WO2014129924A1 - Methods for heterogeneous proppant placement and reduced fluids loss during fracturing - Google Patents

Methods for heterogeneous proppant placement and reduced fluids loss during fracturing

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Publication number
WO2014129924A1
WO2014129924A1 PCT/RU2013/000141 RU2013000141W WO2014129924A1 WO 2014129924 A1 WO2014129924 A1 WO 2014129924A1 RU 2013000141 W RU2013000141 W RU 2013000141W WO 2014129924 A1 WO2014129924 A1 WO 2014129924A1
Authority
WO
Grant status
Application
Patent type
Prior art keywords
peels
method
disclosed
alternative
treatment
Prior art date
Application number
PCT/RU2013/000141
Other languages
French (fr)
Inventor
Maksim Pavlovich YUTKIN
Szabo Geza Horvath
Mohan Kanaka Raju PANGA
Denis Viktorovich BANNIKOV
Original Assignee
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Holdings Limited
Schlumberger Technology B.V.
Prad Research And Development Limited
Schlumberger Technology Corporation
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date

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Classifications

    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; MISCELLANEOUS COMPOSITIONS; MISCELLANEOUS APPLICATIONS OF MATERIALS
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60Compositions for stimulating production by acting on the underground formation
    • C09K8/92Compositions for stimulating production by acting on the underground formation characterised by their form or by the form of their components, e.g. encapsulated material
    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; MISCELLANEOUS COMPOSITIONS; MISCELLANEOUS APPLICATIONS OF MATERIALS
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60Compositions for stimulating production by acting on the underground formation
    • C09K8/62Compositions for forming crevices or fractures
    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; MISCELLANEOUS COMPOSITIONS; MISCELLANEOUS APPLICATIONS OF MATERIALS
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60Compositions for stimulating production by acting on the underground formation
    • C09K8/80Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25Methods for stimulating production
    • E21B43/26Methods for stimulating production by forming crevices or fractures
    • E21B43/267Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping

Abstract

A method for treating a subterranean formation penetrated by a wellbore, comprising forming a treatment slurry comprising a carrying fluid, particulates and one or more peels; injecting the treatment slurry into a fracture to form a substantially uniformly distributed mixture of the particulates and the peels; and wherein the particulate and the peels have substantially dissimilar sedimentation rates in the fracture is provided

Description

METHODS FOR HETEROGENEOUS PROPPANT PLACEMENT AND REDUCED

FLUIDS LOSS DURING FRACTURING

RELATED APPLICATION DATA

[0001] None.

BACKGROUND

[0002] The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.

[0003] Fracturing is used to increase permeability of subterranean formations. A fracturing fluid is injected into the wellbore passing through the subterranean formation. A propping agent (proppant) is injected into the fracture to prevent fracture closing and, thereby, to provide improved extraction of extractive fluids, that is oil, gas or water.

[0004] The proppant maintains the distance between the fracture walls in order to create conductive channels in the formation. Settling of proppant particles, however, can decrease the conductivity in the fracture.

[0005] The loss of the fracturing fluid due to its penetration to the formation is undesirable. The fluid loss increases fracturing cost and causes delay in recovering some part of the escaped fluid from the formation. Further, fluid loss can result in subterranean formation damage; for example, the fracturing water left behind in the small pores of the fractured shales can reduce gas production rates. Presently filling additives are used in the fracturing water, which form a "filtercake" on the surface of the fractures and thus reducing fluid loss. Although this approach mitigates the fluid loss, the filter cake itself reduces production rates and requires complex removal techniques.

SUMMARY

[0006] The disclosed subject matter of the application provides a method for treating a subterranean formation penetrated by a wellbore providing heterogeneous proppant placement and reduced fluids loss during fracturing.

[0007] The disclosed subject matter of the application further provides a composition capable of transforming via settling from a first state of being substantially homogeneously mixed and a second state having portions that are rich of the solid particulates and portions that are substantially free of the solid particulates and having interconnections between the solids-free portions.

[0008] 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.

BRIEF DESCRIPTION OF THE DRAWINGS

[0009] These and other features and advantages will be better understood by reference to the following detailed description when considered in conjunction with the accompanying drawings.

[0010] Fig. 1 schematically illustrates a peel or complex peel within a fracture.

[0011] Fig. 2 schematically illustrates peels in a fracture mediated by a fiber framework.

[0012] Fig. 3 schematically illustrates the orientation of circular peels parallel and perpendicular to a fracture wall.

[0013] Fig. 4 schematically illustrates a side view of a modified experimental slot.

[0014] Fig. 5 is a graph illustrating the percentage of trapped circular peels in a slot with varying step width, with the assumption that all peels are oriented randomly (random angle, three degrees of freedom).

[0015] Fig. 6a schematically illustrates a top view of a lens-like slot and Fig. 6b schematically illustrates a front elevational view of the lens-like slot.

[0016] Fig. 7a schematically illustrates the equipment used for bridging testing and Fig. 7b schematically illustrates the slot present in the equipment shown in Fig. 7a.

[0017] Fig. 8 schematically illustrates a small slot manifold.

DETAILED DESCRIPTION OF SOME ILLUSTRATIVE EMBODIMENTS

[0018] For the purposes of promoting an understanding of the principles of the disclosure, reference will now be made to some illustrative embodiments of the current application. [0019] . Some embodiments of the disclosed subject matter may be described in terms of treatment of vertical wells, but are equally applicable to wells of any orientation. Embodiments may be described for hydrocarbon production wells, but it is to be understood that embodiments may be used for wells for production of other fluids, such as water or carbon dioxide, or, for example, for injection or storage wells. It should also be understood that throughout this specification, when a concentration or amount range is described as being useful, or suitable, or the like, it is intended that any and every concentration or amount within the range, including the end points, is to be considered as having been stated. Furthermore, each numerical value should be read once as modified by the term "about" (unless already expressly so modified) and then read again as not to be so modified unless otherwise stated in context. For example, "a range of from 1 to 10" is to be read as indicating each and every possible number along the continuum between about 1 and about 10. In other words, when a certain range is expressed, even if only a few specific data points are explicitly identified or referred to within the range, or even when no data points are referred to within the range, it is to be understood that the inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that the inventors have possession of the entire range and all points within the range. It should also be understood that fracture closure includes partial fracture closure.

[0020] As used herein, the term hydraulic fracturing treatment means the process of pumping fluid into a closed wellbore with powerful hydraulic pumps to create enough downhole pressure to crack or fracture the formation. This allows injection of proppant-laden fluid into the formation, thereby creating a region of high-permeability sand through which fluids can flow. The proppant remains in place once the hydraulic pressure is removed and therefore props open the fracture and enhances flow into or from the wellbore.

[0021] As used herein, the term void means any open space in a geological formation, including naturally occurring open spaces and open spaces formed between the geological formation and one or more objects placed into the geological formation.

[0022] Treatment slurries may be laboratory tested using artificial voids created between two plates having a space therebetween, or slots. The simulated fracture width may be from 3 to 6 mm and the plates may range from 6 by 8 inches to 40 by 40 inches. The plates are made from a transparent material, such as acrylic glass, so that the settling and distribution of the treatment slurry may be observed over time. Channelization index 0 corresponds to the scenario wherein the treatment slurry inside the void (e.g. hydraulic fracture) is homogeneous and no separation or settling of the solid particulates takes place.

[0023] As used herein, the term "peels" means a particle having 3 dimensions, x, y and z wherein the particle size in dimension z is substantially smaller than the size of at least one of the dimensions y and x. As used herein, substantially smaller means that the particle size in dimension z is at least ten times smaller than the particle size in at least one of the dimensions y and x. For example, if the particle size in the y and x dimensions is 10 mm, the particle size in the z dimension would be 1 mm or smaller.

[0024] In some embodiments, the "peels" further possess at least one attractive interaction with the particulates.

[0025] Attractive interactions include any kind of force which would tend to draw the solid particles into the proximity of the peels, including, for example, hydrophobicity, hydrophilicity, ionic charge, and tackiness. As would be understood, the characteristic of the peel would depend upon the characteristic of the solid particles as well as that of a carrier fluid, if any. The attractive interaction may arise from the surface and/or bulk of the peels. The attractive interaction may be a property inherent to the peel materials or may arise by way of a coating or other treatment applied to the peels, such as a tackifying agent. Attractive interactions can be realized ether by coating peels with organic or inorganic adhesives, such as epoxy resins, silicate glue, urea- formaldehyde resins, and resorcinol resins, or by mechanical embedment in the body of peels. Further, the attractive interaction may be present at all times or alternatively, may be activated or triggered upon some treatment, such as a change in temperature or pressure or the addition of an activating component, such as a pH modifier, polar fluid or solution, surfactant additive, electrolyte, and others.

[0026] In one embodiment, the peels may have an attractive interaction with the particulates along only one dimension of the peel. Alternatively, the peels may have an attractive interaction with the particulates along only two or three dimensions of the peel.

[0027] As used herein, the term "complex peels" means peels which have been coated with particulates and/or having particulates embedded in the bulk of the peels prior to forming the treatment slurry. [0028] As used herein, the term "tacky" in reference to a surface property means that the surface is coated or embedded with one or more tackifying agents, which can be originally active or be activated/triggered by altering the pressure, temperature, or chemical composition of the system. Alternatively, the bulk material of the "peel" is a "tacky material."

[0029] A first embodiment of the disclosed subject matter provides a first method for treating a subterranean formation penetrated by a well bore, comprising forming a treatment slurry comprising a carrying fluid, particulates and one or more peels; injecting the treatment slurry into a fracture to form a substantially uniformly distributed mixture of the particulates and the peels; and wherein the particulate and the peels have substantially dissimilar sedimentation rates in the fracture. As used herein, substantially dissimilar means differing by at least 20%. All values and subranges from at least 20% are included herein and disclosed herein. For example, the sedimentation rates of particulate and peels may differ by at least 20%, or in the alternative, differ by at least 50%, or in the alternative, differ by at least 75%, or in the alternative, differ by at least 100%, or in the alternative, differ by at least 150%.

[0030] A second embodiment of the disclosed subject matter provides a composition, comprising forming a treatment slurry comprising a carrying fluid, optionally particulates and one or more complex peels; and injecting the treatment slurry into a fracture to form a substantially uniformly distributed mixture of the particulates, if present, and the complex peels.

[0031] Carrying fluids suitable for use in embodiments of the disclosed subject matter include any fluid useful in fracturing fluids, including, without limitation, gels, foams, slickwater, energized fluids, and viscoelastic surfactants.

[0032] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the x and z dimensions of the peels and/or complex peels are smaller than the characteristic size of the fracture gap during a fracturing process.

[0033] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the x and z dimensions of the peels and/or complex peels are comparable in size to the characteristic size of the fracture gap.

[0034] In certain embodiments wherein the peels and/or complex peels are comparable in size to the maximum fracture gap, it is anticipated that the particulate covered peels and/or complex peels may become lodged within the maximum fracture gap. Such situation is schematically shown in Fig. 1 . In Fig. 1 , the curved line 1 represents a peel having particulates 2 attracted or attached thereto. The particulate covered peel is lodged in between the fracture walls 3.

[0035] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the peels and/or complex peels have a size in the x and y dimensions of 4 mm and a size in the z dimension of 0.25 mm.

[0036] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the carrying fluid comprises a crosslinked fluid such as a crosslinked polysaccharide and/or crosslinked polyacrilamide. Any appropriate cross linking agent may be used in forming the crosslinked fluid, including, for example, boron and its salts, salts or other compounds of transition metals such as chromium and copper, titanium, antimony, aluminum, zirconium, and organic crosslinkers, such as glutaraldehyde.

[0037] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that at least a portion of the particulates adhere to the one or more peels during the one or more steps of forming the treatment slurry and injecting the treatment slurry.

[0038] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the step of injecting the treatment slurry occurs intermittently and wherein other well treatment fluid is injected into the fracture between the intermittent injections of the treatment slurry. Such intermittent injections are described in U.S. Patent Nos. 6,776,235; 7,581 ,590; and 8,061 ,424, the disclosures of which are incorporated herein by reference in their entireties. For example, U.S. Patent No. 7,581 ,590 describes injecting alternating volumes of proppant-rich fluid and volumes containing a channelant. .

[0039] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the composition of the treatment slurry is modified by changing the concentration of one or more of the peels and particulates during the step of injecting the treatment slurry. Such change of composition may occur stepwise or continuously. That is, in a stepwise change, discrete concentration changes made at discrete times during the injection step. In a continuously changing process, the concentrations may be changed small amounts during the entire or major part of the injection step.

[0040] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that each of the one or more peels or complex peels has size ratios of either y.x and z.x of at least 10. In specific embodiments, the one or more peels or complex peels has size ration of either y:x and z:x of less than 100. For example, the size ration of either y:x and z:x may range from 10 to 1 ,000, or in the alternative, from 15 to 500, or in the alternative, from 10 to 50, or in the alternative, from 10 to 1 50.

[0041] The bulk materials of which the peels and/or complex peels are made may be any material suitable for injection into a subterranean formation. For example, the peel material may be organic or inorganic, crystalline or amorphous, polymeric or monomeric, crosslinked polymer or linear polymer. In yet other embodiments, the peels and/or complex peels may be degradable, self-degradable or stable under subterranean formation conditions.

[0042] The bulk materials of which the peels and/or complex peels are made may be, in alternative embodiments, rigid, flexible, swellable, expandable, contractible, porous, or any appropriate combination thereof.

[0043] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the one or more peels or complex peels are made of one or more materials selected from the group consisting of polylactic acids, nylons, polyhydroxyalkanoates, polyhydroxyalkanoates, polycaprolactones, polyvinyl alcohols, nylons, polyacrylamides, polyethylenes, polyurethanes and polycaprolactones.

[0044] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that there is attractive interaction between more than one surface of the one or more peels and the particulates.

[0045] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the largest dimension of the one or more peels or complex peels is from 10 microns to 20 mm. All individual values and subranges are included and disclosed herein. For example, the largest dimension of the peels and/or complex peels may be from a lower limit of 20 microns, 100 microns, 300 microns, 500 microns, 700 microns, 900 microns, 2 mm, 12 mm or 19 mm to an upper limit of 200 microns, 400 microns, 600 microns, 800 microns, 1 mm, 5 mm, 15 mm or 20 mm. For example, the largest dimension of the peels and/or complex peels may be from 10 microns to 20 mm, or in the alternative, from 50 microns to 20 mm, or in the alternative, from 50 microns to 15 mm, or in the alternative, from 100 microns to 15 mm, or in the alternative, from 100 microns to 20mm.

[0046] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the largest dimension of the one or more peels or complex peels comprises a size distribution.

[0047] Furthermore, peels or complex peels may comprise a mixture or blend of two or more peels or complex peels. For example, the peels or complex peels my comprise a first peel or complex peel type having a first average size, a second peel or complex peel type having a second average size, a third peels or complex peels type having a third average particle size, and so on, wherein the average size refers to an average size in the largest dimension. In addition, the largest dimensions of peels or complex peels may also form a one or more size distributions.

[0048] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the sedimentation rate of the treatment slurry is no greater than 0.7 of the sedimentation rate of a treatment slurry comprising the particulate in the absence of any peels. All individual values and subranges from no greater than 0.7 of the no peel sedimentation rate are included and disclosed herein. For example, the sedimentation rate of the treatment slurry may be no greater than 0.7 of the no peel sedimentation rate, or in the alternative, no greater than 0.65 of the no peel sedimentation rate, or in the alternative, no greater than 0.6 of the no peel sedimentation rate.

[0049] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the treatment slurry further comprises fibers. Without being bound to any particular theory, it is currently believed that when fibers are present, the fibers create a framework inside fracture with the peels serving as a mediator between the framework and proppant, thereby spreading efficiently the weight of proppant over the framework. Such hypothecated structure is schematically illustrated in Fig. 2, wherein a fracture is viewed from the top, having fracture walls 4, a fiber network made of a plural ity of fibers 6 mediated by a plurality of circular peels 8 on which solid particulate 10 is attached or attracted.

[0050] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the concentration of fibers in the treatment slurry is from 2 to 30 ppt. All values and subranges from 2 to 30 ppt are included and disclosed herein. For example, the concentration of fibers in the treatment slurry may be from a lower limit of 2, 3, 4, 5, 6, 7, 8 or 9 ppt to an upper limit of 10, 12, 15, 1 8, 2025 or 30 ppt. For example, the concentration of fibers in the treatment slurry may be from 2 to 30 ppt, or in the alternative, from 5 to 15 ppt, or in the alternative, from 2 to 20 ppt, or in the alternative, from 2 to 30 ppt.

[0051] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the concentration of fibers in the treatment slurry is sufficiently low so as to be unable to sustain the particulates.

[0052] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the peels have a zero sedimentation rate. Without being bound to any particular theory, it is currently believed that a zero sedimentation rate may occur, at least in part, due to interactions between the peels and the walls of the fracture, fibers and/or polymeric components. Alternatively, a zero sedimentation rate may arise, in part, from the peels having a density comparable to the carrier fluid.

[0053] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the treatment slurry further comprises one or more polymeric components selected from crosslinked polymers and linear polymers. Without being bound to any particular theory, it is currently believed that because crosslinked polymers have better carrying abilities than water, peels loaded with proppant transmit stress to the fluids with carrier abilities more efficiently than that of bare proppant. [0054] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the treatment slurry further comprises one or more crosslinked polymers at a concentration from 5 to 20 pounds per one thousand gallons ("ppt"). All individual values and subranges from 5 to 20 ppt are included and disclosed herein. For example, the concentration of crosslinked polymers may be from a lower limit of 5, 7, 9, I I , 13, 15, 17 or 19 ppt to an upper limited of 6, 8, 10, 12, 14, 16, 1 8 or 20 ppt. For example, the concentraction of the crosslinked polymers may be from 5 to 20 ppt, or in the alternative, from 5 to 1 2 ppt, or in the alternative, from 12 to 20 ppt, or in the alternative, from 8 to 1 5 ppt.

[0055] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the treatment slurry further comprises one or more linear polymers at a concentration from 5 to 30 ppt. All individual values and subranges from 5 to 30 ppt are included and disclosed herein. For example, the concentration of linear polymers may be from a lower limit of 5, 9, 13, 1 7, 21 , 24, or 27 ppt to an upper limited of 6, 10, 14, 1 8, 22, 26 or 30 ppt. For example, the concentraction of the linear polymers may be from 5 to 30 ppt, or in the alternative, from 5 to 1 8 ppt, or in the alternative, from 18 to 30 ppt, or in the alternative, from 12 to 25 ppt.

[0056] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the concentration of polymeric components is sufficiently low so as to be unable to sustain the particulates.

[0057] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the slurry or composition further comprises one or more breaker additives for reducing the viscosity of the liquid phase.

[0058] The particulates may have any size or size distribution in the range from 10 nm to 5 mm. All values and subranges from 10 nm to 5 mm are included and disclosed herein. For example, the particulates may have a size from 10 nm to 5 mm, or in the alternative, from 10 nm to 0.001 mm, or in the alternative, from 0.001 mm to 5 mm, or in the alternative, from 0.0005 mm to 5 mm, or in the alternative, from 1000 nm to 1 mm.. [0059] Any particulate useful in well treatment fluids may be used. Particulates include but are not limited to, sand, walnut shells, sintered bauxite, glass beads, ceramic materials, naturally occurring materials, or similar materials. Mixtures of proppants can be used as well. If sand is used, it may be from about 20 to about 100 U.S. Standard Mesh in size. With synthetic proppants, mesh sizes about 8 or greater may be used. Naturally occurring materials may be underived and/or unprocessed naturally occurring materials, as well as materials based on naturally occurring materials that have been processed and/or derived. Suitable examples of naturally occurring particulate materials for use as proppants include: ground or crushed shells of nuts such as walnut, coconut, pecan, almond, ivory nut, brazil nut, etc.; ground or crushed seed shells (including fruit pits) of seeds of fruits such as plum, olive, peach, cherry, apricot, etc.; ground or crushed seed shells of other plants such as maize (for example, corn cobs or corn kernels); processed wood materials such as those derived from woods such as oak, hickory, walnut, poplar, mahogany, etc. including such woods that have been processed by grinding, chipping, or other form of particulation, processing, etc.

[0060] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the particulate comprises sand with particle sizes from 1 micron to 1000 microns.

[0061] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the particulates comprise a mixture or blend of two or more particulate. For example, the solid particulates my comprise a first particulate type having a first average particle size, a second particulate type having a second average particle size, a third particulate type having a third average particle size, and so on.

[0062] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that, some or all of the particulates are made of degradable, meltable, soluble or dissolvable materials.

[0063] In another embodiment, the treatment slurry further comprises one or more agent(s) that accelerate or control degradation of degradable particulates. For example, CaC03 and Ca(OH)2 may be added to the treatment slurry to control degradation of particulate materials comprising polylactic acid. Likewise, an acid, such as for example, organic acids, including for example formic acid, or a mineral acid, including for example, hydrochloric acid, may be used to accelerate degradation for particulate materials comprising polyamides.

[0064J In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the peels and/or complex peels comprise a material selected from the group consisting of polylactic acid, polyester, polyamide, polyglycolic acid, polyterephthalate, cellulose, wool, basalt, glass, rubber, or a combination thereof.

[0065] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the injecting is achieved by pumping the treatment slurry under a pressure sufficient to create the fracture or maintain the fracture open in the subterranean formation.

[0066] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the carrying fluid exhibits Newtonian or non-Newtonian (e.g., Herschel-Bulkley, Bingham, power law) flow.

[0067] In an alternative embodiment, the disclosed subject matter provides a first method and a second method in accordance with any of the embodiments disclosed herein, except that the viscosity of the carrying fluid during injection into a void may be different from the viscosity of the carrying fluid following placement into the void.

[0068] In another alternative embodiment, the disclosed subject matter is a third method for treating a subterranean formation penetrated by a wellbore, comprising: forming a treatment slurry comprising a carrying fluid, and one or more peels, and optionally, particulates; injecting the treatment slurry into a fracture to form a substantially uniformly distributed mixture of the particulates and the peels; thereby reducing fluid loss in the fracture. Without being bound by any particular theory, it is currently believed that as the peels are driven by the hydrodynamic forces of fluid leak-off to the formation, the peels are eventually situated on the surface of the fracture and that the peel orientation is mostly parallel with the fracture wall. In such position, the peels, which are devoid of any solid particulates may conform at least partially to the fracture surface thereby blocking fracture openings and reducing fluid leakoff. [0069| In an alternative embodiment, the third method further comprises removing the peels from the fracture.

EXAMPLES

[0070] Any element in the examples may be replaced by any one of numerous equivalent alternatives, only some of which are disclosed in the specification. Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from the concepts described herein. The disclosed subject matter may be embodied in other forms without departing from the spirit and the essential attributes thereof, and, accordingly, reference should be made to the appended claims, rather than to the foregoing specification, as indicating the scope of the disclosed subject matter. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the fol lowing claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures.

[0071] Example 1 Circular peels of 0.4 cm diameter were manufactured from a polymeric material with the following parameters: 1 ) specific gravity ~ 1.35 g/cm3; 2) thickness 0.025 cm; 3) color - red or colorless; and 4) hydrophobic. The peels were sunk in a slot of 100 cm height and 1 cm thickness; the media was water. Settling time over a known distance was measured for

6XT)

30 separate peels. The sedimentation rates (t/d ) were obtained by dividing traveled distance by the time.

[0072] A proppant with 16/30 mesh size (~ 0.1 cm in diameter) and specific gravity 2.84 g/cm3 (commercially available from FORES Ltd. under the name FOREPROP 1630) was chosen and its sedimentation characteristics with respect to the same media were recorded and statistically treated. The obtained mean velocity (UpXp ) was compared with velocity (Upim) calculated by

Stock's equation with lyachko's correlation.

[0073] Table 1 provides the results of the experiments and the calculated values. Proppant particles settle rapidly in water media which is reliably confirmed by theory and experiments (Table 1 , first row). Plastic peels with hindering shape factor settle much slower than proppant particles (Table 1 , second row).

[0074] A number of peels each having a different ratio of proppant:peel were manufactured. A proppant grain was minimally wetted with glue and randomly stuck on a peel. This procedure was repeated to achieve desired proppant:peel ratio. The composite peels were investigated against sedimentation rates (^+ p) the above procedure (Table 1 , column 3). The experiments show similar trend as the calculations, though settling rates are a little higher than the expected ones. Indeed, even a peel covered with 10 proppant particles falls down notably slower than a proppant (compare first row and last row Table 1 ).

[0075] Table 1. Calculation and experiment comparison of settling velocity for proppant and proppant-embedded-peels

Figure imgf000016_0001

[0076] Stock's equation with lyachko's correlation was used

[0077] 2 Happel calibrated model used for calculation [ See in Low Reynolds Number Hydrodynamics with special applications to patriculate media, John Happel, Howard Brenner, Prentice-hall, 1965]

peel nxV, proppant

[0078] 3 p - ppeei X - I" Pproppant ~

" peeiT ,tA "proppant v peel 1+^Μ "^-^ 'pr"o"p"pant ' where n = 9 ± 1 .

[0079] When peel diameter approaches the slit width, peel starts to interact with wall stronger and stronger by means of friction and turbulence. From the other hand, due to increased turbulence at the edges, peels may turn: change their orientation from perpendicular to the walls to parallel to the walls, as shown in Fig. 3. Experiments in which peel diameter was varied in a range from 0.8 to 0.99 to 2.2 times the slot width were conducted. The same procedures as above were used to examine settling behavior of peels with and without proppant. The results for water media are summarized in Table 2. Peels with larger relative diameters (with larger "peel diameter/slot width" ratio) bearing more proppant settle slower than peels with smaller diameter when in an axial orientation. When in a parallel orientation, peels always settle faster than in axial orientation. Increasing peel size proportionally increase settling rate for parallel orientation.

Table 2

Figure imgf000017_0001

[0080] Example 2: In order to demonstrate the effects of wall's roughness on sedimentation rates two points were considered: roughness caused by rock and roughness caused by fracture propagation, namely steps, turns, and T-junctions.

[0081] The walls of 1 cm slot were imprinted by steel mesh with the following parameters: square size 2 mm ± 0.120 mm; wire diameter 1 mm ± 0.020 mm; stainless steel; linen weave. The thickness of the mesh was I mm so the overall slot width was about 0.8 cm. 0.4 cm diameter circular peels loaded with proppant were tested in this slot. Sedimentation rates were determined as described above. The sedimentation rates were about 5% slower than those in the smooth walled slot.

[0082] As illustrated in Fig. 4, another kind of roughness was simulated by placing 3 mm Plexiglas insert 12 on about a half of height of a typical slot 14 having uniform width A. So, the sum of insert thickness and peel diameter is larger than slot width. 1 cm peels with and without proppant were tested in the modified slot. Upon interaction with the step I cm peel either changes its orientation from axial to parallel and starts to settle faster or stacks on the step (get lodged) or passes with no interaction. The general rule bears a probabilistic character and depends on initial orientation, as graphically shown in Fig 5. Each point on the graph corresponds to probability estimation for a million of events. This probability can be increased for more desirable orientations. This can be achieved by unequal proppant placement on the peels so that it will have some degree of slope during settling, which was demonstrated in our experiments. Indeed, peels having shifted center of gravity move unpredictable and always have some slope.

[0083] Example 3: Peels settling in presence of fibers was studied. 10 mm diameter circular peels loaded (assume 50-60% coverage) with proppant ( 16/30; ~ 1 mm avg. size) were sunk in a slot with lens-like cross-section (range from 10 to 12 mm, as schematically illustrated in Fig. 6). The lens-like slot shown in Fig. 6 has a top cross-sectional view as shown in Fig. 6a and a front elevational view as shown in Fig. 6b.Polylactic acid fibers were added to the mixture at concentrations ranging from 1 ppt to 5, 10, 15, and 20 ppt. 1 ppt concentration of fibers did not produce any noticeable network in the container, nor does it impact the sedimentation of peels. Concentration of 5 ppt fibers generated a uniform network though it was not sufficient to support peels. Therefore, the peels settled but at slower rates compared to settling without fibers. 10 ppt of fibers resulted in the peels being lodged in the slot. 15 ppt and 20 ppt concentration of fibers gave results substantially the same as those using 10 ppt fibers. In the case of bare proppant, neither 15 nor 10 ppt could prevent settling.

[0084] Example 4: Similarly to the previous experiments with fibers, settling in low concentrations of cross-linked gel was studied. Cross-linked fluids with the following guar loading were used: 5 ppt, 10 ppt, 15ppt, 20 ppt. The settling was studied in long cylinders with diameter much larger than peel's diameter. At concentrations 5 ppt the gel had very low carrying abilities. Therefore, both proppant and coated peels could settle although peels fully loaded with proppant settled notably slower than bare proppant (around 2 times slower than bare proppant). 10 ppt cross-linked guar gel can support 4 mm peels, while proppant continues settling though rather slow. Both 15 ppt and 20 ppt concentrations demonstrate quite the same abilities to suspend peels and proppant.

[0085] Example 5: Bridging was also examined. Bridging of peels in a fracture is a complicated phenomenon, because it depends on many parameters. Therefore, bridging studies on two different setups were conducted. [0086] First, a typical bridging setup, as illustrated schematically in Fig. 7a was used for bridging tests. The equipment consisted of an accumulator ( 1 " Swagelok tube with volume of about 700 ml) 16 connected to a small I " tube 18 with a slot 20 inside. The slot width was 0.08 inch (2mm). The other end of the accumulator was connected to a Knauer HPLC -1800 pump 22 that provided continuous pumping with rates up to 999 mL/min. The system was equipped with a pressure relief valve (500 psi) 24 and an electronic analog pressure transducer (not shown). Pressure measurements were carried out by using a National Instrument data acquisition system which converted analog pressure readings from the pressure transducer to a numerical format. Fig. 7b provides side sectional and top views of the slot geometry, wherein 65 indicates 65 mm and 75 indicates 75 mm.

[0087] We explicitly showed that bridging in perforations (9 mm in diameter) by 4 mm peels (thickness of peels is 0.25 mm) in the range of concentrations from 0.6 ppa to 1.2 ppa (pound of proppant per gallon of fluid added) is not an issue (i.e., no flow restriction was observed).

[0088] For tests of bridging in slit (corresponds to bridging in narrow fracture) 0.6 ppa of 4 mm peels were suspended in a fluid (saturated solution of CaCl2) with a density of 1.345 g/cc and viscosity about 10 cP. The suspension was pushed through 1 , 2, or 3.5 mm width slits, (having 15 mm height) at 1 L/min and 10 mL/min constant flow rates. The pressure response was recorded and analyzed. In all experiments on this setup, partial block of the flow was observed, resulting in an inability of the peels to flow further.

[0089] In s second set of experiments, a small slot manifold (SSM), schematically shown in Fig. 8 was used. In SSM geometry, both the ability to travel along the narrow fracture and the ability to turn into corners were tested. For SSM experiments, two carrying fluids were used: tap water or cross-linked guar with 15 ppt gel concentration. Concentration of peels was about 0.5-0.6 ppa

[0090] Table 3 gives the results for both types of bridging experiments. The typical bridging setup always showed bridging. In contrast, in the SSM, the peels could successfully turn into corners and pass though narrow fracture (see second row of Table 3). In the SSM setup, the peels were aligned parallel to the walls. In the typical bridging setup, random orientation of the peels was observed. Table 3

Figure imgf000020_0001

[0091] The present invention may be embodied in other forms without departing from the spirit and the essential attributes thereof, and, accordingly, reference should be made to the appended claims, rather than to the foregoing specification, as indicating the scope of the invention.

Claims

Claims
1 . A method for treating a subterranean formation penetrated by a wellbore, comprising: forming a treatment slurry comprising a carrying fluid, particulates and one or more peels; injecting the treatment slurry into a fracture to form a substantially uniformly distributed mixture of the particulates and the peels; and wherein the particulate and the peels have substantially dissimilar sedimentation rates in the fracture.
2. A method for treating a subterranean formation penetrated by a wellbore, comprising: forming a treatment slurry comprising a carrying fluid, optionally particulates and one or more complex peels; and injecting the treatment slurry into a fracture to form a substantial ly uniformly distributed mixture of the particulates, if present, and the complex peels.
2. The method according to claim 1 , wherein at least a portion of the particulates adhere to the one or more peels during the one or more steps of forming the treatment slurry and injecting the treatment slurry.
3. The method according to claim 1 or 2, wherein the step of injecting the treatment slurry occurs intermittently and wherein other well treatment fluid is injected into the fracture between the intermittent injections of the treatment slurry.
4. The method according to claim 1 , wherein a composition of the treatment slurry is modified by changing a concentration of one or more of the peels and particulates during the step of injecting the treatment slurry.
5. The method according to claim 4, wherein the changing of the concentration occurs stepwise or continuously.
6. The method according to claim 1 or 2, wherein the size ratios of each of the one or more peels or complex peels simultaneously satisfies the following conditions (i) y:x > 10, and (ii) z:x > 10.
7. The method according to claim I or 2, wherein the one or more peels or complex peels are made of one or more materials selected from the group consisting of polylactic acids, nylons, polyhydroxyalkanoates, and polycaprolactones.
8. The method according to claim 1 , wherein attractive interaction exists between one or more surfaces of the one or more peels and the particulates.
9. The method according to claim 1 or 2, wherein a largest dimension of the one or more peels or complex peels is from 10 micrometers to 20 mm.
10. The method according to claim 1 or 2, wherein a largest dimension of the one or more peels or complex peels comprise a size distribution.
1 1 . The method according to claim 1 or 2, wherein the one or more peels or complex peels comprises a mixture or blend of two or more peels or complex peels.
12. The method according to claim 1 , wherein a sedimentation rate of the treatment slurry is no greater than 0.7 of the sedimentation rate of a treatment slurry comprising the particulate in the absence of any peels.
13. The method according to claim 1 or 2, wherein the treatment slurry further comprises fibers.
14. The method according to claim 13, wherein a concentration of fibers in the treatment slurry is sufficiently low so as to be unable to sustain the particulates.
15. The method according to claim 1 or 2, wherein the peels have a zero sedimentation rate.
16. The method according to claim 15, wherein the zero sedimentation rate arises at least in part from interaction between the peels or complex peels with the fracture walls.
17. The method according to claim 13, wherein the peels or complex peels have a zero sedimentation rate and further wherein the zero sedimentation arises at least in part from interaction between the peels or complex peels and the fibers.
18. The method according to claim 1 or 2, wherein the peels or complex peels have a zero sedimentation rate and further wherein the zero sedimentation arises at least in part from the density of the peels or complex peels being substantially the same as the density of the carrying fluid.
19. The method according to claim 1 , wherein the treatment slurry further comprises one or more polymeric components selected from crosslinked polymers and linear polymers.
20. The method according to claim 14, wherein the concentration of polymeric components is sufficiently low so as to be unable to sustain the particulates.
21 . A method for treating a subterranean formation penetrated by a wellbore, comprising: forming a treatment slurry comprising a carrying fluid, and one or more peels, and optionally, particulates; injecting the treatment slurry into a fracture to form a substantially uniformly distributed mixture of the particulates and the peels; thereby reducing fluid loss in the fracture.
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Publication number Priority date Publication date Assignee Title
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* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
RU2404359C2 (en) * 2006-01-27 2010-11-20 Шлюмберже Текнолоджи Б.В. Method for hydraulic fracturing of subsurface (versions)

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