WELL TREATMENT

Abstract

A combustible foamed fluid energized with gaseous fuel and combustion oxidant sources. Also, an energized fluid system, a treatment method using the combustible foamed fluid, and a method to prepare the combustible foamed fluid are disclosed.

Description

RELATED APPLICATION DATA

None.

BACKGROUND

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

Foamed fluids, including energized fluids, are often used in downhole applications such as fracturing and other treatments. In some applications it may be desired to quickly break, dissipate, and/or flow back foamed fluids in downhole applications, e.g., to implement fracture closure, or to otherwise rapidly change the properties of the foamed fluid after introducing it into the wellbore.

Foamed fluids may be used in matrix treatments, for example, in the injection of acidizing agents, chelating agents, paraffins, scale inhibitors, and so on.

As another example, foamed fluids are often used as carrying fluids to place proppant and/or other solids into a fracture. The proppant in such applications may be homogeneously or heterogeneously placed in a fracture, or sometimes in a combination of such placement modalities. In US 2014/0262264 by Potapenko et al. (also published as WO 2014/143490A1), incorporated herein by reference, for example, a method for treating a subterranean formation wherein a treatment slurry, which may include a foamed carrying fluid among others, is injected into a fracture to form a substantially uniformly distributed mixture of solid particulate and agglomerant; and transforming the substantially uniform mixture into areas that are rich in solid particulate and areas that are substantially free of solid particulate, wherein the solid particulate and the agglomerant have substantially dissimilar velocities in the fracture so that the transformation results from the substantially dissimilar velocities, e.g., during forced fracture closure or flowback.

The industry is thus desirous of improvements to carrying fluids and/or foamed fluids and/or methods of preparing and using them for various applications.

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.

The present disclosure relates in some embodiments to a combustible foamed fluid energized with a gaseous phase comprising both fuel and combustion oxidant sources, as well as to energized fluid systems, and treatment methods, relating to the combustible foamed fluid, and methods to prepare the combustible foamed fluid.

In some embodiments, a treatment method may comprise introducing downhole a quantity of a treatment fluid comprising a combustible foamed fluid comprising a mixture of a fuel source and a combustion oxidant source, placing the combustible foamed fluid in a downhole structure under non-combustion conditions free of an active ignition source, and thereafter igniting the combustible foamed fluid to combust the fuel source in the downhole structure forming a post-combustion fluid.

In some embodiments, a gas phase of the foam may comprise a mixture of the fuel source and the combustion oxidation source. In some embodiments, the mixture may take the form of a gas phase of homogenous composition dispersed in a continuous liquid phase, and in further embodiments, the gas phase may be heterogeneous, e.g., the fuel source and combustion oxidation source may be separately dispersed or dispersed in mixtures of varying proportions.

In some embodiments, the combustion may decompose the foamed fluid. In some examples, the decomposition may occur such as by vaporizing the liquid phase to an extent that a gas phase or mist is formed, by forming combustion product(s) that condense to liquid(s), or are miscible with the liquid phase, by thermally decomposing a foaming agent, by forming a defoaming agent, or the like, or a combination thereof.

In some embodiments, the method may further comprise cooling the post-combustion fluid to a reduced specific volume relative to the combustible foamed fluid. In some examples, the post combustion fluid may contain a lower proportion of non-condensable, non-soluble gases at the ambient formation pressure and temperature conditions, e.g., a mixture of hydrogen and oxygen will form water, which upon equilibration to ambient formation pressure and temperature conditions and at least partial condensation, will reduce the total volume of the resultant fluid relative to that of the pre-combustion foam.

In some embodiments of the method, the treatment fluid may further comprise proppant and/or the downhole structure may comprise a fracture, e.g., above a fracturing pressure of the formation. In some examples the treatment fluid may be a fracturing fluid, e.g., a pad stage, proppant stage, flush stage, or the like.

In some embodiments, the treatment fluid may further comprise a matrix treatment agent, and/or the downhole structure may comprise a formation matrix, e.g., below a fracturing pressure of the formation.

In some embodiments, the combustion may improve the effectiveness of treatment, reduce flowback volumes, minimize formation damage, accelerate return to production following treatment, or the like.

In some embodiments, the fuel source is selected from hydrogen, hydrocarbon gases, or a mixture thereof, and/or the combustion oxidant source may comprise oxygen, e.g., molecular oxygen, in the form of air, oxygen-enriched air, purified oxygen, oxygen formed by chemical reaction, or the like.

In some embodiments, the combustible foam is prepared at a surface location and introduced into a wellbore, and in other embodiments, the combustion oxidant source is introduced into the wellbore in a first stream separate from a second stream comprising the fuel source, and the first and second streams are mixed downhole to form the combustible foamed fluid.

The present disclosure also relates to embodiments of an energized fluid system comprising a combustible foamed fluid comprising a combustible gaseous mixture dispersed in a continuous liquid phase, a downhole structure to receive the combustible foamed fluid under non-combustion conditions free of an active ignition source, and an ignition source in communication with the downhole structure activatable to initiate combustion of the dispersed gaseous mixture. In some embodiments, the combustible foamed fluid is substantially free of inert gas, e.g., comprised of less than 5 vol % inert gases such as nitrogen, e.g., the mixture may be comprised of oxygen mixed with a fuel source selected from hydrogen, hydrocarbon gases, and the like, including combinations thereof.

In some embodiments, the structure may comprise a wellbore, a fracture, a formation matrix, or the like.

In some embodiments, the ignition source may comprise an igniter, e.g., an electrical or chemical igniter, and/or the energized fluid system may further comprise a controller to activate the ignition source, which controller may automatically activate the ignition source, e.g., after a predetermined time period or at predetermined pressure, temperature, or chemical or other downhole conditions, and/or which may be remotely located, e.g., downhole or at the surface, for remotely activating the ignition source.

The present disclosure also relates to embodiments of a method, comprising dispersing a gaseous fuel source and a gaseous combustion oxidant source into a continuous liquid phase to form a combustible foamed fluid, and isolating the combustible foamed fluid in a downhole structure under non-combustion conditions free of an active ignition source. In some embodiments, the gaseous fuel source and gaseous combustion oxidant may be delivered in separate streams through a wellbore and mixed downhole, or the fuel source and combustion oxidant may be mixed at the surface and the mixture pumped downhole, e.g., in a combustible foam prepared at the surface.

In some other embodiments, the method may comprise passing the liquid phase through an electrolysis cell, either downhole or at the surface, to electrolytically generate the fuel and combustion oxidant sources, e.g., where the liquid phase is aqueous, the gaseous fuel source may be hydrogen, and the gaseous combustion oxidant may be oxygen.

In some embodiments, the downhole structure comprises a fracture above a fracturing pressure, or a formation matrix below the fracturing pressure, or a combination of a fracture and a formation matrix.

BRIEF DESCRIPTION OF THE DRAWINGS

None.

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. Certain statements made in this section may merely provide background information related to the present disclosure, but may not constitute prior art.

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. Terms may also be defined elsewhere in the specification and/or claims.

The term “downhole structure” includes any subterranean arrangement of materials below the surface that may hold, contain, be filled with, or allow the passage of a fluid, such as, without limitation, wellbore, drill pipe or string, tubing, casing, wireline, screen, annulus, fracture, tool, matrix, cavern, lost circulation zone, vug, pores, perforations, and the like. A downhole structure thus refers to any downhole 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 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 or at the surface. The wellbore or other downhole structure may be horizontally or vertically disposed, or sloped.

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. Fracture “creation” includes initiation of a new fracture or fracture branch, as well as propagation and/or expansion of a fracture. The fracturing methods otherwise use techniques known in the art.

“Partial fracturing” refers to the formation of one or especially a plurality fractures formed within a formation which do not communicate directly to the wellbore, or do not connect to a fracture that communicates directly to the wellbore and/or form a part of a fracture network isolated from direct communication to the wellbore.

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.

The terms “combustible fluid,” “auto-combustible fluid,” and similar terms are used interchangeably herein refer to a mixture comprising a combustion-sustaining mix of fuel and oxidant sources, i.e., through which a flame can be propagated in situ by an ignition source without the requirement of exogenous reactants, as in an enclosed container.

The term “combustion” refers to the act or instance of burning of a fuel with an oxidant to release energy, usually in the form of heat and light, and also including the terms “detonation” and “explosion” referring to combustion in which the flame propagation exceeds the acoustic velocity of the reactant media, as well as “ignition” referring to the initiation of combustion.

The term “non-combustion conditions” refers to a stable combustible fluid that is not in fluid communication with a flame or other active ignition source such as a static electrical spark.

The term “ignition source” refers to a composition, device or mechanism capable of initiating combustion of a combustible fluid.

The terms “energized fluid” and “foam” refer to a fluid which when subjected to a low pressure environment liberates or releases gas from solution or dispersion, for example, a liquid containing dissolved gases. Foams or energized fluids are stable mixtures of gases and liquids that form a two-phase system. Foam and energized fluids are generally described by their foam quality, i.e. the ratio of gas volume to the foam volume (fluid phase of the treatment fluid), i.e., the ratio of the gas volume to the sum of the gas plus liquid volumes. If the foam quality is between 52% and 95%, the energized fluid is usually called foam. Above 95%, foam is generally changed to mist. In the present patent application, the terms “energized fluid” and “foam” may be used interchangeably herein, and refer to any stable mixture of gas and liquid, regardless of the foam quality unless context indicates otherwise. Energized fluids comprise any of: (a) Liquids that at downhole conditions of pressure and temperature are close to saturation with a species of gas; for example the liquid can be aqueous and the gas nitrogen or carbon dioxide or hydrogen or oxygen or air or methane or fuel gas, etc.; associated with the liquid and gas species and temperature is a pressure called the bubble point, at which the liquid is fully saturated; at pressures below the bubble point, gas emerges from solution; (b) Foams, consisting generally of a gas phase, an aqueous phase and an optional solid phase; at high pressures the foam quality is typically low (i.e., the non-saturated gas volume is low), but quality (and volume) rises as the pressure falls; additionally, the aqueous phase may have originated as a solid material and once the gas phase is dissolved into the solid phase, the viscosity of solid material is decreased such that the solid material becomes a liquid; or (c) Liquefied gases.

“Viscosity” as used herein unless otherwise indicated refers to the apparent dynamic viscosity of a fluid at a temperature of 25° C. and shear rate of 170 s⁻¹. As used herein, when not used in context relative to a higher viscosity fluid, a “low viscosity” fluid or phase, e.g., a low viscosity carrier or liquid phase, 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.

As used herein, “slurry” refers to an optionally flowable mixture of particles dispersed in a fluid carrier. The terms “flowable” or “pumpable” or “mixable” are used interchangeably herein and refer to a fluid or slurry that has either a yield stress or low-shear (5.11 s⁻¹) viscosity less than 1000 Pa and a dynamic apparent viscosity of less than 10 Pa-s (10,000 cP) at a shear rate 170 s⁻¹, where yield stress, low-shear viscosity and dynamic apparent viscosity are measured at a temperature of 25° C. unless another temperature is specified explicitly or in context of use.

The term “particulate” or “particle” refers to a solid 3-dimensional object with maximal dimension less than 1 meter, or less than 0.1 meter or less than 0.01 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.

In embodiments, the combustible foamed fluid may comprise multimodal particles. As used herein “multimodal” refers to a plurality of particle sizes or modes which each has a distinct size or particle size distribution, e.g., proppant and fines. As used herein, the terms distinct particle sizes, distinct particle size distribution, or multi-modes or multimodal, mean that each of the plurality of particles has a unique volume-averaged particle size distribution (PSD) mode. That is, statistically, the particle size distributions of different particles appear as distinct peaks (or “modes”) in a continuous probability distribution function. For example, a mixture of two particles having normal distribution of particle sizes with similar variability is considered a bimodal particle mixture if their respective means differ by more than the sum of their respective standard deviations, and/or if their respective means differ by a statistically significant amount. In an embodiment, the particles contain a bimodal mixture of two particles; in an embodiment, the particles contain a trimodal mixture of three particles; in an embodiment, the particles contain a tetramodal mixture of four particles; in an embodiment, the particles contain a pentamodal mixture of five particles, and so on. Representative references disclosing multimodal particle mixtures include U.S. Pat. No. 5,518,996, U.S. Pat. No. 7,784,541, U.S. Pat. No. 7,789,146, U.S. Pat. No. 8,008,234, U.S. Pat. No. 8,119,574, U.S. Pat. No. 8,210,249, US 2010/0300688, US 2012/0000641, US 2012/0138296, US 2012/0132421, US 2012/0111563, WO 2012/054456, US 2012/0305245, US 2012/0305254, US 2012/0132421, PCT/RU2011/000971 and U.S. Ser. No. 13/415,025, each of which are hereby incorporated herein by reference.

“Proppant” refers to particulates that are used in well work-overs and treatments, such as hydraulic fracturing operations, to hold fractures open following the treatment. In some embodiments, the proppant may be of a particle size mode or modes in the slurry having a weight average mean particle size greater than or equal to about 100 microns, e.g., 140 mesh particles correspond to a size of 105 microns. In further embodiments, the proppant may comprise particles or aggregates made from particles with size from 0.001 to 1 mm. All individual values from 0.001 to 1 mm are disclosed and included herein. For example, the solid particulate size may be from a lower limit of 0.001, 0.01, 0.1 or 0.9 mm to an upper limit of 0.009, 0.07, 0.5 or 1 mm. Here particle size is defined is the largest dimension of the grain of said particle.

“Gravel” refers to particles used in gravel packing, and the term is synonymous with proppant as used herein. “Sub-proppant” or “subproppant” refers to particles or particle size or mode (including colloidal and submicron particles) having a smaller size than the proppant mode(s); references to “proppant” exclude subproppant particles and vice versa. In an embodiment, the sub-proppant mode or modes each have a weight average mean particle size less than or equal to about one-half of the weight average mean particle size of a smallest one of the proppant modes, e.g., a suspensive/stabilizing mode.

As used herein, proppant loading is specified in weight of proppant added per volume of treatment stream to which it is added, 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 in which they are present (ppt=pounds of material per thousand gallons of treatment fluid).

The term “fiber” refers to elongated particles having an aspect ratio (ratio of length longest dimension to diameter or shortest dimension) of at least 10. 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 fracture. 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. “Bridging fibers” refers to fibers that do not have the non-bridging quality and/or non-bridging fibers used at bridge-inducing loading rates. Carrier fibers may be bridging or non-bridging.

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 21° C. (70° F.) to about 79° C. (175° F.); mid temperatures typically from about 80° C. (176° F.) to about 149° C. (300° F.); and high temperatures typically about 150° C. (302° F.) and above, or from about 150° C. (302° F.) to about 232° C. (450° F.).

As used herein, an agglomerant is any material, such as fibers, flocs, flakes, discs, rods, stars, etc., for example, which may be heterogeneously distributed in the fracture and have a different movement rate, and/or cause some of the first solid particulate to have a different movement rate, which may be faster or preferably slower with respect to the settling of the first solid particulate and/or clusters. As used herein, an agglomerant may also be or include an “anchorant,” referring to a material, a precursor material, or a mechanism, that inhibits movement such as settling, or preferably stops movement, of particulates or clusters of particulates in a fracture, whereas an “anchor” refers to an anchorant that is active or activated to inhibit or stop the movement. As used herein, the term “flocs” includes both flocculated colloids and colloids capable of forming flocs in the treatment slurry stage.

Some embodiments of this disclosure relate to systems and methods to treat a well and/or downhole structure with a foamed fluid comprising a combustible gaseous phase, e.g., for hydraulic fracturing, matrix treatments, wellbore cleanout operations, and the like. Combustion of the fluid as a process feature in some embodiments generally results in an energy release from the exothermic combustion process and a transient temperature, pressure and/or volume increase of the fluid, generally followed by a return to ambient downhole temperature and pressure conditions.

In some specific embodiments, especially where the combustion products may include condensable components such as water and/or a post-combustion gaseous phase of lower volume, an ultimate reduction of the overall fluid volume relative to the combustible foamed fluid just prior to combustion. For example, oxygen, hydrogen and light hydrocarbons such as methane, ethane or the like may occur in the gaseous phase of the combustible foamed fluid, but upon combustion, there may be fewer gaseous products on a molar or volumetric basis, and also, some common combustion products such as water may condense largely to liquid phase at the ambient downhole pressure and temperature, while carbon dioxide may dissolve in and/or be miscible with other downhole liquids. For example, a gaseous mixture of stoichiometric oxygen and hydrogen (1:2 molar ratio) may form almost entirely into water condensate, which has a negligible volume relative to the gaseous reactants. Further, transient pressure or temperature increases during the combustion may lead to the escape of some gaseous phase, e.g., through the wellbore, or into adjacent porous formation matrix or other porous material, or into fractures created by the combustion, or the like, and the escaped fluid may not, or not fully return post-combustion to the situs of the original combustible foamed fluid.

In some embodiments, the combustion of the combustible fluid in a downhole structure such as a wellbore, annulus, formation fracture, formation matrix, or the like, may enhance the effectiveness of one or more treatment attributes, such as, for example, more desirable proppant placement (e.g., well-defined pillars and channels), reduced formation damage, reduced flowback volume, shortening of the unproductive period of time for the treatment and/or more rapid initiation or return of the production of reservoir fluids following treatment, and the like.

In various embodiments, the properties of the combustible foamed fluid, including the combustion parameters such as dynamics and kinetics, are in various embodiments controlled by foam quality, size and size distribution of the dispersed fluid phase droplets, fluid chemistry, composition of the gaseous and/or liquid phases, and the like.

In specific embodiments of the present disclosure, the combustible foamed fluid is used for performing matrix treatments, e.g., below fracturing pressure of the subterranean formation and/or in conjunction with fracturing. Examples of such treatments include matrix acidizing, injection of chelating agents into the matrix, injection of paraffin into the matrix, injection of scale inhibitors into the matrix, etc. In matrix treatment embodiments, at or near the conclusion of the treatment process, all of a significant portion of the combustible foamed fluid may remain in various openings inside the treated formation, with the size and configuration of the openings defined by the type of the treatment as well as the formation geology: acid etched fractures, hydraulic fractures, wormholes, open natural fractures, caverns, vugs, interstices, etc. When the combustible foamed fluid is ignited and combustion otherwise occurs in accordance with embodiments of the present disclosure, the combustion of the fluid in such openings may result in increasing effectiveness of the performed treatment, such as, for example, by reducing the flowback volume, and/or by at least partially fracturing the formation, e.g., due to an initial pressure increase during the combustion process that can locally exceed the fracture pressure as well as an initial temperature increase that can locally reduce the fracture pressure of the formation, or the like.

The following discussion is directed in the main to hydraulic fracturing embodiments, by way of illustration and example, and is not intended to thereby limit the scope of the disclosure or claims, it being understood that the systems and methods described herein as well as the principles thereof may be equally applicable, with or without appropriate modification, to other downhole treatments and structures such as matrix treatments, wellbore treatments, etc. In hydraulic fracturing, the combustible foamed fluid may be employed in the initiation, propagation or other creation of a fracture, such as, for example, in one, or a combination, or all, of a pad or pre-pad stage, a proppant stage, a non-proppant stage, spacer stage, tail-in stage, flush stage, or the like.

The combustible foamed fluid in various embodiments may comprise a liquid phase or phases, a gaseous phase or phases, fuel source(s), combustion oxidant source(s), inert(s) such as nitrogen, argon, and the like, combustion modifier(s), including inhibitors, retardants, accelerants, and/or initiators, foaming agent(s), gelling agent(s), proppant(s), fluid loss additive(s), sub-proppant(s), fiber(s), polymer(s), crosslinker(s), surfactant(s), breaker(s), biocide(s), friction reducer(s), corrosion inhibitor(s), temperature stabilizer(s), clay stabilizer(s), chelant(s), scale inhibitor(s), diverting agent(s), proppant or other solid flowback control additive(s), agglomerant(s), and the like, including multifunctional components that perform two or more of these functions. For example, nitrogen gas is an inert gas which can inhibit flame propagation as well as reduce any transient temperature increase following combustion due to a lower heating value of the gaseous phase of the fluid. Lower foam quality, i.e., a higher volumetric proportion of water or other non-flammable liquid, can likewise be used in some embodiments to inhibit flame propagation and reduce the transient temperature and/or pressure increases due to a lower heating value and the latent heat for volatilization of the liquid component of the foam.

The liquid phase of the combustible foamed fluid may be aqueous in some embodiments, or can be non-aqueous, or a mixture, such as an oil/water emulsion or invert emulsion. The presence of fuel materials such as hydrocarbons and/or oxidant materials such as peroxides can also accelerate the combustion process and/or increase the resulting transient pressures and temperatures, whereas the presence of non-flammable components such as brine can serve to inhibit the combustion process. In some embodiments, 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.

The combustible foamed fluid may be mixed at the surface before or during pumping downhole, or one or more components may be delivered downhole separately, e.g., in separate flow paths or containers, and mixed downhole, e.g., in the wellbore or in or adjacent the formation, or one or more components may be generated or formed downhole, e.g., by electrolysis, chemical reaction, or the like. For example, the gaseous fuel source may be separated from the combustion oxidant source by using separate lines, tubing, coiled tubing, including concentrical coil-tubing (e.i. containing one or more tubing inside the coil tubing itself), or the like, and a downhole mixer to combine or mix the separate streams together prior to introduction into the formation. In some embodiments, mixing or other formation of the combustible mixture is caused to occur below (relative to the surface) a flow direction check valve, flame arrester or the like to inhibit combustion through the wellbore to the surface, or combustion of the combustible foamed fluid or components at or adjacent the surface can be inhibited by locating a flame arresting device in the wellbore, e.g., above the ignition source. In some embodiments, the wellhead and/or surface equipment are designed to withstand any pressure and/or temperature increases that might result from combustion of the combustible foamed fluid, whether the combustion is planned or occurs inadvertently, e.g., after shut in of the well and/or during pumping, e.g., after shut in of the well and/or during pumping of the combustible foamed fluid.

Electrolysis of water or another aqueous liquid in some embodiments can be used to generate a mixture of hydrogen and oxygen gases according to the reaction: 2H₂O→2H₂+O₂. Electrolysis can be performed at the surface or downhole in an electrolytic cell by passing an electrical current between electrodes in contact with the aqueous liquid. In some embodiments, either direct current (DC) or alternating current (AC) can be used, including a variable voltage such as a frequency modulated voltage, e.g., in the frequency range of from 1 Hz to 1 MHz. The mixture of hydrogen and oxygen in the gaseous phase of the foamed fluid can be stoichiometric or approximately stoichiometric (due to different solubilities or reactivities etc.) in the foamed fluid media, and in some embodiments may be the only gases introduced into the foamed fluid, or can be used with other gaseous materials.

In some embodiments, the combustible foamed fluid is placed in the fracture or other downhole structure under non-combustion conditions free of an active ignition source, and thereafter ignited. In contrast to methods employing a downhole burner or other combustion device in which a steady state or moving flame front is maintained as in dry combustion, reverse combustion, wet combustion and like in situ combustion techniques, in some embodiments, the combustible foamed fluid herein is not ignited and/or combustion initiated until after the fluid is placed in the fracture or otherwise used to at least partially complete a treatment function, e.g., fracture creation, matrix acidization, or the like. At some point during performance of the fracture treatment, i.e., during placement into the downhole structure, or after completion of the fracturing treatment, i.e., after placement into the downhole structure, a combustion process is initiated in the gaseous phase of the combustible foamed fluid.

In some embodiments, ignition of the combustible foamed fluid is achieved by one or more of surface ignition and propagation through the wellbore or tubing installed in the wellbore; downhole ignition with an electrical arc or other igniter which may be deployed via coiled tubing, wireline or the like; chemical systems such as Mg/H₂O, Al/NaOH, KMnO₄/glycerol, or the like, that increase the temperature at a point or region of the combustible foamed fluid above the ignition point, e.g., by encapsulating one or more reactants wherein a coating dissolves, melts or is crushed at downhole conditions such as pressure, temperature, pH, fracture closure, or the like; the use of explosive materials that can detonate downhole.

In some embodiments, the direction of the combustion or flame front(s) during the combustion process may be selected by the placement of the ignition source, e.g., at the tip of the fracture for a “reverse” combustion propagation toward the wellbore, at a location near the wellbore-fracture junction for “forward” propagation through the fracture away from the wellbore toward the tip(s), and/or placement of a plurality of ignition sources at multiple locations to form a plurality of propagation zones corresponding to each of the respective ignition sources, which may or may not have propagation fronts that meet intermediate the ignition sources. According to some embodiments, proppant may accumulate to form pillars or ridges at the outer edges of the respective propagation zones and/or where the propagation fronts meet between adjacent ones of the ignition sources.

In some embodiments, combustion of the combustible foamed fluid in a fracture may result in a reduction of the volume of the foamed fluid placed in the formation fracture, e.g., a fracture network, and achieve relatively instantaneous fracture closure, e.g., especially relative to a shut-in procedure where the fracturing fluid may need a period of time, first to chemically break and/or then to generally only gradually permeate into the formation matrix.

Rapid fracture closure in some fracturing embodiments can assist in achieving and/or retaining a desired proppant placement modality, for example, by reducing the opportunity for proppant to settle or excessively settle in the formation. In some embodiments, the proppant is “frozen” in place by rapid fracture closure, e.g., trapping the proppant in a relatively homogeneous distribution that preserves a high porosity and/or conductivity for fluid to flow through the interstices in the proppant pack, or trapping the proppant in pillars spaced apart by conductive flow channels between the proppant pillars or islands.

In some embodiments, the fracturing method or system optionally includes isolating the fracture from fluid communication from the fracture prior to or during combustion of the foamed fluid in the fracture, e.g., using isolation sleeves, isolation valves, or diversion plugs. Isolation of the fracture can inhibit fluid flowback during the combustion process, and inhibit turbulence and/or fluid flow during combustion that might otherwise result in movement of the proppant within the fracture from its desired location.

In some embodiments, fluid communication between the wellbore and another downhole structure in which the combustible fluid has been placed, such as a fracture, is established during the combustion of the combustible foamed fluid. A transient pressure increase resulting from the combustion in some embodiments may create or increase fluid flow into the wellbore from the other downhole structure to facilitate fluid flowback, facilitate cleanup (e.g., by entrainment and expulsion of flow damaging materials), and/or or facilitate proppant placement, e.g. by forming or assisting in the formation of proppant pillars, or by placing and/or consolidating proppant in a gravel pack in a screen annulus and/or in a near wellbore portion of the fracture.

In some embodiments, a proppant injection stage comprises alternating proppant-rich and proppant-lean or proppant-free substages, or otherwise alternating the characteristics between substages, so as to form a pillar-channel proppant placement configuration. The present disclosure in some embodiments includes injecting the combustible foamed fluid, e.g., in or with the proppant injection stage, wherein the combustion operation facilitates quickly closing the fracture and preserves the pillar-channel proppant placement. 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.

According to some embodiments herein, the proppant injection stage comprises alternating the injection of a combustible foamed fluid substage with another substage comprised of a non-combustible fluid, which may be a liquid or a foam, e.g., a foam of similar quality, density, and/or viscosity to inhibit mixing between the alternating adjacent substages. The proppant or other materials or components may be otherwise homogeneous or of similar content between the alternating substages, or they may have different concentrations of proppant, agglomerant, anchors or the like. Upon placement and/or combustion of the alternating substages in the fracture, optionally wherein the substages are segregated within the fracture, according to some embodiments, the proppant may accumulate to form pillars selectively within the combustible foam substages, or within the non-combustible foam substages, or within both, or at interfaces between the combustible and non-combustible foam substages. In some embodiments, the combustible foamed fluid substages may each comprise at least one respective ignition source. In some embodiments, the combustible foamed fluid substages are ignited simultaneously, sequentially or in a combination thereof.

In some embodiments, as in, for example, US 2014/0262264 by Potapenko et al. (also published as WO 2014/143490A1), incorporated herein by reference, a method for treating a subterranean formation comprises injecting a treatment slurry, which includes a combustible foamed carrying fluid according to embodiments of the present disclosure, into a fracture to form a substantially uniformly distributed mixture of solid particulate and agglomerant; initiating combustion of the combustible foamed fluid in the fracture; and transforming the substantially uniform mixture into areas that are rich in solid particulate and areas that are substantially free of solid particulate, wherein the solid particulate and the agglomerant have substantially dissimilar velocities in the fracture so that the transformation results from the substantially dissimilar velocities. In some embodiments, the combustion induces a flow of fluid in the fracture to initiate transport and/or promote further transport the solid particulate and the agglomerant at the substantially dissimilar velocities. In some embodiments, the combustion induces rapid fracture closure to substantially preserve, i.e., inhibit degrading or blurring of, the solid particulate-rich and solid particulate-lean areas. In some embodiments, the combustion induces a flow of fluid in the fracture to transport or further transport the solid particulate and the agglomerant at the substantially dissimilar velocities. In some embodiments, the combustion initially induces a flow of fluid in the fracture to initiate transport and/or promote further transport the solid particulate and the agglomerant at the substantially dissimilar velocities, and subsequently then induces rapid fracture closure to substantially preserve (or inhibit degrading or blurring of) the solid particulate-rich and solid particulate-lean areas.

According to some embodiments herein, the combustion of the combustible foamed fluid may create fractures in the subterranean formation, e.g., initiate new fractures and/or extend existing fractures. In some embodiments, combustion of the combustible foamed fluid in the downhole structure may at least temporarily raise the pressure of the fluid, and in some embodiments the elevated pressure may exceed a fracture pressure of the adjacent formation. In some embodiments, extension of fractures may be coordinated with isolation of the fracture from the wellbore during combustion of the combustible foamed fluid in the existing or created fracture. In some embodiments, initiation of new fractures may be coordinated with isolation of any pre-existing fractures from a wellbore during combustion of the combustible foamed fluid in the wellbore, and/or by isolating the combustible foamed fluid to an interval of the wellbore and igniting the combustible foamed fluid to create an at least temporary increase in pressure above the fracturing pressure of the formation.

In further embodiments according to the present disclosure, the combustion may at least temporarily increase the temperature of the post-combustion fluid. In some embodiments, the treatment fluid may comprise a thermally sensitive viscosity or rheology modifier, and the temperature increase can effectively break the treatment fluid, i.e., reduce the viscosity and/or gel strength of the fluid or a portion thereof. In some embodiments, the combustible foamed fluid may comprise a thermally sensitive foaming system, e.g., foaming agents or stabilizers or liquid surface tension that cease to support the foam structure at the elevated temperature, and the temperature increase, alone or together with the changes in foam quality associated with combustion (at least transient changes and/or fluctuations in the gas:liquid ratio due to temporary expansion and ultimate reduction of the gas volume) can effectively destabilize and/or degrade the foam.

In some embodiments, the present disclosure can use a treatment fluid that is thermally stable at the expected downhole conditions of use, but readily broken, degraded, or destabilized, at the fluid temperature profile resulting from combustion of the combustible foamed fluid used as the treatment fluid or as a sufficient portion of the treatment fluid effective to provide the fluid temperature. For example, treatment fluids such as fracturing fluids are designed by taking into consideration the downhole temperature and the viscosifiers needed to meet the viscosity requirements during a fracturing treatment at that temperature, and also by considering the requirements for breaking as well as fluid destruction requirements in the end of it. Taking into account that combustion temperature may be relatively higher than that of the ambient formation, in some embodiments a fracturing fluid may be used having a composition normally considered as too damaging or otherwise unsuitable for use due to a low ambient formation temperature. In a specific embodiment of the present disclosure a single composition of such fracturing fluid can be used for treating wells regardless of their temperature range, e.g., a “universal” fracturing fluid can be used over a wide range of formation temperatures.

In some embodiments herein, a combustible foamed fluid may comprise proppant, or be used or pumped with another stage or substage comprising proppant in a fracturing operation. The proppant, when present, can be naturally occurring materials, such as sand grains. The proppant, when present, can also be man-made or specially engineered, such as coated (including resin-coated) sand, modulus of various nuts, high-strength ceramic materials like sintered bauxite, etc. In some embodiments, the proppant of the current application, when present, has a density greater than 2.45 g/mL, e.g., 2.5-2.8 g/mL, such as sand, ceramic, sintered bauxite or resin coated proppant. In some embodiments, the proppant of the current application, when present, has a density greater than or equal to 2.8 g/mL, and/or the treatment fluid may comprise an apparent specific gravity less than 1.5, less than 1.4, less than 1.3, less than 1.2, less than 1.1, or less than 1.05, less than 1, or less than 0.95, for example. In some embodiments a relatively large density difference between the proppant and carrier fluid may enhance proppant settling during the clustering phase, for example.

In some embodiments, the proppant of the current application, when present, has a density less than or equal to 2.45 g/mL, such as light/ultralight proppant from various manufacturers, e.g., hollow proppant. In some embodiments, the treatment fluid comprises an apparent specific gravity greater than 1.3, greater than 1.4, greater than 1.5, greater than 1.6, greater than 1.7, greater than 1.8, greater than 1.9, greater than 2, greater than 2.1, greater than 2.2, greater than 2.3, greater than 2.4, greater than 2.5, greater than 2.6, greater than 2.7, greater than 2.8, greater than 2.9, or greater than 3. In some embodiments where the proppant may be buoyant, i.e., having a specific gravity less than that of the carrier fluid, the term “settling” shall also be inclusive of upward settling or floating.

In some embodiments herein, a combustible foamed fluid 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. In embodiments, even in absence of proppant, the conductivity may be optimized by alteration of the fracture walls, for example by heat, pressure or compounds generated from the combustion reaction of the present energized fluid. In embodiments the intrinsic formation characteristics may provide sufficient conductivity.

The liquid phase of the combustible foamed fluid may include water, fresh water, seawater, connate water or produced water. The liquid phase 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), and an oil-based fluid including a gelled, foamed, or otherwise viscosified oil. The liquid phase may be a brine, and/or may include a brine. The liquid phase 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 liquid phase, 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 liquid phase, 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.

According to some embodiments of the present disclosure, the combustible foamed fluid comprises fibers, or may be used with another treatment fluid or stage or substage comprising fibers. 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.

In some embodiments, the treatment fluid comprises from 1.2 to 12 g/L of 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 fibers, which may be proppant-suspending carrier 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 fibers comprise low crimping equal to or less than 5 crimps/cm of fiber length, e.g., 1-5 crimps/cm.

In some embodiments, the fibers may have a length of from about 2 to about 25 mm, such as from about 3 mm to about 20 mm. 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).

Depending on the temperature that the treatment fluid will encounter downhole, including transient temperatures associated with the combustion of the foamed fluid, the carrier, bridging or non-bridging fibers may be chosen with an emphasis more on their functionality as carrier, bridging and/or non-bridging fibers based on their resistance to degradability at the ambient downhole temperatures and their degradability at the temperature and duration of the combustion process. For example, since low, mid or high temperature fibers may be selected solely for their treatment functionality and resistance to degradation at the formation temperature, whereas any or all of the low, mid or high temperature fibers can be degraded at the temperatures associated with the downhole combustion, e.g., high temperature fibers can be used regardless of the ambient downhole temperatures, e.g., in low or mid temperature formations, since such fibers might sufficiently degrade upon combustion of the foamed fluid. This provides an example of a universal fluid that can be used in a wide variety of formations, regardless of the downhole temperature conditions.

Suitable fibers may optionally degrade under ambient 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.

In some embodiments, the 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 (PLA), polyglycolic acid (PGA), copolymers of lactic and glycolic acid, and combinations thereof.

In some embodiments, the fibers may be degradable or non-degradable, and 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 injection of the treatment fluid including at least one stage or substage comprising the combustible foamed fluid forms a homogenous region within the fracture of continuously uniform distribution of the proppant or other solid particulate. In some embodiments, the alternation of the concentration of the agglomerant and/or agglomerant aid forms heterogeneous areas within the fracture comprising agglomerant/agglomerant aid-rich areas and agglomerant/agglomerant aid-lean areas.

In some embodiments, the agglomerant may comprise a degradable material. In some embodiments, the agglomerant 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, or other natural fibers, rubber, sticky fiber, or a combination thereof. In some embodiments the agglomerant may comprise acrylic fiber. In some embodiments the agglomerant may comprise mica.

In some embodiments, the agglomerant is present in the agglomerant-laden stages of the treatment fluid in an amount of less than 5 vol %. All individual values and subranges from less than 5 vol % are included and disclosed herein. For example, the amount of agglomerant may be from 0.05 vol % less than 5 vol %, or less than 1 vol %, or less than 0.5 vol %. The agglomerant may be present in an amount from 0.5 vol % to 1.5 vol %, or in an amount from 0.01 vol % to 0.5 vol %, or in an amount from 0.05 vol % to 0.5 vol %.

In further embodiments, the agglomerant may comprise a fiber with a length from 1 to 50 mm, or more specifically from 1 to 10 mm, and a diameter of from 1 to 50 microns, or, more specifically from 1 to 20 microns. All values and subranges from 1 to 50 mm are included and disclosed herein. For example, the fiber agglomerant length may be from a lower limit of 1, 3, 5, 7, 9, 19, 29 or 49 mm to any higher upper limit of 2, 4, 6, 8, 10, 20, 30 or 50 mm. The fiber agglomerant length may range from 1 to 50 mm, or from 1 to 10 mm, or from 1 to 7 mm, or from 3 to 10 mm, or from 2 to 8 mm. All values from 1 to 50 microns are included and disclosed herein. For example, the fiber agglomerant diameter may be from a lower limit of 1, 4, 8, 12, 16, 20, 30, 40, or 49 microns to an upper limit of 2, 6, 10, 14, 17, 22, 32, 42 or 50 microns. The fiber agglomerant diameter may range from 1 to 50 microns, or from 10 to 50 microns, or from 1 to 15 microns, or from 2 to 17 microns.

In further embodiments, the agglomerant may be fiber selected from the group consisting of polylactic acid (PLA), polyester, polycaprolactam, polyamide, polyglycolic acid, polyterephthalate, cellulose, wool, basalt, glass, rubber, or a combination thereof.

In further embodiments, the agglomerant may comprise a fiber with a length from 0.001 to 1 mm and a diameter of from 50 nanometers (nm) to 10 microns. All individual values from 0.001 to 1 mm are disclosed and included herein. For example, the agglomerant fiber length may be from a lower limit of 0.001, 0.01, 0.1 or 0.9 mm to any higher upper limit of 0.009, 0.07, 0.5 or 1 mm. All individual values from 50 nanometers to 10 microns are included and disclosed herein. For example, the fiber agglomerant diameter may range from a lower limit of 50, 60, 70, 80, 90, 100, or 500 nanometers to an upper limit of 500 nanometers, 1 micron, or 10 microns.

In some embodiments, the agglomerant may comprise an expandable material, such as, for example, swellable elastomers, temperature expandable particles, Examples of oil swellable elastomers include butadiene based polymers and copolymers such as styrene butadiene rubber (SBR), styrene butadiene block copolymers, styrene isoprene copolymer, acrylate elastomers, neoprene elastomers, nitrile elastomers, vinyl acetate copolymers and blends of EV A, and polyurethane elastomers. Examples of water and brine swellable elastomers include maleic acid grafted styrene butadiene elastomers and acrylic acid grafted elastomers. Examples of temperature expandable particles include metals and gas filled particles that expand more when the particles are heated relative to silica sand. In some embodiments, the expandable metals can include a metal oxide of Ca, Mn, Ni, Fe, etc. that reacts with the water to generate a metal hydroxide which has a lower density than the metal oxide, i.e., the metal hydroxide occupies more volume than the metal oxide thereby increasing the volume occupied by the particle. Further examples of swellable inorganic materials can be found in U.S. Application Publication Number US 20110098202, which is hereby incorporated by reference in its entirety. An example for gas filled material is EXPANCEL™ microspheres that are manufactured by and commercially available from Akzo Nobel of Chicago, Ill. These microspheres contain a polymer shell with gas entrapped inside. When these microspheres are heated, e.g., during the combustion stage and/or due to the ambient formation temperature, the gas inside the shell expands and increases the size of the particle. The diameter of the particle can increase 4 times which could result in a volume increase by a factor of 64.

In some embodiments the agglomerants may be gel bodies such as balls or blobs made with a viscosifier, such as for example, a water soluble polymer such as polysaccharide like hydroxyethylcellulose (HEC) and/or guar, copolymers of polyacrylamide and their derivatives, and the like, e.g., at a concentration of 1.2 to 24 g/L (10 to 200 ppt where “ppt” is pounds per 1000 gallons of fluid), or a viscoelastic surfactant (VES). The polymer in some embodiments may be crosslinked with a crosslinker such as metal, e.g., calcium or borate. The gel bodies may further optionally comprise fibers and/or particulates dispersed in an internal phase. The gel bodies may be made from the same or different polymer and/or crosslinker as the continuous crosslinked polymer phase, but may have a different viscoelastic characteristic or morphology.

In some embodiments, when proppant is present as in the initiation, propagation or other fracture creation operation, the treatment fluid, e.g., the combustible foamed fluid or another treatment fluid or stage or substage associated or used in a treatment job therewith, 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). Exemplary proppants include ceramic proppant, sand, bauxite, glass beads, crushed nut shells, polymeric proppant, rod shaped proppant, and mixtures thereof.

In some embodiments the treatment fluid comprising the combustible foamed fluid 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.

EXAMPLES

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 following 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. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Example 1

Combustible Fluid Foamed with Stoichiometric Hydrogen/Oxygen Mix

An electrolysis cell had graphite and copper electrodes with surface area of 30 cm² spaced 2 cm apart. The cell was loaded with water and powered by a DC unit with a voltage or potential of 24 volts. Gas formed in the cell comprising an oxygen/hydrogen mix was transferred to a bottle through a plastic tube and bubbled through water containing a sodium laurate foaming agent. Bubble size was controlled to 1-2 mm using a choke at the end of the tube. The foam generation rate was up to 10 ml/min of a foam quality of 60% at atmospheric pressure and ambient temperature.

Example 2

Combustion of Combustible Foam in a Narrow Slot

A 30 ml quantity of the combustible foamed fluid of Example 1 was placed in a 1.5 mm wide slot between opposing 10 cm by 20 cm surfaces of aluminum foil wrapped construction bricks. The slot was sealed and the foam was ignited at a side of the slot using a spark igniter. Rapid combustion of the fluid resulted in complete disappearance of the fluid, which was confirmed by opening and visually inspecting the slot after the experiment.

Example 3

Reduction of Foam Volumes

The potential reduction of the volume of the gas phase of foams from the complete combustion of stoichiometric fuel/oxygen ratios was estimated for some gas fuel sources. The estimations assumed the same before and after pressures and temperatures, that the volume of liquid water produced as a combustion product was negligible compared to the initial gas phase volume in the foam, that the carbon dioxide produced as a combustion product was in gas form and/or at least partially soluble in any liquid present, and that all gases in the fluid before and after combustion followed the ideal gas law (PV=nRT). The estimated results are presented in the following Table:

TABLE
Combustion Reaction       Gas phase volume reduction (%)
2H2 + O2 → 2H2O           >99
CH4 + 2O2 → CO2 + 2H2O    >67
2C2H6 + 7O2 → 4CO2 + 6H2O >56
C2H4 + 3O2 → 2CO2 + 2H2O  >50
2C2H2 + 5O2 → 4CO2 + 2H2O >43

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 downhole a quantity of a treatment fluid comprising a combustible foamed fluid comprising a mixture of a fuel source and a combustion oxidant source, wherein a gas phase of the foam comprises the mixture of the fuel source and the combustion oxidation source;

placing the combustible foamed fluid in a downhole structure under non-combustion conditions free of an active ignition source;

thereafter igniting the combustible foamed fluid to combust the fuel source in the downhole structure forming a post-combustion fluid.

2. (canceled)

3. The method of claim 1, wherein the combustion decomposes the foamed fluid.

4. The method of claim 1, further comprising cooling the post-combustion fluid to a reduced specific volume relative to the combustible foamed fluid.

5. The method of claim 1, wherein the treatment fluid further comprises proppant.

6. The method of claim 1, wherein the downhole structure comprises a fracture above a fracturing pressure.

7. The method of claim 1, wherein the downhole structure comprises a formation matrix below a fracturing pressure.

8. The method of claim 1, wherein the fuel source is selected from hydrogen, hydrocarbon gases, or a mixture thereof.

9. The method of claim 1, wherein the combustion oxidant source comprises molecular oxygen.

10. The method of claim 1, further comprising preparing the combustible foamed fluid at a surface location and introducing the mixture into a wellbore.

11. The method of claim 1, further comprising introducing the combustion oxidant source into a wellbore in a first stream separate from a second stream comprising the fuel source, and mixing the first and second streams downhole to form the combustible foamed fluid.

12. An energized fluid system, comprising:

a combustible energized fluid comprising a combustible gaseous mixture dispersed in a continuous liquid phase;

a downhole structure to receive the combustible foamed fluid under non-combustion conditions free of an active ignition source; and

an ignition source in communication with the downhole structure activatable to initiate combustion of the dispersed gaseous mixture.

13. The energized fluid system of claim 12, wherein the combustible gaseous mixture comprises oxygen mixed with a fuel source selected from hydrogen, hydrocarbon gases and combinations thereof.

14. The energized fluid system of claim 12, wherein the downhole structure comprises a formation matrix.

15. The energized fluid system of claim 12, wherein the structure comprises a fracture.

16. The energized fluid system of claim 12, further comprising a controller to remotely activate the ignition source, wherein the ignition source comprises an electrical or chemical igniter.

17. A method, comprising:

dispersing a gaseous fuel source and a gaseous combustion oxidant source into a continuous liquid phase to form a combustible foamed fluid; and

isolating the combustible foamed fluid in a downhole structure under non-combustion conditions free of an active ignition source.

18. The method of claim 17, wherein the gaseous fuel source and gaseous combustion oxidant are delivered in separate streams through a wellbore and mixed downhole.

19. The method of claim 17, wherein the gaseous fuel source comprises hydrogen, the gaseous combustion oxidant comprises oxygen, and the continuous liquid phase comprises water, and further comprising passing the liquid phase through an electrolysis cell to generate the oxygen and hydrogen in the liquid phase.

20. The method of claim 17, wherein the downhole structure comprises a fracture above a fracturing pressure, or a formation matrix below the fracturing pressure.