WO2016097789A1

WO2016097789A1 - Heterogeneous proppant placement

Info

Publication number: WO2016097789A1
Application number: PCT/IB2014/003115
Authority: WO
Inventors: Anastasia Evgenyevna SHALAGINA; Alexey Viktorovich ZINCHENKO; Anatoly Vladimirovich Medvedev; Chad KRAEMER
Original assignee: Schlumberger Canada Limited; Schlumberger Technology Corporation; Schlumberger Holdings Limited; Schlumberger Technology B.V.; Prad Research And Development Limited; Services Petroliers Schlumberger
Priority date: 2014-12-18
Filing date: 2014-12-18
Publication date: 2016-06-23
Also published as: AR102596A1

Abstract

Methods of treating a subterranean formation are disclosed that include introducing a treatment fluid including crimped fibers and a particulate material into a subterranean formation via a wellbore, and forming a plurality of bulky fibrous flocks including the crimped fibers and particulate material.

Description

HETEROGENEOUS PROPPANT PLACEMENT

BACKGROUND

Hydrocarbons (oil, natural gas, etc.) may be obtained from a subterranean geologic formation (a "reservoir") by drilling a well that penetrates the hydrocarbon- bearing formation. Well treatment methods often are used to increase hydrocarbon production by using a treatment fluid to interact with a subterranean formation in a manner that ultimately increases oil or gas flow from the formation to the wellbore for removal to the surface.

Hydrocarbon production from unconventional resources, such as shales and tight gas formations, is becoming a part of the energy supply to meet today's increasing demand. Production from gas and oil shale has become economical mostly because of application of hydraulic fracturing techniques. In unconventional low permeable reservoirs, production may come from one or more complex fracture networks. The complex fracture network may include primary fractures, which are connected to secondary, and then tertiary fractures. To achieve maximum production it is highly desirable to have all fractures propped and connected.

Slickwater fracturing is the most commonly used technique in unconventional subterranean formations, such as shales and tight gas formations, due to economical and operational considerations. However, the low viscosity of such a fracturing fluid comes with an undesired effect of increased rates of proppant sedimentation, which does not allow either far-field delivery of proppant into fracture or uniform placement of proppant along the fracture height. Therefore, under such conditions the chance of proppant delivery into secondary and tertiary factures is very low. The use of conventional fiber for slickwater fracturing is also challenging due to an excessive bridging ability of fiber material in low viscosity environment.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. In some embodiments, the present disclosure relates a method for treating a subterranean formation, where the method includes preparing a treatment fluid containing a carrier fluid and bulky fibrous flocks, and at least some of the bulky fibrous flocks include a crimped fiber and a particulate material; and introducing the treatment fluid into a subterranean formation via a wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

The manner in which the objectives of the present disclosure and other desirable characteristics may be obtained is explained in the following description and attached drawings in which: FIG. 1A is a photograph of proppant pillars formed in slickwater with crimped fibers;

FIG. IB is an blowup of a 100 mm x 100 mm size portion of the photograph of FIG. 1A showing proppant pillars formed in slickwater with crimped fibers;

FIG. 1C shows a plot of the distribution of sand concentration of the 100 mm x 100 mm size portion of the photograph of FIG. 1A;

FIG. 2 is a photograph of proppant pillars formed in linear guar gel with crimped fibers;

FIG. 3 is a photograph of proppant placement in conventional slickwater fluid without fiber; and FIG. 4 is a photograph of proppant pillars formed in slickwater with straight fibers.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to provide an understanding of the present disclosure. However, it may be understood by those skilled in the art that the methods of the present disclosure may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.

At the outset, it should be noted that in the development of any such actual embodiment, numerous implementation-specific decisions may be made to achieve the developer's specific goals, such as compliance with system related and business related constraints, which will 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. In addition, the composition used/disclosed herein can also comprise some components other than those cited. In the summary 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 and this detailed description, it should be understood that a range listed or described as being useful, suitable, or the like, is intended to include support for any conceivable sub-range within the range at least because every point 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 possible number along the continuum between about 1 and about 10. Furthermore, one or more of the data points in the present examples may be combined together, or may be combined with one of the data points in the specification to create a range, and thus include each possible value or number within this range. Thus, (1) even if numerous specific data points within the range are explicitly identified, (2) even if reference is made to a few specific data points within the range, or (3) even when no data points within the range are explicitly identified, it is to be understood (i) that the inventors appreciate and understand that any conceivable data point within the range is to be considered to have been specified, and (ii) that the inventors possessed knowledge of the entire range, each conceivable sub-range within the range, and each conceivable point within the range. Furthermore, the subject matter of this application illustratively disclosed herein suitably may be practiced in the absence of any element(s) that are not specifically disclosed herein.

Fibers may be used for various purposes in oilfield treatment operations. The methods of the present disclosure use crimped fibers as a component in a treatment fluid, such as a treatment fluid used during heterogeneous proppant placement treatment.

In a heterogeneous proppant placement treatment, the proppant is placed throughout the fracture and can form clusters of proppant with open channels between the clusters. When the fracture is allowed to close, the clusters can act as pillars to keep fracture propped open. However, the proppant clusters may not be designed to be permeable. Unlike the hydraulic conductivity of interstitial proppant packs of traditional fracturing treatments, the hydraulic conductivity of the heterogeneous proppant placement fracture can be through the open channels. Thus, heterogeneous proppant placement conductivity can be very high since there is minimal obstruction to flow in the open channels.

The methods of the present disclosure use crimped fibers as a component in a treatment fluid, such as a treatment fluid used during heterogeneous proppant placement treatment. As opposed to straight fiber, the crimped fiber morphology helps to form bulky fibrous flocks, such as, stochastic clumps of fibers created by elastic, frictional and hydrodynamic forces. Such bulky fibrous flocks, heterogeneously distributed in a fracture, hold proppant particles and do not allow the proppant particles to settle. In some embodiments, bulky fibrous flocks (such as, for example, bulky fibrous flocks formed during pumping) that are formed with crimped fibers are able to be transported to the treatment zone of interest without bridging.

The methods of the present disclosure may include introducing a treatment fluid comprising crimped fiber (and/or a fiber capable of being crimped on site or in situ) into a subterranean formation, such as during a hydraulic fracturing treatment for the creation of heterogeneities in proppant pack to improve well productivity, but otherwise use conventional techniques known in the art, such as, for example, methodology for heterogeneous proppant placement described in U.S. Patent No. 7,581,590 and U.S. Patent Application Publication Nos. 20080149329 and 20130105166, the disclosures of which are herein incorporated by reference in their entireties. As used herein, the term "treatment fluid," refers to any pumpable and/or flowable fluid used in a subterranean operation in conjunction with a desired function and/or for a desired purpose. Such treatment fluids may be modified to contain crimped fibers. In some embodiments, the pumpable and/or flowable treatment fluid may have any suitable viscosity, such as a viscosity of from about 0.5 cP to about 50 cP (such as from about 1 cP to about 20 cP, or from about 1 cP to about 10 cP) at the treating temperature, which may range from a surface temperature to a bottom-hole static (reservoir) temperature, such as from about 4°C to about 149°C, or from about 10°C to about 135°C, or from about 20°C to about 121°C, and a shear rate of about 170 s^"1 (for the definition of shear rate reference is made to, for example, Introduction to Rheology, Barnes, H.; Hutton, J.F; Walters, K. Elsevier, 1989, the disclosure of which is herein incorporated by reference in its entirety) as measured by common methods, such as those described in textbooks on rheology, including, for example, Rheology: Principles, Measurements and Applications, Macosko, C. W., VCH Publishers, Inc. 1994, the disclosure of which is herein incorporated by reference in its entirety.

The term "treatment," or "treating," does not imply any particular action by the fluid. For example, a treatment fluid placed or introduced into a subterranean formation subsequent to a leading-edge fluid may be a hydraulic fracturing fluid, an acidizing fluid (acid fracturing, acid diverting fluid), a stimulation fluid, a sand control fluid, a completion fluid, a wellbore consolidation fluid, a remediation treatment fluid, a cementing fluid, a driller fluid, a frac-packing fluid, or gravel packing fluid. In the methods of the present disclosure, any one of the above fluids may be modified to include one or more crimped fibers. The treatment fluids comprising a composition including one or more crimped fibers may be used in full-scale operations, pills, slugs, or any combination thereof. As used herein, a "pill" or "slug" is a type of relatively small volume of specially prepared treatment fluid placed or circulated in the wellbore.

As used herein, the term "treating temperature," refers to the temperature of the treatment fluid that is observed while the treatment fluid is performing its desired function and/or desired purpose, such as fracturing a subterranean formation.

The term "fracturing" refers to the process and methods of breaking down a geological formation and creating a fracture, such as the rock formation around a wellbore, by pumping a treatment fluid at very high pressures (pressure above the determined closure pressure of the formation), in order to increase production rates from or injection rates into a hydrocarbon reservoir. The fracturing methods of the present disclosure may include a composition containing one or more crimped fibers in one or more of the treatment fluids, but otherwise use conventional techniques and components known in the art, such as fracturing with heterogeneous proppant placement (including, for example, using pulsed proppant injection), for example, as described in U.S. Patent

Nos. 6,776,235 and 7,581,590, and U.S. Patent Application Publication Nos. 20080149329 and 20130105166, the disclosures of which are herein incorporated by reference in their entireties.

The treatment fluids of the present disclosure, which may comprise bulky fibrous flocks comprising crimped fibers and a particulate material, such as proppant, may be introduced during methods that may be applied at any time in the life cycle of a reservoir, field or oilfield. For example, the methods and treatment fluids of the present disclosure may be employed in any desired downhole application (such as, for example, stimulation) at any time in the life cycle of a reservoir, field or oilfield.

In embodiments, the treatment fluids of the present disclosure, which comprise a crimped fiber (and/or fiber that may be thermally triggered (such as at the wellsite, for example, either before and/or after introducing the fiber into the treatment fluid) to transform to a crimped fiber) may be formed at the surface and placed or introduced into a wellbore; or, in some embodiment, the components of the treatment fluids may be separately placed or introduced into a wellbore in any order and mixed downhole. As used herein, the term thermal "triggering event" refers to any action that increases the temperature of the crimped fiber in an amount sufficient to initiate the crimping of the fiber (or in the case of a previously crimped fiber to further crimp the fiber) in a manner effective to generate a crimped fiber. For example, the terms thermal "trigger", thermal "triggering" and thermally "triggered," as used herein, may include exposing a fiber to a thermal means, such as electromagnetic radiation, a high temperature treatment fluid and/or one or more temperatures within the subterranean formation temperature, such as bottom hole static temperature, to initiate, induce or cause the fiber to transform into a crimped fiber. In some embodiments, the thermal triggering event may be brought about by exposure to electromagnetic radiation, such as microwaves, infrared waves and/or other radiation types, effective to raise the temperature of the fiber such that it will transform into a crimped fiber.

A "crimped fiber" may be any three-dimensional crimped fiber having a sterically crimped shape, such as for example, a coiled shape fiber (that is, of a helical or spiral shape), a zigzag shape fiber (which may be in a planar or non-planer configuration) and/or U-shaped fiber. For example, a "coiled crimped fiber" refers, for example, to a state that the top part of the crimp is spirally curved. In some embodiments, the fibers are crimped staple fibers. In some embodiments, the crimped fibers comprise from about 0.5 to about 20 crimps/cm of length (such as about 1 to about 10 crimps/cm of length, or about 2 to about 8 crimps/cm of length), a crimp angle from about 45 to about 160 degrees (such as a crimp angle from about 55 to about 150 degrees), an average extended length of fiber of from about 2 to about 30 mm (or an average extended length of fiber of from about 3 to about 15 mm), and/or a mean diameter of from about 6 to about 40 microns (such as about 8 to about 12 microns, or about 8 to about 10 microns). In some embodiments, the crimped fibers comprise low crimping equal to or less than about 5 crimps/cm of fiber length, such as from about 0.5 about 5 crimps/cm, or from about 1.5 about 4 crimps/cm.

The term "latent crimped fiber" refers to a fiber that (upon exposure to a predetermined temperature at or above a shrinkage initiating temperature of the material of the fiber) is capable of shrinking to form a crimped fiber. For example, in some embodiments the crimped fiber may be a fiber that (upon exposure to a predetermined temperature at or above a shrinkage initiating temperature of the material of the fiber) is capable of shrinking (and/or crimping, or further crimping) to a length (the longest linear dimension of the fiber) that is about 95% to about 50% of the initial length the thermally shrinkable (optionally pre-crimped) fiber measured at standard temperature (25°C) and pressure (1 atmosphere) ("STP"), such as a fiber that (upon exposure to a predetermined temperature at or above a shrinkage initiating temperature of the material of the fiber) is capable of shrinking (and/or crimping, or further crimping) to a length that is about 80% to about 60% of the initial length the thermally shrinkable fiber measured at STP. In some embodiments, the thermally shrinkable fiber is capable of shrinking (and/or crimping, or further crimping) to the extent indicated above and/or a maximum percent shrinkage without degrading.

In some embodiments, "(thermally) non-shrinkable crimped fibers" may be used in the methods of the present disclosure. The term "(thermally) non-shrinkable crimped fiber" refers to a crimped fiber having no thermal shrinkability, as well as a crimped fiber that has thermal shrinkability but does not substantially further crimp or substantially shrink (such as a hot air shrinkage of less than 5%) at or below the highest temperature to which the crimped fibers of the treatment fluid will be exposed. The term "shrinkage initiating temperature" refers to the temperature at which the thermally shrinkable fiber starts shrinking (relative to the length of the thermally shrinkable fiber measured at STP), such as the temperature at which the length of the thermally shrinkable fiber shrinks to a length that is about 95% of the initial length of the thermally shrinkable fiber measured at STP.

After the thermally shrinkable fiber has been exposed to a temperature at or above the shrinkage initiating temperature such that the thermally shrinkable fiber shrinks (and/or crimps, or further crimps) to about 95% or less of the initial length (the longest linear dimension of the fiber) of the fiber, the fiber may be referred to as a "shrunken crimped fiber", or simply as a "crimpled fiber." In some embodiments, the term "shrunken crimped fiber" refers to a fiber that has a percent shrinkage (with respect to the longest linear dimension of the fiber, that is, the length of the fiber) such that the fiber ends up no less than 50% of the length of the initial fiber, such as in a range of from 95% to 52% shrinkage, or in a range of from 80%) to 70%. In embodiments in which the fiber shrinks as a result of being exposed to a predetermined temperature, the term "percent shrinkage" may be defined as:

(fiber Iength_{(after shrinkage)} measured at T_x) ^

(fiber length_(before shrinkage) measured at STP) where Ti is the temperature that was used to obtain the shrunken fiber.

In some embodiments, the materials of the thermally shrinkable fiber to be crimped may be selected such that the shrinkage initiating temperature is in the range of from about 40°C to about 180°C, or in the range of from about 50°C to about 150°C. In some embodiments, prior to exposure to the shrinkage initiating temperature (which may be in a hot air environment or solution environment) the thermally shrinkable fibers have not been exposed to a temperature within 10°C of the shrinkage initiating temperature.

The crimped fibers (and crimped fibers formed in situ) thickness (diameter), density and/or concentration may be selected to be any suitable value that is effective form bulky fibrous flocks, such as with proppant, natural formation particulates and the like. For example, in some embodiments the crimped fiber concentration (such as a concentration in the range of from about 0.2 to about 2% by weight of proppant, or a concentration in the range of from about 0.3 to about 1.5% by weight of proppant, or a concentration in the range of from about 0.4 to about 1 % by weight of proppant) may be selected to allow the crimped fibers to form bulky fibrous flocks.

A "wellbore" may be any type of well, including, a producing well, a non- producing well, an injection well, a fluid disposal well, an experimental well, an exploratory deep well, and the like. Wellbores may be vertical, horizontal, deviated some angle between vertical and horizontal, and combinations thereof, for example a vertical well with a non- vertical component.

The term "field" includes land-based (surface and sub-surface) and sub-seabed applications. The term "oilfield," as used herein, includes hydrocarbon oil and gas reservoirs, and formations or portions of formations where hydrocarbon oil and gas are expected but may additionally contain other materials such as water, brine, or some other composition.

The methods of the present disclosure that comprise fracturing a subterranean formation, may include a composition containing a crimped fiber, such as a fiber may be thermally triggered to form a crimped fiber (upon exposure to a predetermined temperature at or above a shrinkage initiating temperature of the material of the fiber), in one or more of the treatment fluids, but otherwise use conventional fracturing techniques known in the art. The methods of the present disclosure may include introducing a treatment fluid comprising crimped fiber (and/or a fiber capable of being crimped on site or in situ) into a subterranean formation, such as during a hydraulic fracturing treatment for the creation of heterogeneities in proppant pack to improve well productivity, but otherwise use conventional heterogeneous proppant placement techniques known in the art, such as, for example, methodology for heterogeneous proppant placement described in, for example, in U.S. Pat. Nos. 7,451,812 and 7,581,590, U.S. Patent Application Publication Nos. 20080149329 and 20130105166, and in International Publication No. WO2009/005387, the disclosures of which are herein incorporated by reference in their entireties.

For example, in some embodiments, heterogeneous proppant placement within fractures of a subterranean formation may be provided by pumping alternate stages of proppant-laden (and crimped fiber-laden) and clean or proppant-free fluids. This may be accomplished by controlling the delivery of proppant (and crimped fibers) so that it is integrated into the fracturing fluid at the surface and thereby forms slugs to facilitate heterogeneous proppant placement within the fractures when introduced into the formation.

In some embodiments, such a fiber may be amorphous or may have an amorphous part or region, such as an amorphous part or region that allows for the fiber to crimp. The term "amorphous" refers, for example, to areas or regions of a material such as, for example, a polymeric region of the crimped fibers, characterized as having no molecular lattice structure and/or having a disordered or not well-defined spatial relationship between molecules, such as a mixture of polymer molecules that is disordered (e.g., where the spatial relationship between monomer units of adjacent polymer molecules is not uniform or fixed, as opposed to a crystalline polymer region). The term "semi-crystalline" refers, for example, to areas or regions of a material such as, for example, a polymeric region of the crimped fibers, that is characterized as having a structure that is partially amorphous and partially crystalline, but not completely one or the other. The term "crystalline " refers, for example, to areas or regions of a material such as, for example, a polymeric region of the crimped fibers, that is characterized as having a structure, which may be solid, with a regular, ordered arrangement of molecules, such as a regular ordered arrangement of polymer molecules were the spaces between monomer units of adjacent polymer molecules is uniform and/or fixed.

In some embodiments, the crimped fiber present in the treatment fluid may have any desired length, such as a crimped fiber length in the range of from about 3 mm to about 20 mm, or in the range of from about 3 mm to about 12 mm, or in the range of from about 3 mm to about 6 mm (i.e., the longest linear dimension, such as if they were stretched). In some embodiments, the plurality of crimped fibers present in the treatment fluid may have any desired average length, such as a crimped fiber average length in the range of from about 3 mm to about 12 mm, or in the range of from about 3 mm to about 10 mm, or in the range of from about 3 mm to about 6 mm. In some embodiments, a crimped fiber may have an average thickness

(diameter) in the range of from about 4 Cm to about 40 Cm, such as in the range of from about 6 U rn to about 20 Cm, or in the range of from about 6 Dm to about 12 Cm. In some embodiments, each of the crimped fibers of the plurality of crimped fibers present in a treatment fluid may have an average thickness (diameter) in the range of from about 6 Cm to about 20 Dm, or in the range of from about 6 Gm to about 12 Cm, or in the range of from about 6 I m to about 8 Gm. The crimped fibers may have an aspect ratio in the range of from about 75 to about 5000, or in the range of from about 150 to about 2000, or in the range of from about 250 to about 1000. As used herein, the "aspect ratio" of a crimped fiber is defined as the ratio of its extended length (that is, its longest dimension) to its diameter (that is, its shortest dimension). In some embodiments, the crimped fibers may have an average density in the range of from about l.lg/cm³ to about 1.6 g/cm³, or in the range of from about 1.1

3 3

g/cm to about 1.3 g/cm . The crimped fibers may have an average density in the range of from about 1.0 g/cm³ to about 1.6 g/cm³, or in the range of from about 1.1 g/cm³ to about 1.4 g/cm³. In some embodiments, the crimped fibers, such as latent crimped fibers and/or thermally non-shrinkable crimped fibers, may be selected such that the density thereof is about two to about three times less than that of the particulate materials, such as proppants, employed; or the crimped fibers, such as latent crimped fibers and/or thermally non-shrinkable crimped fibers, may be selected to have an average density that is about two to about three times less than that of the particulate materials, such as proppants, employed.

In some embodiments, the crimped fibers, such as latent crimped fibers and/or thermally non-shrinkable crimped fibers, may be selected such that the density thereof matches that of the particulate materials, such as proppants, employed, or the crimped fibers, such as latent crimped fibers and/or thermally non-shrinkable crimped fibers, may be selected to have an average density that is within ±2% of the average density of the particulate materials, such as proppants, employed.

A wide range of fiber types (for any of the crimped fibers, such as latent crimped fibers and/or thermally non-shrinkable crimped fibers) may be used in the methods of the present disclosure. For example, in some embodiments, the crimped fiber, such as a latent crimped fiber and/or a thermally non-shrinkable crimped fiber, may be a monofilament crimped fiber, a bi-component crimped fiber with a core/sheath coaxial structure, a bi-component crimped fiber with a side-by-side structure, or any other multi-component crimped fiber configuration. Such crimped fibers can have a variety of cross-sectional shapes ranging from simple round cross-sectional areas, oval cross- sectional areas, trilobal cross-sectional areas, star shaped cross-sectional areas, rectangular cross-sectional areas, delta cross-sectional areas or the like. In some embodiments, the crimped fiber used in the methods of the present disclosure may be hooked on one or both ends (or made with such components or materials that the crimped fiber takes on such a geometry upon shrinking).

In some embodiments, the crimped fiber used in the methods of the present disclosure may be initially straight before being triggered to be a crimped fiber. In some embodiments, the crimped fiber used in the methods of the present disclosure may be an initially straight fiber that is made to assume a crimped geometry, such as a coiled geometry (which may be referred to as a spiral-shaped geometry or a helical-shaped geometry), as a result of a heating/shrinking process. In some embodiments, the crimped fiber used in the methods of the present disclosure may be of a composite structure. For example, more than one material may make up the monofilament crimped fiber, the sheath of a bi-component crimped fiber with a core/sheath coaxial structure, or the core of a bi-component crimped fiber with a core/sheath coaxial structure. In some embodiments, the materials from which the crimped fibers, such as latent crimped fibers and/or thermally non-shrinkable crimped fibers, are formed may not chemically interact with components of the well treatment fluids and may be stable in the subterranean environment. In some embodiments, the materials from which the crimped fibers, such as latent crimped fibers and/or thermally non-shrinkable crimped fibers, are formed may chemically interact with components of the well treatment fluids and may be degradable in the subterranean environment.

In embodiments, the outermost surface of the crimped fiber may be formed of an amorphous polymer. In some embodiments, the outermost surface of the crimped fiber may be formed of an amorphous polymer in a manner that the fiber is capable of crimping upon exposure to a predetermined temperature at or above the shrinking initiation temperature of the amorphous polymer, such as amorphous polylactic acid. Other suitable amorphous polymers that can be used in the methods of the present disclosure include, for example, polystyrene, poly(methyl methacrylate) and polyethylene terephthalate. Such polymers may serve as a portion of the sheath in crimped fibers having a core/sheath coaxial structure. In such embodiments, the core of the crimped fibers having a core/sheath coaxial structure may be a crystalline or semi- crystalline polymer, such as semi-crystalline polylactic acid. Other suitable crystalline or semi-crystalline polymers that are capable of shrinking and crimping upon exposure to a predetermined temperature at or above the shrinking initiation temperature of the polymer that can be used in the methods of the present disclosure include, for example, polyethylene, polypropylene and polyethylene terephthalate.

In some embodiments, the sheath and the core may be composed of the same polymer material (such as polylactic acid) where the core and the sheath have a different degree of crystallinity (the core being of a material that is more crystalline than the sheath) such that the fibers will form a crimp under a certain set of predetermined conditions.

In embodiments, an average diameter of the core of the crimped fibers having a core/sheath coaxial structure may be in the range of from about 1 μιη to about 38 μηι, such as in the range of from about 2 μπι to about 34 μπι. In embodiments, the sheath layer of the crimped fibers having a core/sheath coaxial structure may have a thickness in the range of from about 0.2 μηι to about 27 μηι, such as in the range of from about

0.7 μιη to about 18 μιτι.

The crimped fiber may be present in the treatment fluid in any amount that is effective to form bulky fibrous flocks, and/or in an amount effective to inhibit settling of the particulate material in the treatment fluid. In some embodiments, the crimped fibers are present in the treatment fluid in an amount in the range of from about 0.05% to about 0.5% by weight of the treatment fluid, or in the range of from about 0.1 % to about 0.3% by weight of the treatment fluid. In some embodiments, the crimped fiber may be present in the treatment fluid in an amount in the range of from about 0.1 % to about 4%o by weight of the particulate material, or in the range of from about 0.2% to about 2% by weight of the particulate material. In some embodiments, the crimped fiber amounts present in the bulky fibrous flocks may be in any suitable amounts effective for pillar formation, such as pillars to keep fracture propped open. In some embodiments, the ratio of fiber to proppant may be constant before and after pillar formation. In some embodiments, a concentration factor (i.e., ratio of proppant concentration in bulky fibrous flocks to proppant concentration in initial homogeneous slurry) may be in a range of from about 1.1 to about 3.3, such as in a range of from about 1.5 to about 2.5.

In embodiments, any desired particulate material may be used in the methods of the present disclosure, provided that it is compatible with the crimped fibers of the present disclosure, the formation, the fluid, and the desired results of the treatment operation. For example, particulate materials may include sized sand, synthetic inorganic proppants, coated proppants, uncoated proppants, resin coated proppants, and resin coated sand.

In embodiments where the particulate material is a proppant, the proppant used in the methods of the present disclosure may be any appropriate size to prop open the fracture and allow fluid to flow through the proppant pack, that is, in between and around the proppant (which may have been incorporated into a bulky fibrous flock) making up the pack. In some embodiments, the proppant may be selected based on desired characteristics, such as size range, crush strength, and insolubility. In embodiments, the proppant may have a sufficient compressive or crush resistance to prop the fracture open without being deformed or crushed by the closure stress of the fracture in the subterranean formation. In embodiments, the proppant may not dissolve in treatment fluids commonly encountered in a well.

Any proppant may be used, provided that it is compatible with the crimped fibers of the present disclosure, the formation, the fluid, and the desired results of the treatment operation. Such proppants may be natural or synthetic (including silicon dioxide, sand, nut hulls, walnut shells, bauxites, sintered bauxites, glass, natural materials, plastic beads, particulate metals, drill cuttings, ceramic materials, and any combination thereof), coated, or contain chemicals; more than one may be used sequentially or in mixtures of different sizes or different materials. The proppant may be resin coated, provided that the resin and any other chemicals in the coating are compatible with the other chemicals of the present disclosure, such as the crimped and/or crimped fibers of the present disclosure.

The proppant used may have an average particle size of from about 0.15 mm to about 2.39 mm (about 8 to about 100 U.S. mesh), or of from about 0.25 to about 0.43 mm (40/60 mesh), or of from about 0.43 to about 0.84 mm (20/40 mesh), or of from about 0.84 to about 1.19 mm (16/20), or of from about 0.84 to about 1.68 mm (12/20 mesh) and or of from about 0.84 to about 2.39 mm (8/20 mesh) sized materials. The proppant may be present in a slurry (which may be added to the treatment fluid) in a concentration of from about 0.12 to about 3 kg/L, or about 0.12 to about 1.44 kg/L (about 1 PPA to about 25 PPA, or from about 1 to about 12 PPA; PPA is "pounds proppant added" per gallon of liquid).

The methods of the present disclosure may include providing and/or forming bulky fibrous flocks comprising crimped fibers (and particulate material) during a treatment operation of a subterranean formation. In some embodiments, the present disclosure provides for formation of a bulky fibrous flock (including particulate materials and crimped fibers) that may be introduced into the target treatment zone. This bulky fibrous flock (including particulate materials and crimped fibers) may avoid particles/proppant from settling out of the treatment fluid.

In some embodiments, the methods of the present disclosure may include the formation of bulky fibrous flocks, which may be pumped into a wellbore with a well treatment fluid. In some embodiments, the treatment fluid may comprise a low viscosity carrier fluid having a low viscosity, proppant dispersed in the carrier fluid, and crimped fiber dispersed in the carrier fluid. As used herein, a "low viscosity" fluid refers to one having a viscosity less than 50 mPa-s at a shear rate of 170 s^"1 and a temperature of 25°C. In some embodiments, the crimped fiber is dispersed in the carrier fluid in an amount effective to inhibit settling of the proppant and to inhibit bridging. In some embodiments, the fraction of proppant settling after 90 minutes from the time the treatment fluid is formed by mixing each of the components together is less than 50%, such as less than 40%.

In some embodiments, an additional fibrous material may also be included in the treatment fluid. The additional fibrous material may be one or more member selected from natural fibers, synthetic organic fibers, glass fibers, ceramic fibers, carbon fibers, inorganic fibers, metal fibers, and a coated form of any of the above fibers.

In some embodiments, the crimped fibers may be pumped with a particulate material, such as proppant, such that the crimped fibers are uniformly mixed with the particulate material. In some embodiments, a dispersion of the crimped fibers and the proppant, which may be in the form of bulky fibrous flocks, may be introduced, such as by pumping, into the subterranean formation. The terms "dispersion" and "dispersed" refer, for example, to a substantially uniform distribution of components and/or bulky fibrous flocks (such as crimped fiber and particulate material) in a mixture. In some embodiments, a dispersed phase of one or more fibers, comprising crimped fibers, and particulate material may be formed at the surface. An action or event occurring "at the surface" refers, for example, to an action or event that happens above ground, that is, not at an underground location, such as within the wellbore or within the subterranean formation. In some embodiments, the crimped fibers may be mixed and dispersed throughout the entire batch of proppant to be pumped into the wellbore during the treatment operation. This may occur by adding the crimped fibers to the proppant before it is mixed with the treatment fluid, adding the crimped fibers to the treatment fluid before it is mixed with the proppant, or by adding a slurry of crimped fibers at some other stage, such either before the slurry is pumped downhole, or at a location downhole.

In some embodiments, the methods of the present disclosure may include the following actions, in any order: placing a treatment fluid including crimped fibers and a particulate material into a subterranean formation via a wellbore; mixing the treatment fluid to form an association, such as a mechanical association, covalent association and/or non-covalent association, of the crimped fibers with the particulate material, wherein the crimped fibers optionally form an association, such as a mechanical association, covalent association and/or non-covalent association, with one or more particulate materials to form bulky fibrous flocks. The terms "placing" or "placed" refer to the addition of a treatment fluid to a subterranean formation by any suitable means and, unless stated otherwise, do not imply any order by which the actions occur. The term "introduced" refers when used in connection with the addition of a treatment fluid to a subterranean formation may imply an order of accomplishing the recited actions, if not stated otherwise.

As used herein, the phrase "mixing the treatment fluid to form a mechanical association of the crimped fibers with the particulate material," refers to any action that is sufficient to initiate the formation of a mechanical association of the crimped fibers with the particulate material. The mechanical associations may include, for example, physical interactions and/or tangling. In some embodiments, such mechanical associations may occur to the extent that the resulting crimped fiber may form a 3D network of tangled crimped fibers with proppant particles dispersed between the crimped fibers, such as a 3D network of tangled crimped fibers with proppant particles dispersed between the crimped fibers, which may be referred to as a bulky fibrous flock.

In some embodiments, the association may be a non-covalent (and/or covalent) association (which may also include one or more physical or mechanical associations), in which one or more covalent bonds and/or one or more non-covalent bonds (such as an ionic bond, hydrogen bond or van der Waals forces) between the crimped fibers and a particulate material, such as a proppant or coated proppant, arise to form a bulky fibrous flock.

In some embodiments, the slurry of proppant and crimped fibers may be pumped into the wellbore during a portion of the treatment operation, for example, as the last about 5 to about 25% of the proppant is placed into the fracture, such as to control flowback without using vast amounts of crimped fibers. Such a slug may also be pumped into the wellbore at other stages, for example, to provide an absorbed scale inhibitor to be pumped to the front of the fracture.

In some embodiments, small slugs of a slurry of proppant and crimped fibers may be pumped in between slugs of slurry of proppant, or small slugs of a slurry of crimped fibers may be pumped between slugs of a proppant slurry. Such a series of stages may be used to control flow dynamics down the fracture, for example, by providing more plugflow-like behavior. Pumping of small slugs of slurry of crimped fibers as the tail-in is an example of this type of procedure in a treatment operation. In embodiments, a slurry of a mixture of proppant and crimped fibers may be used for any desired reason in the entire range of reservoir applications, such as from fracturing to sand control, frac-and-sand-pack and/or high permeability stimulation. For example, the methods of the present disclosure may be used in fluid loss applications.

As indicated above, the treatment fluid carrying the crimped fibers may be any well treatment fluid, such as a fluid loss control pill, a water control treatment fluid, a scale inhibition treatment fluid, a fracturing fluid, a gravel packing fluid, a drilling fluid, and a drill-in fluid. The carrier solvent (or carrier fluid) for the treatment fluid may be a pure solvent or a mixture. Suitable solvents for use with the methods of the present disclosure, such as for forming the treatment fluids disclosed herein, may be aqueous or organic based. Aqueous solvents may include at least one of fresh water, sea water, brine, mixtures of water and water-soluble organic compounds and mixtures thereof. Organic solvents may include any organic solvent that is able to dissolve or suspend the various components, such as the chemical entities and/or components of the treatment fluid. Suitable organic solvents may include, for example, alcohols, glycols, esters, ketones, nitrites, amides, amines, cyclic ethers, glycol ethers, acetone, acetonitrile, 1- butanol, 2-butanol, 2-butanone, t-butyl alcohol, cyclohexane, diethyl ether, diethylene glycol, diethylene glycol dimethyl ether, 1,2-dimethoxy-ethane (DME), dimethylether, dibutylether, dimethyl sulfoxide (DMSO), dioxane, ethanol, ethyl acetate, ethylene glycol, glycerin, heptanes, hexamethylphosphorous triamide (HMPT), hexane, methanol, methyl t-butyl ether (MTBE), N-methyl-2-pyrrolidinone (NMP), nitromethane, pentane , petroleum ether (ligroine), 1-propanol, 2-propanol, pyridine, tetrahydrofuran (THF), toluene, triethyl amine, o-xylene, m-xylene, p-xylene, ethylene glycol monobutyl ether, polyglycol ethers, pyrrolidones, N-(alkyl or cycloalkyl)-2- pyrrolidones, N-alkyl piperidones, N, N-dialkyl alkanolamides, Ν,Ν,Ν',Ν'-tetra alkyl ureas, dialkylsulfoxides, pyridines, hexaalkylphosphoric triamides, l,3-dimethyl-2- imidazolidinone, nitroalkanes, nitro-compounds of aromatic hydrocarbons, sulfolanes, butyrolactones, alkylene carbonates, alkyl carbonates, N-(alkyl or cycloalkyl)-2- pyrrolidones, pyridine and alkylpyridines, diethylether, dimethoxyethane, methyl formate, ethyl formate, methyl propionate, acetonitrile, benzonitrile, dimethylformamide, N-methylpyrrolidone, ethylene carbonate, dimethyl carbonate, propylene carbonate, diethyl carbonate, ethylmethyl carbonate, dibutyl carbonate, lactones, nitromethane, nitrobenzene sulfones, tetrahydrofuran, dioxane, dioxolane, methyltetrahydrofuran, dimethylsulfone, tetramethylene sulfone, diesel oil, kerosene, paraffinic oil, crude oil, liquefied petroleum gas (LPG), mineral oil, biodiesel, vegetable oil, animal oil, aromatic petroleum cuts, terpenes, mixtures thereof.

In some embodiments, the carrier fluid may be a low viscosity fluid, such as slickwater, which may or may not contain a viscosifying agent, and a sufficient amount of a friction reducing agent, such as, for example, to minimize tubular friction pressures. In some embodiments, treatment fluids comprising a slickwater carrier fluid may have a viscosity that is slightly higher than unadulterated fresh water or brine.

In some embodiments, the treatment fluid may comprise a linear gel (such as, for example, the carrier fluid) or a linear gel system. Suitable linear gel systems may contain carbohydrate polymers such as guar, hydroxyethylcellulose, hydroxyethyl guar, hydroxypropyl guar, and hydroxypropylcellulose. Such linear gel polymers may be added in any desirable amount, such as at about 10 to about 50 pounds of polymer per 1000 gallons of linear gel fluid.

While the treatment fluids of the present disclosure are described herein as comprising the above-mentioned components, it should be understood that the treatment fluids of the present disclosure may optionally comprise other chemically different materials. In embodiments, the treatment fluid may further comprise stabilizing agents, surfactants, diverting agents, or other additives. Additionally, a treatment fluid may comprise a mixture of various crosslinking agents, and/or other additives, such as fibers or fillers, provided that the other components chosen for the mixture are compatible with the intended use of the treatment fluid. Furthermore, the treatment fluid may comprise buffers, pH control agents, and various other additives added to promote the stability or the functionality of the treatment fluid. The components of the treatment fluid may be selected such that they may or may not react with the subterranean formation that is to be treated.

In this regard, the treatment fluid may include components independently selected from any solids, liquids, gases, and combinations thereof, such as slurries, gas- saturated or non-gas-saturated liquids, mixtures of two or more miscible or immiscible liquids, and the like, as long as such additional components allow for the precipitation of the chemical entity and/or reaction product thereof upon exposure to the precipitation triggering event. For example, the treatment fluid may comprise organic chemicals, inorganic chemicals, and any combinations thereof. Organic chemicals may be monomeric, oligomeric, polymeric, crosslinked, and combinations, while polymers may be thermoplastic, thermosetting, moisture setting, elastomeric, and the like. Inorganic chemicals may be metals, alkaline and alkaline earth chemicals, minerals, and the like. Stabilizing agents can be added to slow the degradation of the a bulky fibrous flock after its formation. Typical stabilizing agents may include buffering agents, such as agents capable of buffering at pH of about 8.0 or greater (such as water-soluble bicarbonate salts, carbonate salts, phosphate salts, or mixtures thereof, among others); and chelating agents (such as ethylenediaminetetraacetic acid (EDTA), nitrilotriacetic acid (NT A), or diethylenetriaminepentaacetic acid (DTP A), hydroxyethylethylenediaminetriacetic acid (HEDTA), or hydroxyethyliminodiacetic acid (HEIDA), among others). Buffering agents may be added to the treatment fluid in an amount of at least about 0.05 wt%, such as from about 0.05 wt% to about 10 wt%, and from about 0.1 wt% to about 2 wt%, based upon the total weight of the treatment fluid. Chelating agents may be added to the treatment fluid in an amount of at least about 0.75 mole per mole of metal ions expected to be encountered in the downhole environment, such as at least about 0.9 mole per mole of metal ions, based upon the total weight of the treatment fluid.

In embodiments, the treatment fluid may be driven into a wellbore by a pumping system that pumps one or more treatment fluids into the wellbore. The pumping systems may include mixing or combining devices, wherein various components, such as fluids, solids, and/or gases maybe mixed or combined prior to being pumped into the wellbore. The mixing or combining device may be controlled in a number of ways, including, but not limited to, using data obtained either downhole from the wellbore, surface data, or some combination thereof.

Fracturing a subterranean formation may include introducing hundreds of thousands of gallons of treatment fluid, such as a fracturing fluid, into the wellbore. In some embodiments a frac pump may be used for hydraulic fracturing. A frac pump is a high-pressure, high-volume pump, such as a positive-displacement reciprocating pump. In embodiments, a treatment fluid comprising the crimped fibers may be introduced by using a frac pump, such that the treatment fluid (such as a fracturing fluid) may be pumped down into the wellbore at high rates and pressures, for example, at a flow rate in excess of about 20 barrels per minute (about 4,200 U.S. gallons per minute) at a pressure in excess of about 2,500 pounds per square inch ("psi"). In some embodiments, the pump rate and pressure of the treatment fluid (such as a fracturing fluid) may be even higher, for example, at flow rates in excess of about 100 barrels per minute and pressures in excess of about 10,000 psi may be used.

The foregoing is further illustrated by reference to the following examples, which are presented for purposes of illustration and are not intended to limit the scope of the present disclosure.

EXAMPLES A large slot manifold was manufactured (as discussed below) was used to simulate flow of a treatment fluid inside a narrow fracture and analyze bridging behavior and pillar formation.

The large slot manifold apparatus contained two parallel glass panes with a length of 3 meters (m), height of 0.5 m and width of 1 to 5 millimeters (mm) for visualization of the fluid and proppant at a flow rate up to 50 Liters/minute (L/min). The large slot manifold tests were run using a slickwater or linear gel as a carrier fluid. Slickwater was prepared from a concentrated solution of friction reducer at 1 mL/L (1 gallon per thousand gallons of water (gpt)) and a concentrated solution of clay stabilizer at 2 mL/L (2 gpt). Linear gel was prepared from a guar powder at 2.4 grams/Liter (g/L) loading (20 pounds per thousand gallons of water (ppt).

Fiber concentration was varied from 0.5 to 4.8 g/L based on the total volume of the carrier fluid (from 4 to 40 pounds per thousand gallons of carrier fluid). Proppant concentration was varied from 0.03 to 1 kg/L based on the total volume of the carrier fluid (from 0.25 to 8.3 pounds proppant added per gallon of carrier fluid). The testing procedure included the following: (1) preparation of the carrier fluid, either slickwater or linear gel; (2) adding of a predetermined amount of crimped fiber to the carrier fluid, and dispersing the fiber in the carrier fluid using an overhead mixer; (3) adding of a predetermined amount of proppant to the mixture of fiber in carrier fluid, and dispersing the proppant in the slurry with an overhead mixer; (4) pumping of the resultant treatment fluid into the large slot manifold apparatus at a flow rate up to 50

L/min, and observing (i) the fluid flow inside the narrow slot, (ii) any bridging of fibers, and (iii) settling of proppant; (5) stopping the pumping, and observing the slurry disintegration and pillars formation; and (6) observing and assessing the proppant settling in time.

Bridging was characterized by the observation of an increase of pressure inside the slot (up to 60 psi) and observation of proppant-fiber slugs jammed inside the slot between the panes. Settling was characterized by observing an increased level of proppant settled at the bottom of the slot.

Proppant pillars were formed in slickwater with crimped fiber. Proppant pillars were formed in a slot (2 mm width; the slot size was made to be 3 m x 0.5 m x 2 mm (length x height x width)) of the above described apparatus in a treatment fluid composed of slickwater (as a carrier fluid) with 3 g/L (25 ppt) of crimped fiber of 9.5 micron diameter and 6 mm length, and 0.2 kg/L (1.7 ppa) of 40/70 API sand. The fluid viscosity was 1.5 mPa-s at 25°C. A linear fluid velocity of 30 cm/sec was employed. Both proppant and fiber materials were concentrated inside the pillars, and the channels between the pillars were clear from particulates. The same heterogeneous distribution (as described above) was achieved for 100 mesh sand in presence of crimped fiber (as described above), as shown in FIG. 1A. Even after 12 hours, the pillars did not settle down, thereby maximizing propped fracture height.

The slot area of 100 mm x 100 mm (IB of FIG. 1A) was taken to assess the distribution of sand concentration (see FIGS. IB and 1C). FIG. 1C illustrates the distribution of sand concentration on a slot area of 100 mm x 100 mm size after a test with 4.8 g/L (40 ppt) crimped fiber and 0.2 kg/L (1.7 ppa) 100 mesh API sand in slickwater in large slot manifold of 1 mm width. The vertical axis of FIG. 1 C is the estimated sand concentration in ppa (pounds proppant added per gallon of carrier fluid) calculated via gray scale level of the image. The horizontal axes represent coordinates in mm corresponding to the position on the slot area.

The results of the experiments indicate that after slurry disintegration and pillars formation, the average concentration of sand in the pillars is at least twice as high relative to the homogeneous slurry. Moreover, as shown in FIG. 1C, there is a gradient of sand concentration inside the pillars from 0 to 1.44 kg/L (from 0 to 12 ppa). Such heterogeneous placement of proppant and open channels result in enhanced conductivity of a propped fracture.

Similar heterogeneous distribution and pillar formation to that observed for the above slickwater carrier fluid experiments was observed in linear guar gel in presence of crimped fiber, as shown in FIG. 2 (where the slot size was 3 m x 0.5 m x 2 mm (length x height x width), linear guar gel was as a carrier fluid, guar was present at 2.4 g/L (20 ppt), the fluid viscosity was 13.5 mPa-s at 25°C, the crimped fiber was present at 2.2 g/L (18 ppt), 40/70 API sand was used at a concentration of 0.4 kg/L (3.5 ppa), and a linear fluid velocity of 30 cm/sec was employed; similar to the above experiment and the experiments described below, the photos were taken immediately after pumping was stopped.

As shown in FIG. 3 (where the slot size was 3 m x 0.5 m x 2 mm (length x height x width), slickwater was used as a carrier fluid, the fluid viscosity was 1.5 mPa-s at 25°C, no fiber was present, 40/70 API sand was used at a concentration of 0.2 kg/L (1.7 ppa), and a linear fluid velocity of 65 cm/sec was employed), substantial proppant settling occurred during the pumping of proppant in slickwater media without any fiber additive (that is, no straight or crimped fiber), thereby decreasing propped fracture height and propped fracture length.

As shown in FIG. 4 (where the slot size was 3 m x 0.5 m x 2 mm (length x height x width), slickwater was used as a carrier fluid, the fluid viscosity was 1.5 mPa-s at 25°C, straight fiber was present at a concentration of 2.4 g/L (20 ppt), 40/70 API sand was used at a concentration of 0.2 kg/L (1.7 ppa), and a linear fluid velocity of 30 cm/sec was employed, uncrimped (straight) fiber can be used to transport proppant over the longer distance without the extent of settling that occurs when no fiber is present. However, there are no proppant pillars formed in the tests where straight fibers were employed (as opposed to experiments where crimped fibers were used). Thus, a treatment fluid containing crimped fiber achieved the highest propped area as compared to straight fiber or conventional fluid without any fiber additive.

Although the preceding description has been described herein with reference to particular means, materials and embodiments, it is not intended to be limited to the particulars disclosed herein; rather, it extends to all functionally equivalent structures, methods and uses, such as are within the scope of the appended claims. Furthermore, although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from the disclosure of HETEROGENEOUS PROPPANT PLACEMENT. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses arc intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures.

Claims

WHAT IS CLAIMED IS:

1. A method for treating a subterranean formation comprising:

preparing a treatment fluid including a carrier fluid and a plurality of bulky fibrous flocks, wherein at least some of the bulky fibrous flocks comprise a crimped fiber and a particulate material; and

introducing the treatment fluid into a subterranean formation via a wellbore.

2. The method of any preceding claim, wherein the crimped fiber has from about 1 to about 10 crimps/cm of length, a crimp angle from about 45 to about 160 degrees, an average extended length of from about 3 to about 12 mm, and an average diameter of from about 3 to about 40 microns.

3. The method of any preceding claim, wherein the crimped fiber is present in the treatment fluid in an amount in the range of from about 4 to about 40 lbm/l,000gal, and the particulate material is present in the treatment fluid in an amount in the range of from about 0.25 to about 10 pounds of proppant added per gallon of carrier fluid.

4. The method of any preceding claim, wherein the treatment fluid has a viscosity measured at a shear rate 170 s^"1 and a temperature 25°C from about 1 to about 50 mPa-s.

5. The method of preceding claim, wherein the treatment fluid is introduced into the subterranean formation during a hydraulic fracturing treatment, and heterogeneous proppant placement is accomplished during the hydraulic fracturing treatment.

6. The method of any preceding claim, wherein the crimped fiber is present in the treatment fluid in an amount effective to inhibit settling of the particulate material in the treatment fluid.

7. The method of any preceding claim, wherein the crimped fiber is present in the treatment fluid in an amount in the range of from about 0.2% to about 2% by weight of the particulate material.

8. The method of any preceding claim, wherein the crimped fiber is present in the carrier fluid in an amount that is insufficient to cause bridging.

9. The method of any preceding claim, wherein the subterranean formation is a shale formation.

10. The method of claim 1 , wherein the carrier fluid is slickwater or a linear gel.

1 1. The method of any preceding claim, wherein at least a portion of the crimped fiber is bi-component crimped fibers with a core/sheath coaxial structure, where the sheath is an amorphous polymer and the core is selected from a crystalline polymer or a semi-crystalline polymer.

12. The method of any preceding claim, wherein at least a portion of the crimped fiber is non-degradable.

13. The method of any preceding claim, wherein at least a portion of the crimped fiber is degradable.

14. The method of any preceding claim, wherein the bulky fibrous flocks of the plurality of bulky fibrous flocks are present in an amount effective for pillar formation.

15. The method of any preceding claim, wherein at least a portion of the particulate material is proppant.