SYSTEM AND METHOD OF TREATING A SUBTERRANEAN FORMATION

Abstract

A method and system for treating a subterranean formation, relating to a diluted stream of carrier fibers, and a high-loading stream of a diverting agent, and their use in a downhole diversion operation.

Description

BACKGROUND

The list of diverting techniques used in wellbores includes, but is not limited to, mechanical isolation devices such as packers and well bore plugs, bridge plugs, ball sealers, slurried solids such as benzoic acid flakes and removable and/or degradable particulates. For example, the hydraulic and acid fracturing of horizontal wells as well as multi-layered formations frequently require the use of diversion techniques to direct the fracturing fluid between different zones.

Treatment diversion with particulates may be based on the bridging of particles of the diverting material, e.g., behind casing, and forming a plug by accumulating additional particles at the formed bridge. Several problems are related to treatment diversion with particulate materials. One problem is that a precisely timed delivery of a relatively high concentration “pill” for diversion in a relatively small volume of treatment fluid for a very short period of time is difficult using standard surface pumping and mixing equipment, that is designed to supply typically low concentrations solids or proppants delivered in large fluid volumes at relatively high flow rates and high pressures for extended periods of time to deliver the proppant to the far reaches of an extensive fracture network. For example, tons of proppant may be delivered at 0.12-0.18 g/L, based on the volume of carrier fluid (1-1.5 ppa or pounds of proppant added per gallon of carrier fluid) over a period of several hours, whereas the diversion slurry may require delivery, in less than a minute, orders of magnitude more solids, e.g., about 10 g/L.

Additionally, any interruption of the continuous injection of treatment fluid can result in proppant or other solids falling out of suspension and possibly forming a bridge in an undesired location, leading to a failure of the fracture operation and prematurely terminating the fracturing treatment. Therefore, care must be taken in making any changes to the treatment fluid so as to avoid an undesirable interruption of pumping of the treatment fluid in a continuous manner.

As another consideration, dilution of the diverting slurry with other wellbore fluid during pumping, e.g., via interface mixing, reduces the ability of the diverting slurry to form a bridge and/or plug and effect diversion to another downhole flow feature. The necessity of using relatively large amounts and/or high concentrations of diverting materials to effect diversion imposes economic and logistic constraints, as well as difficulties with over-diversion to undesired downhole features and removal of excessive diverting material. The poor stability of some diverting agents during either pumping and/or the subsequent treatment stage can lead to poor diversion efficiency.

It can be a challenge to achieve the relatively high content of a diverting agent within a diversion slurry of treatment fluid, that is generally used for plugging or diverting a downhole feature with solid diverting materials to form temporary bridges or plugs, such as a total amount of fibers and/or other shaped particles of from about 2.4 g/L (20 lbs/1000 gal) to about 180 g/L (1500 lbs/1000 gal. The ability to add a briefly high concentration of solid in a continuous manner for a short period of time with traditional low concentration solid feeders, which are limited in their feeding rates, as well as how quickly the feeding rate can be adjusted, is difficult. Because the treatment fluid, including both the fracturing fluid and the diversion slurry, is to be injected at a high rate, typically 132 L/s (50 bbl/min) or more, and at a high pressure, e.g., 6.9 MPa (1000 psi) to 140 MPa (20,000 psi) or more, the rate of addition of the diverting agent should be substantial enough to create a stream of high concentration solid material. Solid material may be in the form of manufactured shapes such as flakes, fibers and particles. The traditional methods of adding solid material cannot easily achieve a rapid injection of high concentrations of diverting agent so as to achieve a suitable stream, and when such methods are repeated during the treatment of the well, errors may be compounded.

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. The statements made merely provide information relating to the present disclosure, and may describe some embodiments illustrating the subject matter of this application.

In aspects, methods for injecting a diverting composition may include transporting a diluted fluid stream to a high pressure flow line, transporting a high-loading stream to the high pressure flow line, combining the diluted fluid stream and the high-loading stream to form a diverting composition, and introducing the diverting composition into the wellbore.

In further aspects, systems for injecting a diverting composition are envisaged. The systems may include at least one diluted fluid device that transports a diluted fluid stream to a high pressure flow line, and at least one high-loading device that transports a high-loading stream to the high pressure flow line. The diluted fluid stream and the high-loading stream may be combined to form a diverting composition, and the diverting composition may be introduced into the wellbore.

In further aspects, methods are disclosed. The methods may be for pumping a diverting composition. The methods may include pumping a diluted fluid stream to a high pressure flow line, pumping a high-loading stream to the high pressure flow line, combining the diluted fluid stream and the high-loading stream to form a diverting composition, and introducing the diverting composition into the wellbore. The diluted fluid stream may include a first amount of degradable fibers, a viscosifying agent and water. The high-loading stream may include a second amount of degradable fibers, particles, and water.

In yet further aspects, treatment methods may comprise introducing a diluted stream, comprising a non-bridging amount of carrier fibers in a low viscosity carrier fluid, into a high pressure flow line; adding proppant to the diluted stream to form a proppant-laden stream; injecting the proppant-laden stream from the high pressure flow line into a first fracture; introducing a high-loading stream, comprising a diverting agent, into the high pressure flow line to combine with the diluted stream to form a diversion slurry; delivering the diversion slurry from the high pressure flow line to the first fracture to divert fluid flow to a second fracture; and injecting the proppant-laden stream from the high pressure flow line into the second fracture.

In still further aspects, treatment methods may comprise introducing a diluted stream, comprising a non-bridging amount of carrier fibers, from a diluted fluid device to a high pressure flow line; introducing a high-loading stream, comprising a mix of bridging fibers and manufactured shape particles, from a high-loading fluid device to the high pressure flow line; combining the diluted stream and the high-loading stream to form a diversion slurry; and delivering the diversion slurry from the high pressure flow line to a downhole fluid flow feature to divert fluid flow from the downhole fluid flow feature to an alternate flow path.

Yet further aspects comprise treatment methods comprising injecting a treatment fluid through a high pressure flow line into the subterranean formation to form a hydraulic fracture system, wherein the treatment fluid comprises: a low viscosity carrier fluid having a viscosity less than 50 mPa-s at a shear rate of 170 s⁻¹ and a temperature of 25° C., proppant dispersed in the carrier fluid, and carrier fiber dispersed in the carrier fluid; maintaining a rate of the injection of the treatment fluid to avoid bridging in the wellbore; introducing a diluted stream, comprising a non-bridging amount of the carrier fibers and optionally free of the proppant, to the high pressure flow line; introducing a high-loading stream, comprising a mix of bridging fibers and manufactured shape particles, to the high pressure flow line; combining the diluted stream and the high-loading stream to form a diversion slurry; delivering the diversion slurry from the high pressure flow line to the hydraulic fracture system to divert fluid flow from one fracture to another.

Aspects pertain to systems for injecting a treatment fluid, comprising at least one diluted fluid device that transports a diluted stream to a high pressure flow line; at least one high-loading device that transports a high-loading stream to the high pressure flow line to combine with the diluted stream to form a diversion slurry; and a flow path for the diversion slurry to a downhole feature.

In any of the foregoing and following aspects of the disclosure, the diluted stream may comprise from 1.2 to 12 g/L of the carrier fibers based on the total volume of the diluted stream (from 10 to 100 ppt, pounds per thousand gallons of carrier fluid).

In any of the foregoing and following aspects of the disclosure, the high-loading stream may comprise a low viscosity carrier fluid; and the diverting agent may comprise from 1.2 to 12 g/L (from 10 to 100 ppt) of bridging fibers based on the total volume of the high-loading stream, and from 1.2 to 120 g/L (10 to 1000 ppt) of manufactured shape particles based on the total volume of the high-loading stream.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a schematic representation of a treatment configuration of the related art.

FIG. 2 shows a schematic representation of a treatment configuration according to one or more embodiments herein.

FIG. 3 shows a diagram of a treatment configuration according to one or more embodiments herein.

FIG. 4 shows a graphical representation of pressure changes with respect to time according to one or more embodiments herein.

FIG. 5A schematically illustrates a bridging test apparatus according to embodiments.

FIG. 5B schematically illustrates an enlarged detail of the slot design in the apparatus of FIG. 5A.

FIG. 6 schematically graphs the proppant settling in a treatment fluid with various fibers.

FIG. 7 schematically graphs the effect of fiber loading on proppant settling in a treatment fluid with crimped mid temperature fibers.

FIG. 8 schematically graphs the effect of fiber loading on proppant settling in a treatment fluid with crimped low temperature fibers.

FIG. 9 schematically graphs the effect of fiber diameter on proppant settling in a treatment fluid with crimped mid temperature fibers.

FIG. 10 schematically graphs the effect of fiber diameter on proppant settling in a treatment fluid with crimped low temperature fibers.

FIG. 11 schematically graphs the effect of fiber length on proppant settling in a treatment fluid with crimped mid temperature fibers.

FIG. 12 schematically graphs the effect of fiber length on proppant settling in a treatment fluid with crimped low temperature fibers.

FIG. 13 schematically graphs the effect of crimp level on proppant settling in a treatment fluid with crimped low temperature fibers.

FIG. 14 schematically graphs the proppant settling in a slickwater fluid with various 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.

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

The term “wellbore” is a drilled hole or borehole, including the openhole or uncased portion of the well that is drilled during a treatment of a subterranean formation. The term “wellbore” does not include the wellhead, or any other similar apparatus positioned over the wellbore. The term “treatment” or “treating” refers to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose. The term “treatment” or “treating” does not imply any particular action by the fluid.

The term “injecting” describes the introduction of a new or different element into a first element. In the context of this application, injection of a fluid, solid or other compound may occur by any form of physical introduction, including but not limited to pumping.

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

The term “matrix acidizing” refers to a process where treatments of acid or other reactive chemicals are pumped into the formation at a pressure below which a fracture can be created. The matrix acidizing methods otherwise use techniques known in the art.

In some embodiments herein, a treatment fluid comprises a carrier fluid, and may optionally further comprise fibers and/or fiber mixtures, proppant and/or other materials such as particles other than fiber or proppant, dispersed in the carrier fluid. As used herein, when not used in context relative to a higher viscosity fluid, a “low viscosity” fluid, e.g., a low viscosity carrier, 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. The term “particulate” or “particle” refers to a solid 3-dimensional object with maximal dimension less than 1 meter. Here, “dimension” of the object refers to the distance between two arbitrary parallel planes, each plane touching the surface of the object at least at one point.

The carrier fluid may include water, fresh water, e.g., “slickwater,” seawater, connate water or produced water. The carrier fluid may also include hydratable gels (such as guars, polysaccharides, xanthan, hydroxy-ethyl-cellulose (HEC), guar, copolymers of polyacrylamide and their derivatives, e.g., acrylamido-methyl-propane sulfonate polymer (AMPS), or other similar gels, or a viscoelastic surfactant system, e.g., a betaine, or the like), a cross-linked hydratable gel, a viscosified acid (such as a gel-based viscosified acid), an emulsified acid (such as an oil outer phase emulsified acid), an energized fluid (such as an N₂ or CO₂ based foam), and an oil-based fluid including a gelled, foamed, or otherwise viscosified oil. The carrier fluid may be a brine, and/or may include a brine. The carrier fluid may include hydrochloric acid, hydrofluoric acid, ammonium bifluoride, formic acid, acetic acid, lactic acid, glycolic acid, maleic acid, tartaric acid, sulfamic acid, malic acid, citric acid, methyl-sulfamic acid, chloro-acetic acid, an amino-poly-carboxylic acid, 3-hydroxypropionic acid, a poly-amino-poly-carboxylic acid, and/or a salt of any acid. In embodiments, the carrier fluid includes a poly-amino-poly-carboxylic acid, such as a trisodium hydroxyl-ethyl-ethylene-diamine triacetate, mono-ammonium salts of hydroxyl-ethyl-ethylene-diamine triacetate, and/or mono-sodium salts of hydroxyl-ethyl-ethylene-diamine tetra-acetate, or other similar compositions. When a polymer is present in a low viscosity carrier fluid, for example, in some embodiments it may be present at a concentration below 1.92 g/L (16 ppt), e.g. from 0.12 g/L (1 ppt) to 1.8 g/L (15 ppt). When a viscoelastic surfactant is used in a low viscosity carrier fluid, for example, in some embodiments it may be used at a concentration below 10 ml/L, e.g. 2.5 ml/L to 5 ml/L.

The term “diluted stream (or fluid)” in one sense, in the context of concentration or loading of a material(s) or type(s) of material(s) relative to another stream, which other stream may be, but not necessarily, referred to as a “high-loading stream,” where the loadings of the comparative streams may or may not be specified, refers to the one of the streams having the lower loading of the material under consideration. In another sense, where the context does not indicate that a relative loading is to be implied, the term “diluted stream” refers to a stream comprising 4.8 g/L (40 lbs/1000 gal) or less of the material(s) or type(s) of material(s), e.g., carrier fibers, based on the total volume of the diluted stream (fluid plus solids volume). In some embodiments, the diluted stream may comprise or consist essentially of fibers that are proppant-suspending and/or non-bridging.

Similarly, the term “high-loading stream (or fluid)” in the context of concentration or loading of a material(s) or type(s) of material(s) relative to another stream, which other stream may be, but not necessarily, referred to as a “diluted stream,” where the loadings of the comparative streams may or may not be specified, refers to the one of the streams having the higher loading of the material under consideration. In another sense, where the context does not indicate that a relative loading is to be implied, the term “high-loading stream” refers to a stream comprising more than 4.8 g/L (40 lbs/1000 gal) of the material(s) or type(s) of material(s), e.g., a mix of fibers and other particles optionally including proppant, based on the total volume of the high-loading stream (fluid plus solids volume).

According to some embodiments of the present disclosure, different types of fibers may be used optionally at different loadings to provide different functionalities, which may not necessarily be mutually exclusive, to a particular treatment fluid or stream. For example, the term “carrier fibers” refers to fibers which are suitable at an appropriate loading for assisting in the transport of proppant into a fracture, e.g., either during initiation, propagation or branching of the fiber, whereas the term “non-bridging fibers” refers to fibers which are suitable for use in a carrier fluid at specified conditions and loadings generally without forming a bridge in the flow path of interest. For example, carrier fibers may be bridging or non-bridging. “Bridging fibers” refers to fibers that do not have the non-bridging quality and/or non-bridging fibers used a bridge-inducing loading rates.

In some embodiments, the treatment fluid comprises from 1.2 to 12 g/L of the carrier fibers based on the total volume of the carrier fluid (from 10 to 100 ppt, pounds per thousand gallons of carrier fluid), e.g., equal to or less than 4.8 g/L of the fibers based on the total volume of the carrier fluid (equal to or less than 40 ppt) or from 1.2 or 2.4 to 4.8 g/L of the fibers based on the total volume of the carrier fluid (from 10 or 20 to 40 ppt).

In some embodiments, the carrier fibers, which may be proppant-suspending and/or non-bridging, are crimped staple fibers. In some embodiments, the crimped fibers comprise from 1 to 10 crimps/cm of length, a crimp angle from 45 to 160 degrees, an average extended length of fiber of from 4 to 15 mm, and/or a mean diameter of from 8 to 40 microns, or 8 to 12, or 8 to 10, or a combination thereof. In some embodiments, the carrier fibers comprise low crimping equal to or less than 5 crimps/cm of fiber length, e.g., 1-5 crimps/cm.

Depending on the temperature that the treatment fluid will encounter, especially at downhole conditions, the carrier fibers may be chosen depending on their resistance or degradability at the envisaged temperature. In the present disclosure, the terms “low temperature fibers”, “mid temperature fibers” and “high temperature fibers” may be used to indicate the temperatures at which the fibers may be used for delayed degradation, e.g., by hydrolysis, at downhole conditions. Low temperatures are typically within the range of from about 60° C. (140° F.) to about 93° C. (200° F.); mid temperatures typically from about 94° C. (201° F.) to about 149° C. (300° F.); and high temperatures typically about 149.5° C. (301° F.) and above, or from about 149.5° C. (301° F.) to about 204° C. (400° F.).

In some embodiments, the carrier fibers comprise polyester. In some embodiments, the polyester undergoes hydrolysis at a low temperature of less than about 93° C. as determined by slowly heating 10 g of the fibers in 1 L deionized water until the pH of the water is less than 3, and in some embodiments, the polyester undergoes hydrolysis at a moderate temperature of between about 93° C. and 149° C. as determined by slowly heating 10 g of the fibers in 1 L deionized water until the pH of the water is less than 3, and in some embodiments, the polyester undergoes hydrolysis at a high temperature greater than 149° C., e.g., between about 149.5° C. and 204° C. In some embodiments, the polyester is selected from the group consisting of polylactic acid, polyglycolic acid, copolymers of lactic and glycolic acid, and combinations thereof.

In some embodiments, the proppant-suspending and/or non-bridging carrier fibers are selected from the group consisting of polylactic acid (PLA), polyglycolic acid (PGA), polyethylene terephthalate (PET), polyester, polyamide, polycaprolactam and polylactone, poly(butylene) succinate, polydioxanone, nylon, glass, ceramics, carbon (including carbon-based compounds), elements in metallic form, metal alloys, wool, basalt, acrylic, polyethylene, polypropylene, novoloid resin, polyphenylene sulfide, polyvinyl chloride, polyvinylidene chloride, polyurethane, polyvinyl alcohol, polybenzimidazole, polyhydroquinone-diimidazopyridine, poly(p-phenylene-2,6-benzobisoxazole), rayon, cotton, cellulose and other natural fibers, rubber, and combinations thereof.

In some embodiments, the treatment fluid, e.g., the diluted stream, when proppant is present as in the initiation, propagation or other fracture creation operation, comprises from 0.01 to 1 kg/L of the proppant based on the total volume of the carrier fluid in the treatment stream (from 0.1 to 8.3 ppa, pounds proppant added per gallon of carrier fluid), e.g., from 0.048 to 0.6 kg/L of the proppant based on the total volume of the carrier fluid in the dilute stream (0.4 to 5 ppa), or from 0.12 to 0.48 kg/L of the proppant based on the total volume of the carrier fluid in the dilute stream (from 1 to 4 ppa), or from 0.12 to 0.18 kg/L of the proppant based on the total volume of the carrier fluid in the dilute stream (from 1 to 1.5 ppa). As used herein, proppant loading is specified in weight of proppant added per volume of dilute stream or other treatment, e.g., kg/L (ppa=pounds of proppant added per gallon of carrier fluid). Other materials in the treatment fluid are generally expressed in terms of g/L based on the total volume of the treatment fluid (ppt=pounds of material per thousand gallons of treatment fluid). Exemplary proppants include ceramic proppant, sand, bauxite, glass beads, crushed nut shells, polymeric proppant, rod shaped proppant, and mixtures thereof.

In some embodiments, a suitable carrier fiber can be dispersed in the carrier in an amount effective to inhibit settling of proppant, where proppant is present. This settling inhibition may be evidenced, in some embodiments, for example, in a static proppant settling test at 25° C. for 90 minutes. The proppant settling test in some embodiments involves placing the fluid in a container such as a graduated cylinder and recording the upper level of dispersed proppant in the fluid. The upper level of dispersed proppant is recorded at periodic time intervals while maintaining settling (quiescent) conditions. The proppant settling fraction is calculated as:

$\mathrm{Proppant}\mathrm{settling}=\frac{\begin{array}{c}\left[\mathrm{initial}\mathrm{proppant}\mathrm{level}\left(t=0\right)\right]-\\ \left[\mathrm{upper}\mathrm{proppant}\mathrm{level}\mathrm{at}\mathrm{time}n\right]\end{array}}{\begin{array}{c}\left[\mathrm{initial}\mathrm{proppant}\mathrm{level}\left(t=0\right)\right]-\\ \left[\mathrm{final}\mathrm{proppant}\mathrm{level}\left(t=\infty \right)\right]\end{array}}$

The carrier fiber inhibits proppant settling if the proppant settling fraction for the fluid containing the proppant and carrier fiber has a lower proppant settling fraction than the same fluid without the carrier fiber and with the proppant only. In some embodiments of the diluted stream containing proppant, the proppant settling fraction of the diluted stream in the static proppant settling test after 90 minutes is less than 50%, e.g., less than 40%.

In some embodiments, the carrier fiber is dispersed in the diluted stream in an amount insufficient to cause bridging, e.g., as determined in a small slot test comprising passing the treatment fluid comprising the carrier fluid and the carrier fiber without proppant at 25° C. through a bridging apparatus such as that shown in FIGS. 5A and 5B comprising a 1.0-1 8 mm slot that is 15-16 mm wide and 65 mm long at a flow rate equal to 15 cm/s, or at a flow rate equal to 10 cm/s.

In some embodiments the carrier fiber is dispersed in the diluted stream comprising proppant in both an amount effective to inhibit settling of the proppant and in an amount insufficient to cause bridging, wherein settling and bridging are determined by comparing proppant accumulation in a narrow fracture flow test comprising pumping the treatment fluid at 25° C. through a 2 mm slot measuring 3 m long by 0.5 m high for 60 seconds at a flow velocity of 65 cm/s, or at a flow velocity of 20 cm/s, relative to a reference fluid containing the carrier fluid and proppant only without the carrier fiber. In the narrow fracture flow test, the slot may be formed of flow cells with transparent windows to observe proppant settling at the bottom of the cells. Proppant settling is inhibited if testing of the fluid with the proppant and carrier fiber results in measurably less proppant settling than the same fluid and proppant mixture without the carrier fiber at the same other testing conditions. Bridging is likewise observed in the narrow fracture flow test as regions exhibiting a reduction of fluid flow also resulting in proppant accumulation in the flow cells.

In some embodiments the treatment fluid comprising the diluted stream may include a fluid loss control agent, e.g., fine solids less than 10 microns, or ultrafine solids less than 1 micron, or 30 nm to 1 micron. According to some embodiments, the fine solids are fluid loss control agents such as γ-alumina, colloidal silica, CaCO₃, SiO₂, bentonite etc.; and may comprise particulates with different shapes such as glass fibers, flocs, flakes, films; and any combination thereof or the like. Colloidal silica, for example, may function as an ultrafine solid loss control agent, depending on the size of the micropores in the formation, as well as a gellant and/or thickener in any associated liquid or foam phase.

In some embodiments, e.g., where the diluted stream is used to carry proppant or otherwise in fracture creation with or without proppant, the carrier fluid comprises brine, e.g., sodium chloride, potassium bromide, ammonium chloride, potassium choride, tetramethyl ammonium chloride and the like, including combinations thereof. In some embodiments the diluted stream may comprise oil, including synthetic oils, e.g., in an oil based or invert emulsion fluid.

In some embodiments, e.g., where the diluted stream is used to carry proppant or otherwise in fracture creation with or without proppant, the carrier fluid comprises a friction reducer, e.g., a water soluble polymer. The diluted stream may additionally or alternatively include, without limitation, clay stabilizers, biocides, crosslinkers, breakers, corrosion inhibitors, temperature stabilizers, surfactants, and/or proppant flowback control additives. The diluted stream may further include a product formed from degradation, hydrolysis, hydration, chemical reaction, or other process that occur during preparation or operation.

In some embodiments, a method to treat a subterranean formation penetrated by a wellbore, comprises injecting the treatment fluid described herein, e.g., the diluted stream into the subterranean formation to form a hydraulic fracture system, and maintaining a rate of the injection to avoid bridging in the wellbore, such as, for example, as determined in a bridging testing apparatus without proppant.

In some embodiments, the method may comprise injecting a pre-pad, pad, tail or flush stage or a combination thereof, which may be, for example, the diluted stream described herein. In some embodiments, the treatment fluid used in other aspects of the method comprises the diluted stream described herein, optionally including proppant and/or other additives described herein, in any combination.

The diluted stream may be prepared using blenders, mixers and the like as shown in FIGS. 1-3 discussed in more detail below, using standard treatment fluid preparation equipment and well circulation and/or injection equipment. In some embodiments, a method is provided to inhibit proppant settling in a treatment fluid circulated in a wellbore, wherein the diluted stream comprises the proppant dispersed in a low viscosity carrier fluid. The method comprises dispersing carrier fiber in the carrier fluid in an amount effective to inhibit settling of the proppant, such as, for example, as determined in the small slot test, and maintaining a rate of the circulation to avoid bridging in the wellbore, such as, for example, as determined in a bridging testing apparatus without proppant and/or in the narrow fracture flow test. In some embodiments, the treatment fluid further comprises a friction reducer.

According to some embodiments, the proppant stage(s) may be injected into a fracture system using any one of the available proppant placement techniques, including heterogeneous proppant placement techniques, wherein the low viscosity treatment fluid herein is used in place of or in addition to any proppant-containing treatment fluid, such as, for example, those disclosed in U.S. Pat. No. 3,850,247; U.S. Pat. No. 5,330,005; U.S. Pat. No. 7,044,220; U.S. Pat. No. 7,275,596; U.S. Pat. No. 7,281,581; U.S. Pat. No. 7,325,608; U.S. Pat. No. 7,380,601; U.S. Pat. No. 7,581,590; U.S. Pat. No. 7,833,950; U.S. Pat. No. 8,061,424; U.S. Pat. No. 8,066,068; U.S. Pat. No. 8,167,043; U.S. Pat. No. 8,230,925; U.S. Pat. No. 8,372,787; US 2008/0236832; US 2010/0263870; US 2010/0288495; US 2011/0240293; US 2012/0067581; US 2013/0134088; EP 1556458; WO 2007/086771; SPE 68854: Field Test of a Novel Low Viscosity Fracturing Fluid in the Lost Hills Fields, California; and SPE 91434: A Mechanical Methodology of Improved Proppant Transport in Low-Viscosity Fluids: Application of a Fiber-Assisted Transport Technique in East Texas; each of which is hereby incorporated herein by reference in its entirety.

The term “diverting (or diversion) agent” refers to a chemical or solid agent used alone or with another diverting agent(s) used in well treatments, e.g., stimulation treatments, to at least temporarily selectively control the rate of flow of a treatment fluid, e.g., reduce or stop the flow rate, into a downhole feature being treated, and may (and usually will), but not necessarily, initiate, maintain or increase the rate of flow of the same or a different treatment fluid to another downhole feature. Diverting agents, also known as chemical or solid diverters, function by creating a temporary blocking effect, e.g., either a bridge or a plug, that may optionally be cleaned up following the treatment, i.e., for diversion or for temporal zonal isolation as disclosed in U.S. Patent Application Publication No. 2012/0285692 to Potapenko et al., which is hereby incorporated by reference in its entirety. A “diverting (or diversion) composition” refers to a composition comprising a diverting agent plus a carrier fluid; and the term “diversion slurry” refers to a diverting agent flowably dispersed in a fluid such as a gas, liquid, foam or energized fluid. A “downhole feature” refers to any feature without limitation through which fluid may flow or pass, including, but not limited to, a formation matrix, screen or other porous media, or surface thereof, fracture, formation void, vug, wormhole, fluid loss zone, chamber, perforation, valve, opening, or a line, tubing pipe or similar flow conduit, such as casing, tubing (including coiled tubing), drill pipe, and including any annulus or space between any of such structures, and any combinations thereof, or the like.

The diversion composition may be made of blends of particles or blends of particles and flakes, as examples. For example, the diversion composition may comprise a non-bridging fiber, either alone at a bridging concentration or in combination with another specific bridging fiber and/or particulates. The size of the largest particles or flakes in the blends according to embodiments may be slightly smaller than the diameter of the perforation holes in the zone or other downhole feature to isolate or divert.

According to embodiments, the size of the particles or flakes in the blends may be larger than an average width of the void intended to be closed or temporally isolated. The average width of the void may be the smallest width of the void after the perforation hole or another entry in such void, at 10 cm, at 20 cm, at 30 cm, at 50 cm or at 500 cm (when going into the formation from the wellbore). The void may be a perforation tunnel, hydraulic fracture or wormhole. In some embodiments, the ratio between particles and flakes in the blends may reduce permeability of the formed plugs.

In some embodiments, the diverting agent includes removable diverting materials which may be degradable material and/or dissolvable material. A degradable material refers to a material that will at least partially degrade (for example, by cleavage of a chemical bond) within a desired period of time such that no additional intervention is used to remove the plug. For example, at least 30% of the removable material may degrade, such as at least 50%, or at least 75%. In some embodiments, 100% of the removable material may degrade. The degradation of the removable material may be triggered by a temperature change, and/or by chemical reaction between the removable material and another reactant. Degradation may include dissolution of the removable material.

Removable materials for use as the diverting agent may be in any suitable shape: for example, powder, particulates, beads, chips, or fibers. When the removable material is in the shape of fibers, the fibers may have a length of from about 2 to about 25 mm, such as from about 3mm to about 20mm In some embodiments, the fibers may have a linear mass density of about 0.111 dtex to about 22.2 dtex (about 0.1 to about 20 denier), such as about 0.167 to about 6.67 dtex (about 0.15 to about 6 denier). Suitable fibers may degrade under downhole conditions, which may include temperatures as high as about 180° C. (about 350° F.) or more and pressures as high as about 137.9 MPa (about 20,000 psi) or more, in a duration that is suitable for the selected operation, from a minimum duration of about 0.5, about 1, about 2 or about 3 hours up to a maximum of about 24, about 12, about 10, about 8 or about 6 hours, or a range from any minimum duration to any maximum duration.

The removable materials may be sensitive to the environment, so dilution and precipitation properties should be taken into account when selecting the appropriate removable material. The removable material used as a sealer may survive in the formation or wellbore for a sufficiently long duration (for example, about 3 to about 6 hours). The duration should be long enough for wireline services to perforate the next pay sand, subsequent fracturing treatment(s) to be completed, and the fracture to close on the proppant before it completely settles, providing an improved fracture conductivity.

Further suitable removable materials and methods of use thereof include those described in U.S. Patent Application Publication Nos. 2006/0113077, 2008/0093073, and 2012/0181034, the disclosures of which are incorporated by reference herein in their entireties. Such materials include inorganic fibers, for example of limestone or glass, but are more commonly polymers or co-polymers of esters, amides, or other similar materials. They may be partially hydrolyzed at non-backbone locations. Any such materials that are removable (due in-part because the materials may, for example, degrade and/or dissolve) at the appropriate time under the encountered conditions may also be employed in the methods of the present disclosure. For example, polyols containing three or more hydroxyl groups may be used. Suitable polyols include polymeric polyols that solubilizable upon heating, desalination or a combination thereof, and contain hydroxyl-substituted carbon atoms in a polymer chain spaced from adjacent hydroxyl-substituted carbon atoms by at least one carbon atom in the polymer chain. The polyols may be free of adjacent hydroxyl substituents. In some embodiments, the polyols have a weight average molecular weight from about 5000 to about 500,000 Daltons or more, such as from about 10,000 to about 200,000 Daltons.

Further examples of removable materials include polyhdroxyalkanoates, polyamides, polycaprolactones, polyhydroxybutyrates, polyethyleneterephthalates, polyvinyl alcohols, polyethylene oxide (polyethylene glycol), polyvinyl acetate, partially hydrolyzed polyvinyl acetate, and copolymers of these materials. Polymers or co-polymers of esters, for example, include substituted and unsubstituted lactide, glycolide, polylactic acid, and polyglycolic acid. For example, suitable removable materials for use as diverting agents include polylactide acid; polycaprolactone; polyhydroxybutyrate; polyhydroxyvalerate; polyethylene; polyhydroxyalkanoates, such as poly[R-3-hydroxybutyrate], poly[R-3-hydroxybutyrate-co-3-hydroxyvalerate], poly[R-3-hydroxybutyrate-co-4-hydroxyvalerate], and the like; starch-based polymers; polylactic acid and copolyesters; polyglycolic acid and copolymers; aliphatic-aromatic polyesters, such as poly(ε-caprolactone), polyethylene terephthalate, polybutylene terephthalate, and the like; polyvinylpyrrolidone; polysaccharides; polyvinylimidazole; polymethacrylic acid; polyvinylamine; polyvinylpyridine; and proteins, such as gelatin, wheat and maize gluten, cottonseed flour, whey proteins, myofibrillar proteins, caseins, and the like. Polymers or co-polymers of amides, for example, may include polyacrylamides.

Removable materials, such as, for example, degradable and/or dissolvable materials, may be used in the diverting agent at high concentrations (such as from about 201bs/1000gal to about 10001bs/1000gal, or from about 401bs/1000gal to about 7501bs/1000gal) in order to form temporary plugs or bridges. The removable material may also be used at concentrations at least 4.8 g/L (40 lbs/1,000 gal), at least 6 g/L (50 lbs/1,000 gal), or at least 7.2 g/L (60 lbs/1,000 gal). The maximum concentrations of these materials that can be used may depend on the surface addition and blending equipment available.

Suitable removable diverting agents also include dissolvable materials and meltable materials (both of which may also be capable of degradation). A meltable material is a material that will transition from a solid phase to a liquid phase upon exposure to an adequate stimulus, which is generally temperature. A dissolvable material (as opposed to a degradable material, which, for example, may be a material that can (under some conditions) be broken in smaller parts by a chemical process that results in the cleavage of chemical bonds, such as hydrolysis) is a material that will transition from a solid phase to a liquid phase upon exposure to an appropriate solvent or solvent system (that is, it is soluble in one or more solvent). The solvent may be the carrier fluid used for fracturing the well, or the produced fluid (hydrocarbons) or another fluid used during the treatment of the well. In some embodiments, dissolution and degradation processes may both be involved in the removal of the diverting agent.

Such removable materials, for example dissolvable, meltable and/or degradable materials, may be in any shape: for example, powder, particulates, beads, chips, or fibers. When such material is in the shape of fibers, the fibers may have a length of about 2 to about 25 mm, such as from about 3mm to about 20mm. The fibers may have any suitable denier value, such as a denier of about 0.1 to about 20, or about 0.15 to about 6.

Examples of suitable removable fiber materials include polylactic acid

(PLA) and polyglycolide (PGA) fibers, glass fibers, polyethylene terephthalate (PET) fibers, and the like.

In some embodiments, the diverting agent content may include pre-processed fiber flocks, which represent solids entrapped inside a fiber network.

The high-loading stream may have a higher loading of materials than the diluted stream, and thus the diversion slurry will have a loading proportional to the amounts of materials and flow rates from each stream being combined. In the diversion slurry, for example, the loading of any one or total amount of any or all of the carrier fibers, bridging fibers, proppant and other particulates, where each is present, in some embodiments may be in the range of from about 2.4 g/L (20 lbs/1000 gal) to about 120 g/L (1000 lbs/1000 gal), or from about 4.8 g/L (40 lbs/1000 gal) to about 90 g/L (750 lbs/1000 gal), e.g., concentrations at least 4.8 g/L (40 lbs/1000 gal), at least 6 g/L (50 lbs/1000 gal), or at least 7.2 g/L (60 lbs/1000 gal).

As shown in FIG. 1, a system for pumping a fluid may include a pumping system 200 for pumping a fluid from a surface 118 of a well 120 to a wellbore 122 during an oilfield operation. The operation may be a hydraulic fracturing operation, and the fluid may be a fracturing fluid. The pumping system 200 includes a plurality of water tanks 221, which feed water to a gel maker 223. The gel maker 223 combines water from the water tanks 221 with a gelling agent so as to form a gel. The gel is then transported to a blender 225 where it is mixed with a proppant from a proppant feeder 227 to form a fracturing fluid.

The fracturing fluid is then pumped at a low pressure (such as 0.41-0.82 MPa (60-120 pounds per square inch (psi)) from the blender 225 to plunger pumps 201 via the line 212. Each plunger pump 201 receives the fracturing fluid at a low pressure and discharges it into a common manifold 210 (sometimes called a missile trailer or missile) at a high pressure as shown by the discharge lines 214. The common manifold 210 then directs the fracturing fluid from the plunger pumps 201 to the wellbore 122 via the line 215. A computerized control system 229 may be employed to direct the entire pump system 200 for the duration of the operation.

In such a system, each of the pumps 201 may be exposed to an abrasive proppant of the fracturing fluid. Accordingly, according to embodiments, a split stream configuration may be designed to allow a fracturing fluid to be pumped into the wellbore.

In a split stream configuration, as disclosed in U.S. Pat. No. 7,845,413 to Shampine et al., which is hereby incorporated by reference in its entirety, a pump system can be operated whereby the fluid that is pumped from a well surface to a wellbore is split into a clean side containing primarily water as well as a dirty side containing solids in a fluid carrier. In a fracturing operation, the dirty side may contain a proppant in a fluid carrier, and the clean side would not be exposed to abrasive fluids.

In some embodiments, a split stream configuration is designed to ultimately transport a diverting composition, which may be a diverting slurry, into a wellbore. The diverting composition may be used at some time during a treatment operation, including a hydraulic fracturing or acid fracturing operation. The diverting composition may be injected to partially or fully close a fracture in a subterranean formation so as to perform a diversion operation.

In embodiments, a method for injecting a diverting composition into a subterranean formation may include a split stream configuration. As can be seen in FIG. 2, the diverting composition may be formed at a point prior to injection in the wellbore.

FIG. 2 shows an injecting system 300 for injecting a diverting fluid from a surface 118 of a well 120 to a wellbore 122 during an oilfield operation. The injection may occur by pumping or by another form of introduction. The operation may be for a diverting treatment to be performed at some point during a fracturing or other treatment. The injecting system 300 includes a plurality of water tanks 321, which feed water downstream. The injecting system 300 also includes tank 323, which feeds a viscosifying agent to a blender 325 where it may be mixed with an amount of proppant from proppant tank 327 and an amount of solid to form a diluted stream. In some embodiments, the solid may be in the form of manufactured shapes, which may include degradable fibers, particles, or a combination of the two.

The diluted stream is then pumped at a low pressure (such as 0.41-0.82 MPa (60-120 psi)) from the blender 325 to plunger pumps 301 via the diluted stream line DL. Each plunger pump 301 receives the diverting fluid at a low pressure and discharges it into a common manifold 310.

Additionally, an amount of water from the water tanks 321 may be combined with a gelling agent supplied by tank 323 so as to form a gel. A diverting agent may be included with the gel at diverting agent truck 313 so as to form a high-loading stream. In some embodiments, the diverting agent may include an amount of manufactured shapes, which may be in the form of fibers, particles or flakes. The mixture of the manufactured shapes and the gel may occur by a process such as batch mixing. The resultant mixture formed as the high-loading stream may be in the form of a slurry.

The high-loading stream may pass through the high-loading stream line HL and reach the pumps 301′ whereby the high-loading stream will be mixed and then pumped into the common manifold 310 which may include or be directly or indirectly connected to a high pressure flow line. The pumps 301′ may be high-loading pumps. In the common manifold, the high-loading stream and the diluted stream may then be mixed to form a diverting composition. The common manifold 310 may then direct the diverting composition from the plunger pumps 201 to the wellbore 122 via the line 315. In embodiments, the high-loading stream and the diluted stream may be combined outside of the common manifold 310, such as downstream of the manifold, which may be by connecting iron or by connecting the high-loading streams and the diluted stream at the wellhead.

A computerized control system 329 may be employed to direct the entire pump system 300 for the duration of the operation.

In embodiments, the pumps 301′ may be high pressure pumps such as positive displacement pumps, multi-stage centrifugal pumps or combinations thereof. In some embodiments, the pumps 301′ may be devices capable of injecting a diverting agent in the form of a ball. Thus, the pumps 301′ may be ball injectors, as described in WO 2013/085410 to Lecerf et al., which is hereby incorporated by reference in its entirety. In embodiments where the pumps 301′ are ball injectors, the high-loading stream will include a ball-type diverting agent. The pumps 301′ may also be suitable for injected destructible containers or containers carrying a fluid and intended to be broken mechanically or otherwise at some point during or after injection into a wellbore.

The following description relates to the high-loading stream.

In embodiments, the components of the high-loading stream other than the diverting agent are components of a carrier fluid. The carrier fluid may include water, fresh water, seawater, connate water or produced water. The carrier fluid may also include hydratable gels (such as guars, polysaccharides, xanthan, hydroxy-ethyl-cellulose, or other similar gels), a cross-linked hydratable gel, a viscosified acid (such as a gel-based viscosified acid), an emulsified acid (such as an oil outer phase emulsified acid), an energized fluid (such as an N₂ or CO₂ based foam), and an oil-based fluid including a gelled, foamed, or otherwise viscosified oil.

The carrier fluid may be a brine, and/or may include a brine. The carrier fluid may include hydrochloric acid, hydrofluoric acid, ammonium bifluoride, formic acid, acetic acid, lactic acid, glycolic acid, maleic acid, tartaric acid, sulfamic acid, malic acid, citric acid, methyl-sulfamic acid, chloro-acetic acid, an amino-poly-carboxylic acid, 3-hydroxypropionic acid, a poly-amino-poly-carboxylic acid, and/or a salt of any acid. In embodiments, the carrier fluid includes a poly-amino-poly-carboxylic acid, such as a trisodium hydroxyl-ethyl-ethylene-diamine triacetate, mono-ammonium salts of hydroxyl-ethyl-ethylene-diamine triacetate, and/or mono-sodium salts of hydroxyl-ethyl-ethylene-diamine tetra-acetate, or other similar compositions.

The high-loading stream also contains a diverting agent which may include degradable fibers of manufactured shapes at high loading, generally more than 100lb/1000gal.

In embodiments, the manufactured shapes which may be used may be round particles, such as, for example, particles having an aspect ratio less than about 5, or less than about 3. The particles may be of dimension which are optimized for plugging or diverting, such as disclosed in Potapenko et al. Though some particles may be round in embodiments, the particles may not have to be round. The particles may include some round particles and some particles of other shapes, or may include no round particles at all. In embodiments where the particles include round particles and other shapes, the particles of other shapes may be cubes, tetrahedrons, octahedrons, plate-like shapes (flakes), oval etc.

Also, the particles can include sand, different types of ceramics used for producing proppant, as well as aluminosilicates, such as muscovite mica. In addition, the diverting agent may include mixtures of fibers, sand, particles, film and other similar components.

In embodiments where fibers are included in the high-loading stream, the fibers may be any of inorganic or organic fibrous materials and can be either degradable or stable at bottomhole conditions. Embodiments may include fiber materials such as PLA and PGA fibers, glass fibers, or PET fibers. In embodiments, pre-processed fiber flocks representing solids entrapped inside the fiber network may be included.

The diverting agent may include manufactured shapes that may be made of a swellable material. The swellable materials may be any materials that swell in the presence of hydrocarbons, water or mixtures of thereof. In embodiments, these may include elastomers, swellable resins, swellable polymers, or clays. The materials may be one or more of x-linked polyacrylamides and polyacrylic acid derivatives, smectite clay, bentonite, oil-swellable rubber, water-swellable elastomers and mixtures of thereof.

The swellable materials can be in any form and size, including grains, spheres, fibers, shaped particulates, beads, and balls. The swellable materials may also be degradable or dissolvable in the presence of acids, hydroxides, amines or other reagents. Swelling time of the particles can be also controlled by slowly dissolvable coatings, additives in the base fluid or in the composition of the swellable material as well as by changing temperature.

In embodiments, the diverting agent including the fibers and swellable materials may be suspended in the carrier fluid.

In embodiments, the swellable materials may swell in the plug so that a decrease in the plug conductivity results, which will thereby reduce the rate of fluid penetration in the isolated zone. Control of the plug permeability may be performed by replacement of the fluid that surrounds the plug with the fluid that causes shrinkage of the swelled particles. In embodiments where polyacrylamide particles are used as swellable component and initial swelling happens in a water-based fluid, then shrinkage of the swelled particles may be caused by exposure to organic solvents or brines with high salinity. Hydrocarbons can be also used to case shrinkage of swelled bentonite grains.

Other swellable particles can be modified proppants comprising a proppant particle and a hydrogel coating. The hydrogel coating is applied to a surface of the proppant particle and localizes on the surface to produce the modified proppant.

In some embodiments, the diverting agent may include polylactide resin particles. The polylactide resin can be molded into different shapes and sizes.

The following relates to the diluted stream.

The diluted stream may include a carrier fluid. The carrier fluid may be the same, or may differ from the carrier fluid in the high-loading stream. In embodiments, the diluted stream may include a fluid with a lower viscosity than the fluid in the high-loading stream, which can be obtained by using the same gelling agent as in the high-loading stream, but in lesser quantity.

The diluted stream may contain manufactured shapes, or may not carry any manufactured shape. In embodiments where manufactured shapes are included, such shapes may be the same ones as in the high-loading stream. In such embodiments, the shapes may be included at a lower loading (e.g., a lower concentration) than the shapes in the high-loading stream. Further, the manufactured shapes in the diluted stream may be a shape of a smaller dimension than those in the high-loading stream.

In embodiments, the high-loading stream may contain large degradable particles of a diameter of 4 mesh to 10 mesh or larger. The diluted stream may contain comparatively smaller degradable particles, such as those of diameter 10 mesh to 100 mesh or smaller. In embodiments, the particle size and distribution of particles will be optimized when the high-loading and diluted streams converge.

In embodiments, the diluted stream may contain a material of a shape different than in the high-loading stream. The diluted stream may contain fiber shapes while the high-loading stream may contain particulate shapes, or vice versa. In embodiments, the high-loading stream may contain a variety of shapes, while the diluted stream contains less variety of shape. In some embodiments, the high-loading stream may contain both fibers and particles, while the diluted stream contains fibers. The diluted stream would still contain a lower loading of manufactured shapes than the high-loading stream, when expressed in weight of shaped particles by volume of the stream.

In embodiments, the high-loading stream and the diluted stream are injected into the common manifold at particular rates. The high-loading stream may be injected at about 1 to about 20 bbl/min, or about 5 to about 10 bbl/min, or about 7 bbl/min The diluted stream may be injected at about 1 to about 100 bbl/min, or about 25 to about 100 bbl/min, or about 25 to about 65 bbl/min, or about 43 bbl/min. The total injection rate at the manifold and subsequently into the wellbore will thus be about 2 to about 120 bbl/min, or about 30 to about 100 bbl/min, or about 30 to about 75 bbl/min, or about 50 bbl/min

Then, to complete the operation, a cleaning operation may be performed.

This can include pumping an amount of fiber to clean the lines, then stopping pumping fiber, and then, once the last fraction of proppant has passed the perforations, slowing down the injection rate when squeezing particles through the perforations.

The following example describes a treatment utilizing a diverting composition and method according to one or more embodiments.

A horizontal well is being fractured in sections, with sections delimited by bridge plugs. Each section is 91.4 m (300 ft) long and has 6 0.305 m (1 ft) perforation clusters, separated by 15.2 m (50 ft). Each perforation cluster contains six perforations. The section is being treated with two stages of 36,300 kg (80,000) lbs of proppant, and each stage is separated by injecting a diverting agent which is a mixture of manufactured shapes. The shapes include particles and beads of various size and fibers.

A diverting agent (also referred to as a plugging or diverting pill) in this example includes 22.7 kg (50 lbs) of particles and includes 3.8 kg (8.4 lbs) of fibers in 795 L (5 bbl) of 3 g/L (25 ppt) linear gel. This corresponds to 11.3 g/L (238 ppt) of particles and 0.48 g/L (40 ppt) of bridging fiber. The high-loading stream is injected into the line connecting the manifold to the wellhead (i.e., downstream of the manifold, identified as line 315 in FIG. 2) at about 1100-1300 L/min (about 7-8 bbl/min) while the diluted stream is injected at about 6700-6800 L/min (42-43 bbl/min) to bring the total injection rate to 7950 L/min (50 bbl/min) The diversion slurry derived as a result of the combination of the high-loading stream and the diluted stream has a volume of 1500 L (36 bbl), a particle loading of 4 g/L (33.3 ppt), and a total fiber (carrier and bridging) loading of 6 g/L (50 ppt).

The high-loading stream is prepared in a mixing tub of a cement mixing/blender float. Thirty minutes before the last fraction of proppant enters the wellbore, diverting material is added in the batch mixer. Specifically, the mixing tub is filled with 795 L (5 bbl) of water gelled with 11.3 kg (25 lbs) of linear gel. Into this 3.8 kg (8.4 lbs) of fiber are mixed. Then, 22.7 kg (50 lbs) of a particulate blend are added to achieve a desired concentration, and the stream is then mixed.

To pump the diverting agent in the high-loading stream, once the last fraction of proppant has passed the pump, the proppant is cut and 3180 L (20 bbl) of crosslinked fluid is injected. Then, the crosslinker is cut and 3180 L (20 bbl) of linear gel is injected.

To prepare the diluted stream, at a pod blender (which is disposed at a low pressure side of the diluted stream), a dry additive feeder may be set to 22.7 kg (50 lbs) of fiber /3785 L (1000 gal) of a 0.24 g/L (20 ppt) linear gel. The rate of the diluted stream is set to 6700-6800 L/min (42-43 bbl/min) so that the total rate of diversion slurry (the high-loading stream and the diluted stream) equals 7950 L/min (50 bbl/min)

As can be seen in FIG. 3, the diluted stream is pumped at a rate of 6800 L/min (43 bbl/min), whereas the high-loading stream, mixed in a batch mixed, is pumped at a rate of 1100 L/min (7 bbl/min) The total pumping rate is 7900 L (50 bbl/min) once the streams are combined to form the diverting composition or slurry.

To mix the high-loading stream with the diluted stream, the high-loading stream is pumped as fast as possible on a dedicated pump, or may be supplied to one of the pumps that is otherwise used for the diluted stream, while maintaining rate of other fracturing pumps.

After the mixing of the high-loading stream with the diluting stream, a cleaning operation including pumping at least 795 L (5 bbl)or at least 1590 L (10nnl) from linear gel to clean the lines that were used to pump the high-loading stream is performed. Then, the fiber pumping through the high-loading stream lines is stopped, and once the last fraction of proppant has passed the perforations, the injection rate is slowed to 3180 L/min (20 bbl/min) when squeezing particles through the perforations.

As shown in FIG. 4, the diverting composition or slurry according to the embodiments described herein allows for an observed pressure when the diverting composition hits the perforation ranges to be from 3.1 to 21.4 MPa (450 to 3100 psi). At stage #10, when the pressure increase reaches an amplitude of 24.1 MPa (3500 psi), the pressure went down sharply and stabilized at a pressure gain of 15 MPa (2180 psi). This shows that the pressure increased by 24.1 MPa (3500 psi), when the diverter hit the perforations. The pressure went down sharply later on, but still remained very high. Overall, the gain in treatment pressure shows that perforation clusters were plugged effectively using the diverting composition.

In the following examples relating to non-bridging and/or proppant-carrying fibers, slickwater and low viscosity linear guar fluids were prepared from tap water. The slickwater contained 1 mL/L (1 gpt) of a concentrated friction reducer solution. Then, depending on the test, two types of linear guar fluids were prepared:

• In the model static settling test in cylinder used in example 1, a fluid A was used, it contained linear guar fluid containing 5.4 g/L (45 ppt) guar and 0.48 kg/L (4ppa) of 12/18 mesh proppant were used, these proppant was obtained from CARBOPROP™ from Carboceramics (Houston, Tex., USA);
• In the settling test in narrow slot used in example 2, a fluid B was used, it contained a linear gel containing 2.4 g/L (20 ppt) guar and 0.12 to 0.24 kg/L (2 ppa) of 40/70 mesh proppant were used, these proppant were BADGER™ sand from Badger Mining Corporation (Berlin, Wis., USA).

The fibers used in the following examples were polylactic acid fibers that were obtained from Trevira GmbH (Germany). Both mid and low temperature resistant fibers were used, the mid temperature fibers generally being useful in treatments with a formation temperature in the range of 94-149° C., and the low temperature resistant fibers at 60-93° C., of those tested in these examples. The fibers were straight (uncrimped), or low crimp (4-5 crimps/cm) or high crimp (>5 crimps/cm, e.g., 8-15 crimps/cm). In the fibers evaluated in these examples, the low crimp fibers performed well in terms of bridging resistance and inhibiting proppant settling at lower fiber loadings. Fibers with diameters from 8 to 13 microns and lengths from 3 to 12 mm were evaluated, and of those tested in these examples, the fibers with a diameter of 8-9.5 microns and a length of 6 mm performed well in terms of bridging resistance and inhibiting proppant settling at lower fiber loadings. The characteristics of the fibers used and other examples of suitable fibers in some embodiments are identified in Table 1.

TABLE 1
Fibers used in experimental tests and other exemplary fibers.
	Fiber	Hydrolysis T		Diameter,	Length,
	ID	Range	Crimps/cm	microns	mm
	NF1	Mid	0	13	6
	NF2	Low	0	12	6
	CF1	Mid	Low	10	4
	CF2	Mid	Low	10	6
	CF3	Mid	Low	10	8
	CF4	Mid	Low	10	12
	CF5	Mid	Low	12	4
	CF6	Mid	Low	12	6
	CF7	Mid	Low	12	8
	CF8	Mid	Low	12	12
	CF9	Low	Low	10	4
	CF10	Low	Low	10	6
	CF11	Low	Low	10	8
	CF12	Low	Low	10	12
	CF13	Low	High	10	4
	CF14	Low	High	10	6
	CF15	Low	High	10	8
	CF16	Low	High	10	12
	CF17	Low	Low	12	4
	CF18	Low	Low	12	6
	CF19	Low	Low	12	8
	CF20	Low	Low	12	12
	CF21	Low	High	12	4
	CF22	Low	High	12	6
	CF23	Low	High	12	8
	CF24	Low	High	12	12

FIGS. 6 to 13 are the results of test obtained with the proppant settling cylinder test.

The model proppant settling test involved placing the fluid in a graduated cylinder and recording the upper level of dispersed proppant in the fluid. The upper level of dispersed proppant was recorded at periodic time intervals, e.g., 0, 10, 30, 60, 90 and 120 minutes while maintaining settling conditions. The proppant settling fraction was calculated as:

$\mathrm{Proppant}\mathrm{settling}=\frac{\begin{array}{c}\left[\mathrm{initial}\mathrm{proppant}\mathrm{level}\left(t=0\right)\right]-\\ \left[\mathrm{upper}\mathrm{proppant}\mathrm{level}\mathrm{at}\mathrm{time}n\right]\end{array}}{\begin{array}{c}\left[\mathrm{initial}\mathrm{proppant}\mathrm{level}\left(t=0\right)\right]-\\ \left[\mathrm{final}\mathrm{proppant}\mathrm{level}\left(t=\infty \right)\right]\end{array}}$

Concerning the bridging screen test apparatus used is seen in FIGS. 5A and 5B. The fluid being tested was pumped through the apparatus at a flow rate of 10-500 mL/min for a period of at least 1 minute (at the end of the time period the total volume of fluid pumped was 500 mL). Formation of a fiber plug in the slot (1-2 mm) was indicated by a pressure rise. Bridging tests using the test apparatus of FIGS. 5A and 5B were conducted without proppant unless otherwise noted. The fluid was recorded as negative for bridge formation if no plug was formed.

A narrow fracture flow test apparatus was also employed for more in depth analysis. The narrow fracture flow test apparatus employed parallel glass panes with a length of 3 m, height of 0.5 m and width of 2 mm for visualization of the fluid and proppant at a flow rate up to 50 L/min. The narrow fracture flow tests were run with L-, T- and X-shape slot orientation.

EXAMPLE 1

Proppant Settling. In this example, fluid A was used. The tests were made to compare one fiber with another, and estimate the behavior of any new fiber as a proppant settling inhibitor. The tests were made in a linear gel since settling test in a slickwater type of fluid may not be representative as the settling may occur immediately.

A fluid with 0.48 g/L of fibers NF1-NF2 and CF1-CF 24 with 0.48 kg/L (4 ppa) proppant was prepared. The data which are shown in FIG. 6 indicate the crimped fibers inhibited proppant settling better than the uncrimped fibers.

The qualitative results in FIGS. 7 and 8 indicate that the mid temperature fiber CF2 (10 microns/6 mm) and the low temperature fiber CF10 (10 microns/6 mm) indicate the fiber loading was reduced by 25% using the crimped fibers in place of the uncrimped fibers NF 1 and NF2, respectively. The results in FIGS. 9 and 10 indicate that 10 micron diameter fibers inhibit inhibited proppant settling to a greater extent than the 12 micron fibers. The results in FIGS. 11 and 12 indicate that 6 mm long fibers provided more or equivalent proppant settling inhibition relative to 4, 8 and 12 mm fibers. The results in FIG. 13 show that low crimp fibers provided better inhibition of proppant settling than high crimp fibers. The data generally show CF2 and CF10 (10 micron, 6 mm, low crimp) had the best settling inhibition characteristics.

Due to the difficulty of applying static proppant settling test in cylinder to slickwater due to immediate settling, experiments on proppant settling in narrow slot in static conditions were not run on this test equipment, however, experiments with fluid B that has a lower viscosity were run to confirm the findings evidenced from the cylinder test with linear gel A. The results are available in FIG. 14 and confirm the tendencies observed.

EXAMPLE 2

Fiber Bridging in Low Viscosity Guar Fluid. In this example, the fluid B was prepared, it contained a linear guar fluid, 2.4 g/L (20 ppt) guar, at 4.8 g/L (40 ppt) of fibers NF1, CF10 and CF14 without proppant. The bridge screening test results are presented in Table 2.

TABLE 2
Screening Bridge Testing.
	Linear	Fiber	Fiber	Fiber
Flow rate,	velocity,	NF1	CF10	CF14
mL/min	cm/s	(uncrimped)	(low crimp)	(high crimp)
10	0.57	Bridged	Bridged	Bridged
50	2.86	Bridged	Bridged	Bridged
75	4.29	Bridged	Bridged	Bridged
100	5.72	Bridged	Bridged	Bridged
150	8.59	Bridged	No Bridge	Bridged
200	11.4	Bridged	No Bridge	No Bridge
250	14.3	Bridged	No Bridge	No Bridge
300	17.2	Bridged	No Bridge	No Bridge
350	20.0	No Bridge	No Bridge	No Bridge

The foregoing data show that fibers can be used in fracturing treatments using slickwater and linear gels having a low viscosity. With the appropriate fiber selection, bottom hole temperatures of 60-204° C. (140-400° F.) may be applicable. The fibers provide better proppant transport and reduced settling with reduced water requirements (higher proppant loading), reduced proppant requirements (better proppant placement) and reduced power requirements (lower fluid viscosity and less pressure drop). The fibers may increase proppant transport in a low viscosity fluid. The fibers may be degradable after placement in the formation. The fibers can be used in hybrid treatments such as heterogeneous proppant placement and/or pulsed proppant and/or fiber pumping operation modes.

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 are within the scope of the appended claims.

Claims

1. A treatment method, comprising:

introducing a diluted stream, comprising a non-bridging amount of carrier fibers in a low viscosity carrier fluid, into a high pressure flow line;

adding proppant to the diluted stream to form a proppant-laden stream;

injecting the proppant-laden stream from the high pressure flow line into a first fracture;

introducing a high-loading stream, comprising a diverting agent, into the high pressure flow line to combine with the diluted stream to form a diversion slurry;

delivering the diversion slurry from the high pressure flow line to the first fracture to divert fluid flow to a second fracture; and

injecting the proppant-laden stream from the high pressure flow line into the second fracture.

2. The method of claim 1, wherein the diluted stream comprises from 1.2 to 12 g/L of the carrier fibers based on the total volume of the diluted stream (from 10 to 100 ppt, pounds per thousand gallons of carrier fluid).

3. The method of claim 1, wherein the high-loading stream comprises a low viscosity carrier fluid and the diverting agent comprises from 1.2 to 12 g/L (from 10 to 100 ppt) of bridging fibers based on the total volume of the high-loading stream, and from 1.2 to 180 g/L (10 to 1500 ppt) of manufactured shape particles based on the total volume of the high-loading stream.

4. The method of claim 1, comprising stopping the addition of the proppant to the diluted stream during the introduction of the high-loading stream into the high pressure flow line and delivery of the diversion slurry for the diversion to the second fracture.

5. The method of claim 1, comprising interrupting the addition of the proppant to the diluted stream during delivery of the diversion slurry to the first fracture and resuming the addition of the proppant to the dilute stream for the injection of the proppant-laden stream to the second fracture.

6. The method of claim 1, further comprising maintaining a continuous fluid flow of the diluted stream to the high pressure flow line from an end of the injection of the proppant-laden stream to the first fracture, through the delivery of the diversion slurry and to an initiation of the injection of the proppant-laden stream to the first fracture.

7. The method of claim 1, further comprising injecting one or more spacer stages to separate the proppant-laden stream injected into the first fracture from the diversion slurry, to separate the diversion slurry from the proppant-laden stream injected into the second fracture, or both.

8. The method of claim 1, wherein the proppant-laden streams are slickwater.

9. The method of claim 1, wherein the carrier fiber is dispersed in the diluted stream in an amount effective to inhibit settling of the proppant in the proppant-laden streams.

10. The method of claim 1, wherein the diluted stream comprises equal to or less than 4.8 g/L of the carrier fibers based on the total volume of the diluted stream (less than 40 ppt).

11. The method of claim 1, wherein the carrier fibers are crimped staple fibers.

12. The method of claim 1, wherein the carrier fibers are crimped staple fibers comprising from 1 to 10 crimps/cm of length, a crimp angle from 45 to 160 degrees, an average extended length of fiber of from 3 to 15 mm, a mean diameter of from 8 to 40 microns, or a combination thereof.

13. The method of claim 1, wherein the carrier fibers are crimped staple fibers comprising crimping equal to or less than 5 crimps/cm of fiber length.

14. The method of claim 1, wherein the carrier fibers comprise polyester.

15. The method of claim 1, wherein the carrier fibers comprise polyester wherein the polyester undergoes hydrolysis at a low temperature of less than 93° C. as determined by heating 10 g of the fibers in 1 L deionized water until the pH of the water is less than 3.

16. The method of claim 1, wherein the carrier fibers comprise polyester wherein the polyester undergoes hydrolysis at a moderate temperature of between 93° C. and 149° C. as determined by heating 10 g of the fibers in 1 L deionized water until the pH of the water is less than 3.

17. The method of claim 1, wherein the carrier fibers comprise polyester wherein the polyester is selected from the group consisting of polylactic acid, polyglycolic acid, copolymers of lactic and glycolic acid, and combinations thereof.

18. The method of claim 1, wherein the carrier fiber is selected from the group consisting of polylactic acid (PLA), polyglycolic acid (PGA), polyethylene terephthalate (PET), polyester, polyamide, polycaprolactam and polylactone, poly(butylene) succinate, polydioxanone, glass, ceramics, carbon (including carbon-based compounds), elements in metallic form, metal alloys, wool, basalt, acrylic, polyethylene, polypropylene, novoloid resin, polyphenylene sulfide, polyvinyl chloride, polyvinylidene chloride, polyurethane, polyvinyl alcohol, polybenzimidazole, polyhydroquinone-diimidazopyridine, poly(p-phenylene-2,6-benzobisoxazole), rayon, cotton, cellulose and other natural fibers, rubber, and combinations thereof.

19. The method according to claim 1, wherein the high-loading stream is introduced into the high pressure flow line at about 5 to about 10 bbl/min.

20. The method according to claim 1, wherein the diluted stream is introduced into the high pressure flow line at about 25 to about 100 bbl/min.

21. The method according to claim 1, wherein the diversion slurry is delivered to the first fracture at about 30 to about 100 bbl/min.

22. A treatment method, comprising:

introducing a diluted stream, comprising a non-bridging amount of carrier fibers, from a diluted fluid device to a high pressure flow line;

introducing a high-loading stream, comprising a mix of bridging fibers and manufactured shape particles, from a high-loading fluid device to the high pressure flow line;

combining the diluted stream and the high-loading stream to form a diversion slurry;

delivering the diversion slurry from the high pressure flow line to a downhole fluid flow feature to divert fluid flow from the downhole fluid flow feature to an alternate flow path.

23. The method of claim 22, wherein the diluted stream comprises a low viscosity carrier fluid having a viscosity less than 50 mPa-s at a shear rate of 170 s−1 and a temperature of 25° C., and from 1.2 to 12 g/L of the carrier fibers based on the total volume of the diluted stream (from 10 to 100 ppt, pounds per thousand gallons of carrier fluid).

24. The method of claim 22, wherein the high-loading stream comprises a carrier fluid having a viscosity less than 50 mPa-s at a shear rate of 170 s−1 and a temperature of 25° C., from 1.2 to 12 g/L (from 10 to 100 ppt) of the bridging fibers based on the total volume of the high-loading stream, and from 1.2 to 180 g/L (10 to 1500 ppt) of the manufactured shape particles based on the total volume of the high-loading stream.

25. The method of claim 22, wherein the diversion slurry comprises a carrier fluid having a viscosity less than 50 mPa-s at a shear rate of 170 s−1 and a temperature of 25° C., from 1.2 to 12 g/L (from 10 to 100 ppt) of the total combined carrier and bridging fibers based on the total volume of the diversion slurry, and from 1.2 to 60 g/L (10 to 500 ppt) of the manufactured shape particles based on the total volume of the diversion slurry.

26. The method of claim 22, comprising forming a bridge from the diversion slurry to bridge over the downhole feature.

27. The method of claim 22, comprising forming a plug from the diversion slurry to plug the downhole feature.

28. The method of claim 22, further comprising establishing a flow of the diluted stream into the downhole feature before delivering the diversion slurry, and alternating from the flow of the diluted stream to the diversion slurry.

29. The method of claim 22, further comprising maintaining a continuous fluid flow, comprising establishing a pre-flow of at least a portion of the diluted stream into the downhole feature before delivering the diversion slurry, alternating from the flow of the diluted stream to the diversion slurry, bridging or plugging the downhole feature with the diversion slurry, alternating from the diversion slurry to a post-flow of the diluted stream, and establishing or increasing a fluid flow to the alternate flow path.

30. The method of claim 22, wherein the diluted fluid device and high-loading device are each pumps.

31. The method according to claim 22, wherein the high-loading device is a ball injector.

32. A treatment method, comprising:

injecting a treatment fluid through a high pressure flow line into the subterranean formation to form a hydraulic fracture system, wherein the treatment fluid comprises:

a low viscosity carrier fluid having a viscosity less than 50 mPa-s at a shear rate of 170 s-1 and a temperature of 25° C.;

proppant dispersed in the carrier fluid; and

carrier fiber dispersed in the carrier fluid;

maintaining a rate of the injection of the treatment fluid to avoid bridging in the wellbore;

introducing a diluted stream, comprising a non-bridging amount of the carrier fibers and optionally free of the proppant, to the high pressure flow line;

introducing a high-loading stream, comprising a mix of bridging fibers and manufactured shape particles, to the high pressure flow line;

combining the diluted stream and the high-loading stream to form a diversion slurry, delivering the diversion slurry from the high pressure flow line to the hydraulic fracture system to divert fluid flow from one fracture to another.

33. A system for injecting a treatment fluid, comprising:

at least one diluted fluid device that transports a diluted stream to a high pressure flow line;

at least one high-loading device that transports a high-loading stream to the high pressure flow line to combine with the diluted stream to form a diversion slurry; and

a flow path for the diversion slurry to a downhole feature.