane coupling agent. Sample 3 contained 4% of the silane coupling agent. Sample 4 contained 6% of the silane coupling agent was added.

The resulting unconfined compressive strengths of the proppant are given below in Table 2

TABLE 2
% Silane Coupling Compressive Strength
Sample Agent (psi)
1 1 1096
2 2 966
3 4 1886
4 6 1462

From Table 2, it is evident that the resin-treated proppants achieve unconfined compressive strengths.

Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present 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. While numerous changes may be made by those skilled in the art, such changes are encompassed within the spirit of this invention as defined by the appended claims. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention. In particular, every range of values (e.g., “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood as referring to the power set (the set of all subsets) of the respective range of values. The terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.

Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US7703520Apr 11, 2008Apr 27, 2010Halliburton Energy Services, Inc.Sand control screen assembly and associated methods
US7712529Jan 8, 2008May 11, 2010Halliburton Energy Services, Inc.Sand control screen assembly and method for use of same
US7814973Aug 29, 2008Oct 19, 2010Halliburton Energy Services, Inc.Sand control screen assembly and method for use of same
US7841409Aug 29, 2008Nov 30, 2010Halliburton Energy Services, Inc.Sand control screen assembly and method for use of same
US7866383Aug 29, 2008Jan 11, 2011Halliburton Energy Services, Inc.Sand control screen assembly and method for use of same
US8306751Dec 31, 2009Nov 6, 2012Halliburton Energy Services, Inc.Testing additives for production enhancement treatments
US8478532Jul 23, 2012Jul 2, 2013Halliburton Energy Services, Inc.Testing additives for production enhancement treatments
US8714249Oct 26, 2012May 6, 2014Halliburton Energy Services, Inc.Wellbore servicing materials and methods of making and using same
US20140076559 *Sep 18, 2012Mar 20, 2014Halliburton Energy Services, Inc.Methods of Treating a Subterranean Formation with Stress-Activated Resins
WO2013028298A2Jul 23, 2012Feb 28, 2013Halliburton Energy Services, Inc.Fracturing process to enhance propping agent distribution to maximize connectivity between the formation and the wellbore
WO2014035724A1Aug 20, 2013Mar 6, 2014Halliburton Energy Services, Inc.Methods for forming highly conductive propped fractures
WO2014070144A1Oct 30, 2012May 8, 2014Halliburton Energy Services, Inc.Drilling fluid compositions and methods for use thereof in subterranean formations
Classifications
U.S. Classification166/295, 507/219, 166/305.1
International ClassificationE21B33/138
Cooperative ClassificationC09K8/805
European ClassificationC09K8/80B
Legal Events
DateCodeEventDescription
Jul 6, 2006ASAssignment
Owner name: HALLIBURTON ENERGY SERVICES, INC., TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:RICKMAN, RICHARD D.;NGUYEN, PHILIP D.;REEL/FRAME:018051/0587;SIGNING DATES FROM 20060705 TO 20060706