Methods for Pillar Placement in Fracturing

Abstract

Methods for placing proppant aggregates using a diverting fluid comprising a diverting agent and a packing fluid. Proppant aggregates are introduced into a fracture that is fluidically connected to a wellbore through a plurality of perforations. Thereafter, a diverting diverting fluid is introduced into the wellbore to seal some perforations and leave at least one unsealed perforation. Once some perforations are sealed, a packing fluid is introduced into the fracture through the at least one unsealed perforation, thereby forming the proppant aggregates to move together and form a proppant bed within the fracture.

Description

BACKGROUND

The present invention relates to fracturing operations and, more particularly, to compositions and methods related to proppant pillar placement using diverting agents.

In a typical hydraulic fracturing operation, a proppant (sometimes referred to as a “propping agent”) is suspended in a portion of a fracturing fluid, and may then be transported and deposited in fractures within the subterranean formation. Proppants are traditionally particulates that collectively form proppant packs that can serve as a physical barrier to prevent the fractures from fully closing so that conductive channels are formed around the proppants through which produced hydrocarbons can flow. Thus, the degree of success of a fracturing operation depends, at least in part, upon the resultant fracture porosity and conductivity once the fracturing operation is stopped and production is begun. Typical hydraulic fracturing operations place a large volume of proppants into a fracture to form a relatively homogeneous proppant pack within the fracture. The porosity of the resultant packed, propped fracture is then at least partially related to the interconnected interstitial spaces between the abutting proppant particulates.

An alternative fracturing approach (i.e., heterogeneous proppant placement) involves placing a significantly reduced volume of proppants in a fracture to create a propped fracture having high porosity, fracture permeability, and/or conductivity. The reduced volume of proppants may be consolidated, in certain conditions, to form individual aggregate structures (e.g., proppant pillars) that can be used to abut the fracture. As used herein, the term “proppant pillar” and related terms such as “proppant aggregate” refer to a coherent cluster of proppants that remains a coherent body that may be used to prop a fracture. Proppant aggregates generally do not become dispersed into smaller bodies without application of significant shear. A proppant aggregate may be formed, for example, by coating individual proppants with an adhesive substance such that the proppants have a tendency to create clusters or aggregates. As used herein, the term “proppants” refers to the various individual proppant forms described in this disclosure.

Heterogeneous proppant placement typically involves pumping different types of slurries or fluids in discrete intervals. This can provide higher conductivity fractures than those obtained from conventional treatments, and may increase fracture porosity by forming a heterogeneous proppant pack, that is, a random (or heterogeneous) distribution of proppant pillars. The proppant pillars should have sufficient strength to hold the fracture partially open under closure stress. The open space between proppant pillars forms a network of interconnected open channels, available for the flow of fluids into the wellbore. This results in a significant increase of the effective hydraulic conductivity and porosity of the overall fracture.

However, there are certain technical challenges that limit the usefulness of proppant pillars in fracturing operations. For example, proppant settling can be a significant problem for heterogeneous proppant placement operations that use reduced volumes of proppants. Thus, settling can lead to fracture closure, particularly at or near the top portion of a fracture, which can significantly lower the conductivity and porosity of the propped fracture.

SUMMARY OF THE INVENTION

The present invention relates to fracturing operations and, more particularly, to compositions and methods related to proppant pillar placement using diverting agents.

In some embodiments, the present invention provides a method comprising: providing proppant aggregates; a diverting fluid comprising a diverting agent; and a packing fluid; introducing the proppant aggregates into a fracture that is fluidically connected to a wellbore through a plurality of perforations; introducing the diverting fluid into the wellbore thereby forming at least one sealed perforation and leaving at least one unsealed perforation; and introducing the packing fluid into the fracture through the at least one unsealed perforation thereby allowing the proppant aggregates to form a proppant bed within the fracture.

In other embodiments, the present invention provides a method comprising: providing proppant aggregates; a diverting fluid comprising a degradable diverting agent; and a packing fluid; introducing the proppant aggregates into a fracture that is fluidically connected to a wellbore through a plurality of perforations; introducing the diverting fluid into the wellbore thereby forming at least one sealed perforation and leaving at least one unsealed perforation; introducing the packing fluid into the fracture through the at least one unsealed perforation thereby allowing the proppant aggregates to form a proppant bed within the fracture; and allowing the degradable diverting agent to degrade thereby unsealing the at least one perforation.

The features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of the preferred embodiments that follows.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of the present invention, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, as will occur to those skilled in the art and having the benefit of this disclosure.

FIGS. 1A-1C schematically illustrate aspects of proppant pillar placement according to one or more embodiments.

DETAILED DESCRIPTION

The present invention relates to fracturing operations and, more particularly, to compositions and methods related to proppant pillar placement using diverting agents.

While the various embodiments of the present invention are discussed in detail below, it should be appreciated that the present invention provides many applicable inventive concepts which can be embodied in a wide variety of specific contexts. The specific embodiments discussed herein are merely illustrative of specific ways to make and use the invention, and do not delimit the scope of the present invention. To facilitate a better understanding of the present invention, the following examples of preferred or representative embodiments are given.

The present invention provides compositions and methods for selectively diverting fluids during a fracturing operation, which can reduce the settling of particulates (e.g., proppants) within a fracture. As a result, proppants including aggregates of proppants can be distributed more evenly within the fracture, particularly at or near the top portion of a fracture. When a fracture closes on a more evenly distributed aggregates of proppants, a higher porosity propped fracture can be formed.

Referring to FIG. 1A, proppant aggregates 100 suspended in fluid have been transported into fracture 110 through perforations 120 (a-d) on a casing or liner 130 that spans the wellbore, including zones containing the fracture 110. Perforations can be formed by any suitable means including, but not limited to, jet perforating guns equipped with shaped explosive charges, abrasive jetting, and high-pressure fluid jetting. Over time, proppant aggregates can settle due to factors such as gravitational force (prior to closing of the fracture), which can lead to partial or possibly full closure of the upper portion of the fracture, which can significantly compromise the capacity to recover fluids. As used herein, “settling” and related terms (e.g., “sagging”) refer to the phenomena of suspended particles falling in liquid.

Referring to FIG. 1B, a degradable diverting agent has been used to selectively seal one or more perforations 120a, 120b, and 120c, while leaving open 120d to hydraulically connect the fracture 110 and the inside of casing 130. As illustrated, a majority of the perforations 120 on casing/liner 130 have been sealed by the diverting agent so that only a single perforation 120d remains unsealed. It should be understood that the exact number of sealed and unsealed perforations, including the exact ratio of sealed to unsealed perforations, may be varied without departing from the scope of the present invention. In some embodiments, more that one perforation may be left unsealed. The unsealed perforations, such as 120d in FIG. 1B, are typically located at or near the bottom portion 140 of the fracture 110 while the sealed perforations are typically located above the unsealed perforations. However, other configurations may be compatible with the one or more embodiments described herein. Moreover, while it may be desirable that the diverting agent fully seals the targeted perforations so that fluidic communication between the fracture and casing/liner is completely cut off, it should be understood that the present invention can be practiced, in some embodiments, even when the targeted perforations are partially sealed.

Next, referring to FIG. 1C, a packing fluid according to one or more embodiments comprising relatively high volumes of proppants 100 is introduced into the fracture 110 through the unsealed perforation(s) 120d such that a homogeneous proppant bed 150 is formed at the bottom portion 140 of the fracture 110. The homogeneous proppant bed 150 prevents proppant aggregates 100 from settling to the bottom portion 140. Consequently, free particulates or aggregates of particulates suspended within the fracture are generally displaced towards the top portion of the fracture 110. Once the fracture closes on the proppant aggregates and the proppant bed below, a high porosity fracture is formed.

Whenever the terms “bottom” or “top” are used to describe the orientation of the height of a fracture, “bottom” typically refers to the portion of the fracture that the proppants generally settle towards while “top” may be determined by its orientation in relation to the above-defined “bottom.”

Once the proppant aggregates and proppant bed are in place, the diverting agents used to seal the perforations 120 may be degraded or otherwise removed. Hydrocarbons can then be recovered through the formed high porosity fracture and into the production casing through the unsealed perforations. In some embodiments, the diverting agents should degrade or be removed before the onsite of production. In some embodiments, non-degradable material may be removed during flowback.

Some embodiments provide methods comprising: providing proppant aggregates; a diverting fluid comprising a diverting agent; and a packing fluid; introducing the proppant aggregates into a fracture that is fluidically connected to a wellbore through a plurality of perforations; introducing the diverting fluid into the wellbore thereby forming at least one sealed perforation and leaving at least one unsealed perforation; and introducing the packing fluid into the fracture through the at least one unsealed perforation thereby allowing the proppant aggregates to form a proppant bed within the fracture.

The diverting fluids of the present invention may be introduced in a subterranean formation, such that the diverting fluids carry a diverting agent downhole where the diverting agent can seal targeted perforations. In some embodiments, a majority of perforations are sealed. In some embodiments, at least 60% of the perforations are sealed. In some embodiments, at least 75% of the perforations are sealed. In some embodiments, at least 90% of the perforations are sealed.

In some embodiments, the diverting fluid of the present invention comprises a base fluid and a diverting agent. A base fluid will typically include an aqueous-based fluid, but may include any fluid that can carry the diverting agent to the targeted perforations. Suitable aqueous-based fluids may include, but are not limited to, fresh water, saltwater (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated salt water), seawater, and any combination thereof. Oil-based fluids may also be used. An example of a suitable oil-based fluid is described in U.S. Pat. Nos. 8,119,575 and 4,316,810, the entire disclosures of which are hereby incorporated by reference.

According to some embodiments, diverting agents of the present invention can be used to selectively seal one or more perforations that fluidically connect a fracture and a wellbore while leaving one or more, preferably lower, perforations unsealed. After the diverting agent has sealed targeted or desired perforations, subsequent treatment fluids introduced into the subterranean formation can be diverted to the remaining unsealed perforations. Generally, diverting agents are introduced into a subterranean formation at matrix flow rates;

that is, flow rates and pressures that are below the rate/pressure sufficient to create or extend fractures in that portion of the subterranean formation. In other embodiments, the diverting agents are introduced into the subterranean formation at a rate/pressure sufficient to create new fractures.

In order to selectively to seal the targeted perforations, diverting agents should be added in a predetermined amount. Several factors may determine the exact amount of diverting agent to be used. These factors include, but are not limited to, the diverting agent selected, the number of targeted perforations, the size of the perforations, and the like. Generally, the diverting agent will initially seal perforations formed closer to the top of the fracture and then later seal perforations located further toward the bottom of the fracture. Ideally, the diverting agent should be added in an amount sufficient to seal all of the targeted perforations.

In some embodiments, the diverting agent may be degradable such that it forms a non-permanent seal. Suitable examples of diverting agents include, but are not limited to, polysaccharides, chitins, chitosans, proteins, orthoesters, aliphatic polyesters, poly(glycolides), poly(lactides), poly(c-caprolactones), poly(hydroxybutyrates), polyanhyrides, aliphatic polycarbonates, poly(orthoesters), poly(amino acids), poly(ethylene oxides), polyphosphazenes, derivatives thereof, and combinations thereof. The diverting agent may also be a degradable polymer gel blobs or chunks (described in U.S. Published Patent Application 2011/0240297, and U.S. Pat. No. 5,680,900, the entire disclosures of which are hereby incorporated by reference). The diverting agent may also be a dehydrated salt. Suitable examples of dehydrated salts that may be used in conjunction with the present invention include, but are not limited to, particulate solid anhydrous borate materials. Specific examples of particulate solid anhydrous borate materials that may be used include but are not limited to anhydrous sodium tetraborate (also known as anhydrous borax), and anhydrous boric acid. Such anhydrous borate materials are only slightly soluble in water. However, with time and heat in a subterranean environment, the anhydrous borate materials react with the surrounding aqueous fluid and become hydrated. The resulting hydrated borate materials are highly soluble in water as compared to anhydrous borate materials and as a result degrade in the aqueous fluid. Regardless of the type of agent chosen, the diverting agent may be present in an amount of about 0.1% to about 20% by weight of the diverting fluid.

The diverting agent may be of any physical shape including, but not limited to, fiber, oval, spherical, platelet, and any combination thereof. It is preferred that the diverting agent be in the form of a fiber or platelet. The diverting agents may be of any size and shape combination. The size and shape combination may depend upon, among other factors, the composition of the subterranean formation, the chemical composition of formation fluids, the flow rate of fluids present in the formation, the effective porosity and/or permeability of the subterranean formation, pore throat size and distribution, and the like. It is within the ability of one skilled in the art, with the benefit of this disclosure, to determine the size and shape of diverting agents to include in the methods of the present invention to achieve the desired results.

According to some embodiments, a packing fluid comprising proppants may be introduced into a subterranean formation to form a relatively homogeneous proppant pack at the bottom of a fracture. The packing fluid may be introduced after the targeted perforations have been sealed so that it can be diverted to the unsealed perforations. The packing fluid can transport the proppants into the fracture through the unsealed perforations where the proppants then settle to form a proppant pack. This proppant pack reduces the space through which the freely suspended proppant aggregates, above, can settle. The proppant pack may reduce settling of proppant aggregates, resulting in a more even distribution of proppant aggregates within the fracture (particularly near or at the top portion of the fracture). As such, the proppant aggregates may form more evenly distributed proppant pillars when the fracture closes, thus resulting in high porosity fractures and/or fewer fracture closures.

In some embodiments, the packing fluid of the present invention comprises a carrier fluid and proppants. In other embodiments, the packing fluid of the present invention comprises only a carrier fluid. The composition of the packing fluids may resemble commonly known fracturing fluids. The packing fluid may also include additional additives such as, but not limited to, gelling agents, crosslinking agents, gel breakers, any combinations thereof, and the like.

Proppant particulates suitable for use in the packing fluids of the present invention may be of any size and shape combination known in the art as suitable for use in a fracturing operation. In some embodiments, the proppants are engineered to be of a specific volume or size to carry out their desired function. In some embodiments of the present invention it may be desirable to use substantially non-spherical proppant particulates. Suitable substantially non-spherical proppant particulates may be cubic, polygonal, fibrous, or any other non-spherical shape. Such substantially non-spherical proppant particulates may be, for example, cubic-shaped, rectangular shaped, rod shaped, ellipse shaped, cone shaped, pyramid shaped, or cylinder shaped. That is, in embodiments wherein the proppant particulates are substantially non-spherical, the aspect ratio of the material may range such that the material is fibrous to such that it is cubic, octagonal, or any other configuration. Substantially non-spherical proppant particulates are generally sized such that the longest axis is from about 0.02 inches to about 0.3 inches in length. In other embodiments, the longest axis is from about 0.05 inches to about 0.2 inches in length. In one embodiment, the substantially non-spherical proppant particulates are cylindrical having an aspect ratio of about 1.5 to 1 and about 0.08 inches in diameter and about 0.12 inches in length. In another embodiment, the substantially non-spherical proppant particulates are cubic having sides about 0.08 inches in length. The use of substantially non-spherical proppant particulates may be desirable in some embodiments of the present invention because, among other things, they may provide a lower rate of settling when slurried into a fluid as is often done to transport proppant particulates to desired locations within subterranean formations. By so resisting settling, substantially non-spherical proppant particulates may provide improved proppant particulate distribution as compared to more spherical proppant particulates.

Proppants suitable for use in the present invention may comprise any material suitable for use in subterranean operations. Suitable materials for these particulates include, but are not limited to, sand, bauxite, ceramic materials, glass materials, polymer materials, polytetrafluoroethylene materials, nut shell pieces, cured resinous particulates comprising nut shell pieces, seed shell pieces, cured resinous particulates comprising seed shell pieces, fruit pit pieces, cured resinous particulates comprising fruit pit pieces, wood, composite particulates, and combinations thereof. Suitable composite particulates may comprise a binder and a filler material wherein suitable filler materials include silica, alumina, fumed carbon, carbon black, graphite, mica, titanium dioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash, hollow glass microspheres, solid glass, and combinations thereof. The mean particulate size generally may range from about 2 mesh to about 400 mesh on the U.S. Sieve Series; however, in certain circumstances, other mean particulate sizes may be desired and will be entirely suitable for practice of the present invention. In particular embodiments, preferred mean particulates size distribution ranges are one or more of 6/12, 8/16, 12/20, 16/30, 20/40, 30/50, 40/60, 40/70, or 50/70 mesh. 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 combinations thereof. Moreover, fibrous materials, that may or may not be used to bear the pressure of a closed fracture, may be included in certain embodiments of the present invention. In certain embodiments, the particulates may be present in the treatment fluids of the present invention in an amount in the range of from about 0.01 pounds per gallon (“ppg”) to about 30 ppg by volume of the treatment fluid, the exact value depending on the treatment fluid.

Some embodiments of the present provides methods comprising: providing proppant aggregates; a diverting fluid comprising a degradable diverting agent; and a packing fluid; introducing the proppant aggregates into a fracture that is fluidically connected to a wellbore through a plurality of perforations; introducing the diverting fluid into the wellbore thereby forming at least one sealed perforation and leaving at least one unsealed perforation; introducing the packing fluid into the fracture through the at least one unsealed perforation thereby allowing the proppant aggregates to form a proppant bed within the fracture; and allowing the degradable diverting agent to degrade thereby unsealing the at least one perforation.

According to some embodiments, proppant aggregates may be introduced into at least one fracture within a subterranean formation. The proppant aggregates may have any shape including, but not limited to, oval, spheroid, stringy mass, combinations thereof, and the like. As those of ordinary skill in the art will appreciate, the proppant aggregates may have any well-defined physical shape or may have an irregular geometry. In some embodiments, the proppant aggregates are substantially the same size. In other embodiments, the proppant aggregates have different sizes.

A variety of methods may be used to form proppant aggregates. Examples of suitable methods are described in U.S. Patent Publication No. 2006/0113078, filed on Dec. 1, 2004, the contents of which is hereby incorporated by reference to the extent not inconsistent with the present disclosure. In one example, to form proppant aggregates, a proppant slurry should be provided. Because the proppant slurry is used to form the proppant aggregates, the proppant aggregates may have substantially the same composition as the proppant slurry, namely both the proppant aggregates and the proppant slurry generally comprise a binding fluid and a filler material. A carrier fluid should also be provided.

As used herein, the term “binding fluid” refers to a fluid that confines the proppant aggregate, such that when the proppant aggregate is placed into a fracture or placed into a carrier fluid, the proppant aggregate remains a coherent body that does not generally become dispersed into smaller bodies without application of shear. In some embodiments, the binding fluids comprise a consolidating agent and an aqueous gel. Generally, the binding fluid should be immiscible or at least partially immiscible with the carrier fluid so that the proppant aggregates remains a coherent body when contacted by or combined with the carrier fluid. For example, in some embodiments, the proppant slurry may be used to form a plurality of proppant aggregates, which will be suspended in the carrier fluid. In these embodiments, the binding fluid should allow each of the proppant aggregates to remain a coherent body when suspended in the carrier fluid.

Suitable consolidating agents may include, but are not limited to, non-aqueous tackifying agents, aqueous tackifying agents, emulsified tackifying agents, silyl-modified polyamide compounds, resins, crosslinkable aqueous polymer compositions, polymerizable organic monomer compositions, consolidating agent emulsions, zeta-potential modifying aggregating compositions, and binders. Combinations and/or derivatives of these also may be suitable. Nonlimiting examples of suitable non-aqueous tackifying agents may be found in U.S. Pat. Nos. 5,853,048; 5,839,510; and 5,833,000 as well as U.S. Patent Application Publication Nos. 2007/0131425 and 2007/0131422 the relevant disclosures of which are herein incorporated by reference. Nonlimiting examples of suitable aqueous tackifying agents may be found in U.S. Pat. Nos. 5,249,627 and 4,670,501 as well as U.S. Patent Application Publication Nos. 2005/0277554 and 2005/0274517, the relevant disclosures of which are herein incorporated by reference. Nonlimiting examples of suitable crosslinkable aqueous polymer compositions may be found in U.S. Patent Application Publication Nos. 2010/0160187 and 2011/0030950 the relevant disclosures of which are herein incorporated by reference. Nonlimiting examples of suitable silyl-modified polyamide compounds may be found in U.S. Pat. No. 6,439,309 entitled the relevant disclosure of which is herein incorporated by reference. Nonlimiting examples of suitable resins may be found in U.S. Pat. Nos. 7,673,686; 7,153,575; 6,677,426; 6,582,819; 6,311,773; and 4,585,064 as well as U.S. Patent Application Publication Nos. 2010/0212898 and 2008/0006405, the relevant disclosures of which are herein incorporated by reference. Nonlimiting examples of suitable polymerizable organic monomer compositions may be found in U.S. Pat. Nos. 7,819,192, the relevant disclosure of which is herein incorporated by reference. Nonlimiting examples of suitable consolidating agent emulsions may be found in U.S. Patent Application Publication No. 2007/0289781 the relevant disclosure of which is herein incorporated by reference. Nonlimiting examples of suitable zeta-potential modifying aggregating compositions may be found in U.S. Pat. Nos. 7,956,017 and 7,392,847, the relevant disclosures of which are herein incorporated by reference. Nonlimiting examples of suitable binders may be found in U.S. Pat. Nos. 8,003,579; 7,825,074; and 6,287,639 as well as U.S. Patent Application Publication No. 2011/0039737, the relevant disclosures of which are herein incorporated by reference. It is within the ability of one skilled in the art, with the benefit of this disclosure, to determine the type and amount of consolidating agent to include in the methods of the present invention to achieve the desired results.

Suitable aqueous gels are generally comprised of water and one or more gelling agents. In certain embodiments of the present invention, the binding fluid is an aqueous gel 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, binding fluid, inter alia, allows the binding fluid to transport significant quantities of suspended filler material and allows the proppant slurry to remain a coherent mass. Furthermore, it is desired for the aqueous gel to maintain its viscosity after placement into the fracture in the subterranean formation. Accordingly, the components of the aqueous gel should be selected so that, when exposed to downhole conditions (e.g., temperature, pH, etc.), it does not experience a breakdown or deterioration of the gel structure nor do the proppant aggregates experience a breakdown or deterioration.

Generally, the filler material should form a stable aggregate with the binding fluid. Filler materials suitable for use in the present invention may comprise a variety of proppant materials suitable for use in subterranean operations, including, but not limited to, sand (such as beach sand, desert sand, or graded sand), bauxite; ceramic materials; glass materials (such as crushed, disposal glass material); polymer materials; Teflon™ materials; nut shell pieces; seed shell pieces; cured resinous particulates comprising nut shell pieces; cured resinous particulates comprising seed shell pieces; fruit pit pieces; cured resinous particulates comprising fruit pit pieces; wood; composite particulates, lightweight particulates, microsphere plastic beads, ceramic microspheres, glass microspheres, man-made fibers, cements (such as Portland cements), fly ash, carbon black powder, combinations thereof, and the like. Suitable composite materials may comprise a binder and a filler material wherein suitable filler materials include silica, alumina, fumed carbon, carbon black, graphite, mica, titanium dioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash, hollow glass microspheres, solid glass, and combinations thereof. The appropriate filler material to include in the proppant slurry depends on a number of factors, including the selected binding fluid, the ability to control density of the binding fluid, and the structural flexibility or firmness of the masses of the proppant slurry. For example, where the binding fluid comprises an aqueous gel, the filler material should act, inter alia, as proppant particulates and thus should be capable of preventing the fractures from fully closing. In other embodiments, where the binding fluid comprises a curable resin composition, the filler material is included in the proppant slurry, inter alia, to enhance the compressive strength of the proppant slurry after curing of the resin therein. In addition to supporting the fracture, the filler material also may act to prevent leakoff of the binding fluid into the subterranean formation.

The filler material may be provided in a wide variety of particle sizes. The average particulate sizes generally may range from about 2 mesh to about 400 mesh on the U.S. Sieve Series; however, it is to be understood that in certain circumstances, other sizes may be desired and will be entirely suitable for practice of the present invention. In some embodiments, for example, where the filler material has a specific gravity of greater than 2, the filler material may be present in the proppant slurry in an amount in the range of from about 1 pound to about 35 pounds per gallon of the binding fluid. In some embodiments, for example, where the filler material has a specific gravity of less than about 2, the filler material may be present in the proppant slurry in an amount in the range of from about 0.01 pound to about 10 pounds per gallon of the binding fluid. One of ordinary skill in the art, with the benefit of this disclosure, will be able to select the appropriate type, size, and amount of filler material to include in the proppant slurry for a particular application.

Optionally, the filler material may be coated with an adhesive substance. As used herein, the term “adhesive substance” refers to a material that is capable of being coated onto a particulate and that exhibits a sticky or tacky character such that the filler material that has adhesive thereon has a tendency to create clusters or aggregates. As used herein, the term “tacky,” in all of its forms, generally refers to a substance having a nature such that it is (or may be activated to become) somewhat sticky to the touch. Generally, the filler material may be coated with an adhesive material where the binding fluid is not a curable resin composition. Examples of adhesive substances suitable for use in the present invention include the consolidating agents listed above, such as non-aqueous tackifying agents; aqueous tackifying agents; silyl-modified polyamides; curable resin compositions that are capable of curing to form hardened substances; and combinations thereof. Among other things, the adhesive substances, in conjunction with the binding fluid, encourage the filler materials to form aggregates, preventing the filler material from being dispersed within the fractures, so that the filler materials aggregate even if the binding fluid that is confining the filler material becomes deteriorated after prolonged exposure to downhole conditions. Adhesive substances may be applied on-the-fly, applying the adhesive substance to the filler material at the well site, directly prior to pumping the proppant slurry into the well bore.

Any suitable carrier fluid that may be employed in subterranean operations may be used in accordance with the teachings of the present invention, including aqueous gels, viscoelastic surfactant gels, oil 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 exemplary embodiments of the present invention, the carrier 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, carrier fluid, inter alia, reduces fluid loss and allows the carrier fluid to transport proppant particulates (where desired) and/or the proppant aggregates (if necessary). The water used to form the carrier fluid may be fresh water, saltwater, seawater, brine, 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.

In one embodiment, predetermined volumes of proppant slurry may be pumped intermittently into the well bore so that a plurality of proppant aggregates may be introduced into the fracture. In these embodiments, the proppant slurry may be alternately pumped into the well bore with carrier fluid. For example, a first portion of the carrier fluid may be introduced into the well bore. After introduction of the first portion, a predetermined volume of the proppant slurry may be introduced into the well bore. In some embodiments, the predetermined volume of the proppant slurry may be in the range of from about 0.01 gallon to about 5 gallons. However, one of ordinary skill in the art, with the benefit of this disclosure, will recognize that larger volumes of the proppant slurry may be used, dependent upon, for example, the dimensions of the fracture. Once the predetermined volume of the proppant slurry has been introduced into the well bore, a second portion of the carrier fluid may be introduced into the well bore, thereby forming a proppant aggregate in the well bore, the proppant aggregate spaced between the first and second portions. These steps may be repeated until the desired amount of proppant aggregates have been formed and introduced into the fracture. The predetermined volumes of the proppant slurry that are being alternately pumped may remain constant or may be varied, such that the plurality of proppant aggregates introduced into the fracture are of varying sizes and shapes.

In another embodiment, the proppant slurry is combined with the carrier fluid so that the proppant slurry forms a plurality of proppant aggregates in the carrier fluid. Among other things, in these embodiments, the plurality of proppant aggregates should be suspended in the carrier fluid, carried by the carrier fluid into the fracture, and distributed within the fracture. In such embodiments, at least a portion of the proppant aggregates may be deposited within the fracture, for example, after the carrier fluid's viscosity is reduced. Generally, in these embodiments, the proppant slurry should be combined with the carrier fluid prior to introducing the carrier fluid into the well bore. Where the proppant slurry contains a curable resin composition, the proppant slurry is preferably combined with the carrier fluid downstream of the blending and/or pumping equipment to, among other things, reduce coating of the curable resin composition onto such equipment and to minimize the interaction of the proppant slurry and the carrier fluid. In one embodiment, the plurality of proppant aggregates are formed by shearing (or cutting) the proppant slurry as it is combined with the carrier fluid, e.g., as it is pumped and extruded from a container into a different container that contains the carrier fluid. In one certain embodiment where the proppant slurry is combined with the carrier fluid, predetermined volumes of the proppant slurry are intermittently injected into the carrier fluid that is being introduced into the well bore. The predetermined volumes of the proppant slurry that are being intermittently injected into the carrier fluid may remain constant or may be varied, such that the proppant aggregates form in the carrier fluid in varying sizes and shapes. In some embodiments, each predetermined volume of the proppant slurry may be in the range of from about 0.01 gallon to about 5 gallons. However, one of ordinary skill in the art, with the benefit of this disclosure, will recognize that larger volumes of the proppant slurry may be used, dependent upon, for example, the dimensions of the fracture.

In another embodiment, formation of the plurality of proppant aggregates comprises simultaneously introducing the carrier fluid and the proppant slurry into the fracture. In these embodiments, the carrier fluid and the proppant slurry may be introduced into the fracture via separate flow paths, so at to form a plurality of proppant aggregates. For example, one of the fluids (e.g., the carrier fluid or the proppant slurry) may be introduced into the fracture(s) via a conduit (e.g., coiled tubing or jointed pipe) that is disposed within the well bore, while the other fluid (e.g., the carrier fluid or the proppant slurry) may be introduced into the fracture via an annulus defined between the tubing and the casing. As the proppant slurry and the carrier fluid are co-introduced into the fracture, the plurality of proppant aggregates should form and be distributed within the fracture. Among other things, this may minimize interaction between the carrier fluid and the plurality of proppant aggregates and also may enhance the formation of layers between the two fluids. One of ordinary skill, with the benefit of this disclosure, will recognize other suitable methods for forming the proppant aggregates and introducing them into the fracture, dependent upon the particular application.

In accordance with the above described steps, the plurality of proppant aggregates should be introduced into the fracture so that the proppant aggregates are distributed through the length and height of the fracture without packing or stacking together. It is preferred that the proppant aggregates are randomly distributed throughout the length and height of the fracture. Despite the preference in forming partial monolayers of proppant aggregates in the fracture, the potential for forming a full monolayer or a packed portion potion in the fracture always exists due to, among other things, uneven distribution of the proppant aggregates, undesired accumulation of the proppant aggregates, or particle settling at one location.

Generally, the ratio of the plurality of proppant aggregates to carrier fluid introduced into the fracture will vary, depending on the compositions of the proppant aggregates and the carrier fluid, the closure stress applied on the proppant aggregates, formation characteristics and conditions, the desired conductivity of the fracture, the amount of the carrier fluid that can be removed from the fracture, and other factors known to those of ordinary skill in the art. As will be understood by those of ordinary skill in the art, with the benefit of this disclosure, the higher the ratio of the plurality of proppant aggregates to carrier fluid introduced into the fracture, the less void channels or less conductive fractures will result. In some embodiments, for example, in high Young's modulus formations (e.g., greater than about 1×10⁶ psi), the ratio of the plurality of proppant aggregates to carrier fluid introduced into the fracture is in the range of from about 1:9 by volume to about 8:2 by volume. In some embodiments, for example, in low Young's modulus formations (e.g., less than about 5×10⁵ psi), the ratio of the plurality of proppant aggregates to carrier fluid introduced into the fracture is in the range of from about 4:6 by volume to about 6:4 by volume.

In another embodiment, proppant aggregates may be formed and transported to a fracture by using a fracturing fluid system comprising a carrier fluid (e.g., a gel or a crosslinked gel fluid), and solids-laden gel bodies wherein the solids are non-degradable proppant materials (in a form such as aggregates, blobs, or clusters encapsulated by a degradable gel). Optionally, the fracturing fluid system may further comprise degradable solids-free gel bodies (in a form such as a blob, fragment, or chunk). The solid-laden gel bodies, tend to form aggregates when placed into a subterranean formation, such that once the gelled carrier fluid is removed, what remains are multiple, separate clusters of solid-laden gel bodies that act as pillars to keep the fracture propped open once the fracturing pressure has been released.

Gel bodies suitable for use in the present invention include those described in U.S. Patent Application Publication No. 2010/0089581, the entire disclosure of which is hereby incorporated by reference. In addition, the super-absorbent polymer discussed in U.S. Patent Application Publication No. 2011/0067868, the relevant discussion of which is hereby incorporated by reference, may also be suitable for use as gel bodies in the present invention. One of skill in the art will recognize that some of the gel bodies may be designed to degrade once the fracture closes, while other gel bodies may be more resistant to such degradation long after the closing of the fracture. In some instances, the gel used to form the solids-laden gel bodies preferably does not degrade under the conditions in the subterranean formation while the solids-free gel bodies preferably degrade after the fracture closes.

By way of example, gel bodies of the present invention may be formed from swellable polymers. Preferably, the swellable particulate is an organic material such as a polymer or a salt of a polymeric material. Typical examples of polymeric materials include, but are not limited to, cross-linked polyacrylamide, cross-linked polyacrylate, cross-linked copolymers of acrylamide and acrylate monomers, starch grafted with acrylonitrile and acrylate, cross-linked polymers of two or more of allylsulfonate, 2-acrylamido-2-methyl-1-propanesulfonic acid, 3-allyloxy-2-hydroxy-1-propanesulfonic acid, acrylamide, acrylic acid monomers, and any combination thereof in any proportion. Typical examples of suitable salts of polymeric material include, but are not limited to, salts of carboxyalkyl starch, salts of carboxymethyl starch, salts of carboxymethyl cellulose, salts of cross-linked carboxyalkyl polysaccharide, starch grafted with acrylonitrile and acrylate monomers, and any combination thereof in any proportion. The specific features of the swellable particulate may be chosen or modified to provide a proppant pack or matrix with desired permeability while maintaining adequate propping and filtering capability. These swellable particulates are capable of swelling upon contact with a swelling agent. The swelling agent for the swellable particulate can be any agent that causes the swellable particulate to swell via absorption of the swelling agent.

In a preferred embodiment, the swellable particulate is “water swellable,” meaning that the swelling agent is water. Suitable sources of water for use as the swelling agent include, but are not limited to, fresh water, brackish water, sea water, brine, and any combination thereof in any proportion. In another embodiment of the invention, the swellable particulate is “oil swellable,” meaning that the swelling agent for the swellable particulate is an organic fluid. Examples of organic swelling agents include, but are not limited to, diesel, kerosene, crude oil, and any combination thereof in any proportion.

Also by way of example, degradable gel bodies may be formed from super-absorbent polymers. Suitable such super-absorbent polymers include polyacrylamide, crosslinked poly(meth)acrylate, and non-soluble acrylic polymers.

In some embodiments, the solids (proppant) used in the solids-laden gel bodies can be coated with a curable resin. The resin may cure in the subterranean formation to consolidate the proppant of the proppant pack to form a “proppant matrix.” After curing, the resin improves the strength, clustering ability, and flow-back control characteristics of the proppant matrix relative to a similar proppant pack without such a curable resin. A proppant matrix may also be formed by incorporating a non-curable tackifying agent into at least a portion of the proppant. The tackifying agent can be used in addition to or instead of a curable resin.

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. 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, combined, or modified and all such variations are considered within the scope and spirit of the present invention. The invention illustratively disclosed herein suitably may be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “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 to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

Claims

1. A method comprising:

providing proppant aggregates; a diverting fluid comprising a diverting agent; and a packing fluid;

introducing the proppant aggregates into a fracture that is fluidically connected to a wellbore through a plurality of perforations;

introducing the diverting fluid into the wellbore thereby forming at least one sealed perforation and leaving at least one unsealed perforation; and

introducing the packing fluid into the fracture through the at least one unsealed perforation thereby allowing the proppant aggregates to form a proppant bed within the fracture.

2. The method of claim 1, wherein the diverting agent is degradable.

3. The method of claim 2, further comprising: allowing the degradable diverting agent to degrade thereby unsealing the at least one perforation.

4. The method of claim 1, wherein the diverting agent is selected from the group consisting of: a polysaccharide, a chitin, a chitosan, a protein, an orthoester, an aliphatic polyester, a poly(glycolide), a poly(lactide), a poly(ε-caprolactone), a poly(hydroxybutyrate), a polyanhyride, an aliphatic polycarbonate, a poly(orthoester), a poly(amino acid), a poly(ethylene oxide), a polyphosphazene, any derivative thereof, and any combination thereof.

5. The method of claim 1, wherein the diverting agent seals at least 60% of the perforations that fluidically connect the wellbore and the fracture.

6. The method of claim 1, wherein the diverting agent seals at least 75% of the perforations that fluidically connect the wellbore and the fracture.

7. The method of claim 1, wherein the at least one unsealed perforation is located at or near a bottom of the fracture.

8. The method of claim 1, wherein the proppant aggregate comprises a binding fluid and a filler material selected from the group consisting of: sand, bauxite, ceramic material, glass material, polymer material, polytetrafluoroethylene material, nut shell piece, cured resinous particulate comprising a nut shell piece, seed shell piece, cured resinous particulate comprising seed shell piece, fruit pit piece, cured resinous particulate comprising fruit pit piece, wood, composite particulate, and any combination thereof.

9. The method of claim 8, wherein the filler material is coated with an adhesive selected from the group consisting of: a non-aqueous tackifying agent, an aqueous tackifying agent, a silyl-modified polyamide, a zeta-potential modifying agent, a curable resin composition, and any combination thereof.

10. The method of claim 8, wherein the binding fluid comprises a curable resin composition and an aqueous gel.

11. The method of claim 1, wherein the packing fluid comprises proppants.

12. A method comprising:

providing proppant aggregates; a diverting fluid comprising a degradable diverting agent; and a packing fluid;

introducing the proppant aggregates into a fracture that is fluidically connected to a wellbore through a plurality of perforations;

introducing the diverting fluid into the wellbore thereby forming at least one sealed perforation and leaving at least one unsealed perforation;

introducing the packing fluid into the fracture through the at least one unsealed perforation thereby allowing the proppant aggregates to form a proppant bed within the fracture; and

allowing the degradable diverting agent to degrade thereby unsealing the at least one perforation.

13. The method of claim 12, wherein the diverting agent is selected from the group consisting of: a polysaccharide, a chitin, a chitosan, a protein, an orthoester, an aliphatic polyester, a poly(glycolide), a poly(lactide), a poly(ε-caprolactone), a poly(hydroxybutyrate), a polyanhyride, an aliphatic polycarbonate, a poly(orthoester), a poly(amino acid), a poly(ethylene oxide), a polyphosphazene, any derivative thereof, and any combination thereof.

14. The method of claim 12, wherein the diverting agent seals at least 60% of the plurality of perforations that fluidically connect the wellbore and the fracture.

15. The method of claim 12, wherein the diverting agent seals at least 75% of the plurality of perforations that fluidically connect the wellbore and the fracture.

16. The method of claim 12, wherein the at least one unsealed perforation is located at or near a bottom of the fracture.

17. The method of claim 12, wherein the proppant aggregate comprises a binding fluid and a filler material selected from the group consisting of: sand, bauxite, ceramic material, glass material, polymer material, polytetrafluoroethylene material, nut shell piece, cured resinous particulate comprising a nut shell piece, seed shell piece, cured resinous particulate comprising seed shell piece, fruit pit piece, cured resinous particulate comprising fruit pit piece, wood, composite particulate, and any combination thereof.

18. The method of claim 17, wherein the filler material is coated with an adhesive selected from the group consisting of: a non-aqueous tackifying agent, an aqueous tackifying agent, a silyl-modified polyamide, a zeta-potential modifying agent, a curable resin composition, and any combination thereof.

19. The method of claim 17, wherein the binding fluid comprises a curable resin composition and an aqueous gel.

20. The method of claim 12, wherein the packing fluid comprises proppants.