WELL TREATMENT

Abstract

Rapidly pulsed injection fracture acidizing. A method comprises rapidly pulsed injection of a high reactivity fracture treatment fluid mode or substage alternated with one or more low reactivity treatment fluid modes or substages.

Description

RELATED APPLICATIONS

None.

FIELD

The disclosure relates to methods for treating subterranean formations. More particularly, the disclosure relates to methods for fracturing, acidizing or otherwise stimulating a wellbore.

BACKGROUND

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

Carbonate reservoirs present tremendous challenges to completion, stimulation and production processes. These completion intervals are often vertically and laterally heterogeneous with natural permeability barriers, natural fractures and a vast array of porosity types. In some wells, acid reaction rate may be the dominant factor controlling the effectiveness of an acid-fracturing treatment. Temperature accelerates the reaction rate between acid and carbonate formation and, in turn, significantly affects the depth of penetration. Management of the rapid reaction rate of the acid with the carbonate formation presents a challenge to create long, conductive fractures.

In hydraulic fracturing, a first viscous fluid called the pad has been injected into the formation to initiate and propagate the fracture, and is followed by a second fluid that contains a proppant to keep the fracture open after the pumping pressure is released. In acid fracturing, the second fluid contains an acid or other chemical such as a chelating agent that can dissolve part of the rock, causing irregular etching of the fracture face and removal of some of the mineral matter, resulting in spaces between the opposing fracture surfaces upon closure.

The relatively high reactivity of mineral acids with carbonate formations, however, may result in the rapid consumption of the acid before the acid can penetrate as deeply as desired into the fracture. Accordingly, it would be beneficial to improve fracture conductivity.

SUMMARY

According to some embodiments of the disclosure herein, a method comprises rapidly alternating or pulsing modalities of reactivity of a treatment fluid stage introduced into a fracture in a reactive formation, such as, for example: alternating pulses of a low reactivity mode and a high reactivity mode, which may be delivered downhole in a common flow conduit or in separate flow paths.

According to some embodiments, a method according to the instant disclosure may comprise: injecting a treatment stage fluid into a subterranean formation above a fracturing pressure to form a fracture in the formation; successively alternating reactivity modes in the treatment stage fluid, in either order, between at least first and second reactivity modes to react with carbonate in the formation at different rates or times to unevenly etch surfaces of the fracture; sustaining injection of the treatment stage fluid during each of the first and second reactivity modes for a period of time from 5 seconds up to 2.5 minutes; repeating the successive alternation of reactivity modes for a plurality of cycles; and reducing pressure to facilitate fracture closure and form interconnected, hydraulically conductive channels between opposing fracture surfaces.

In some embodiments, one of the first and second reactivity modes comprises a reactant reactive with the carbonate in the formation and the other of the first and second reactivity modes comprises the reactant at a lesser concentration, or in a less reactive form, or is free of the reactant. In some embodiments, the reactant is selected from the group consisting of mineral acids, organic acids, chelants and combinations thereof. In some embodiments, the method may include injecting a pad stage in advance of the treatment fluid stage, injecting a terminal flush stage, or a combination thereof.

According to some embodiments, the method may further comprise: successively alternating viscosity modes in the treatment stage fluid, in either order, between at least first and second viscosity modes, wherein one of the first and second viscosity modes has a higher viscosity than the other; sustaining injection of the treatment stage fluid during each of the first and second modes for a period of time from 5 seconds up to 2.5 minutes; and repeating the successive alternation of viscosity modes for a plurality of cycles. In some embodiments, the first and second reactivity modes coincide with the first and second viscosity modes, respectively.

According to some embodiments, the relatively low viscosity mode forms fingers penetrating into the high viscosity mode in the fracture, and in some further embodiments, the fingers break through the penetrated high viscosity mode into a preceding low viscosity mode and/or form channels between islands of the high viscosity mode. In some embodiments, the first reactivity and viscosity mode has a high viscosity and low reactivity relative to the second reactivity and viscosity mode.

According to some embodiments, a system may comprise: a subterranean formation penetrated by a wellbore; a treatment fluid stage disposed in the wellbore, the treatment fluid stage comprising a plurality of first mode substages disposed in the wellbore in an alternating sequence with a plurality of second mode substages, wherein the first mode substages have a high viscosity relative to the second mode substages and wherein the second mode substages have a high reactivity with carbonate in the formation relative to the first mode substages; and a pump system to continuously deliver the treatment fluid stage from the wellbore to the formation at a pressure above fracturing pressure to inject the treatment fluid stage into a fracture in the formation, and at a rate wherein each substage is injected into the formation over a period of time from 1 second to 2.5 minutes. In some embodiments, the viscous fingering from one of the second modes breaks through one of the first modes into another one of the second modes and/or forms channels between islands of the first mode(s).

According to some embodiments, a system may comprise: a subterranean formation penetrated by a wellbore; means for injecting a treatment stage fluid above a fracturing pressure to form a fracture in the formation; means for successively alternating modes in the treatment stage fluid, in either order, between at least first and second modes; wherein the first modes have a high viscosity relative to the second modes for viscous fingering of the second mode into the first mode in the fracture; wherein the second modes have high reactivity with carbonate in the formation relative to the first mode to unevenly etch surfaces of the fracture; means for sustaining injection of the treatment stage fluid during each of the first and second modes for a period of time from 5 seconds up to 2.5 minutes; means for repeating the successive alternation of modes for a plurality of cycles; and means for reducing pressure to facilitate fracture closure and form interconnected, hydraulically conductive channels between opposing fracture surfaces.

In some embodiments, the first reactivity and viscosity modes, or mode substages, comprise a viscoelastic diverting agent and has a viscosity higher than that of the second reactivity and viscosity modes, or mode substages.

In some embodiments, the treatment stage fluid comprises a gel, a cross-linked gel, an emulsion, a foam, or a combination thereof.

In some embodiments, the treatment stage fluid comprises a solid material slurried in a carrier fluid.

In some embodiments, the treatment stage fluid comprises a plurality of polyolefin beads having an average particle size distribution of less than or equal to about 1000 microns (˜20 mesh).

In some embodiments, one of the first and second reactivity modes, or mode substages, comprises asphaltene, polylactic acid, latex, or a combination thereof, and the other one of the first and second reactivity modes, or mode substages, comprises a multivalent cation.

In some embodiments, one of the first and second reactivity modes, or mode substages, comprises an aqueous carrier fluid, and the other one of the first and second reactivity modes, or mode substages, comprises an oleaginous carrier fluid.

In some embodiments, the treatment stage fluid comprises a water-in-oil emulsion wherein a reactant with carbonate in the formation is in a dispersed phase.

According to some embodiments, a method may comprise: injecting a treatment stage fluid above a fracturing pressure to form a fracture in a subterranean formation penetrated by a wellbore; successively alternating modes in the treatment stage fluid, in either order, between at least first and second modes; wherein the first modes have a high viscosity relative to the second modes for viscous fingering of the second mode into the first mode in the fracture; wherein the second modes have high reactivity with carbonate in the formation relative to the first mode to unevenly etch surfaces of the fracture; sustaining injection of the treatment stage fluid during each of the first and second modes for a period of time from 5 seconds up to 2.5 minutes; repeating the successive alternation of modes for a plurality of cycles; and reducing pressure to facilitate fracture closure and form interconnected, hydraulically conductive channels between opposing fracture surfaces. In some embodiments, the viscous fingering from one of the second modes may break through one of the first modes into another one of the second modes and/or to form channels separating islands of the first mode(s).

In some embodiments, the relative reactivities with the formation, the viscosities, and the like, of the two fluid modes may be controlled to further improve fracture conductivity. According to some embodiments, the relative proportions of the fluid modes, or mode substages, injected, and/or the composition of the two fluid mode, or mode substages, may be varied over time to further improve the conductivity of the fracture. For example, in some embodiments, a volumetric ratio of the first reactivity mode or mode substage to the second reactivity mode or mode substage may be from about 1:99 to about 99:1, such as by changing the injection or pumping times and/or rates between the modes and/or mode substages. In some embodiments, the sustained periods of time are from about 5 seconds to about 1 minute.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates the compartmentalization provided by embodiments of the instant disclosure, relative to a comparative example.

FIG. 2 illustrates the interpenetration or fingering of fluids according to embodiments of the instant disclosure, relative to a comparative example.

FIG. 3 illustrates the concentration profiles of different phases of the fluids over time according to embodiments of the instant disclosure.

FIG. 4 illustrates the effect of formation stabilization by degradable polymers loaded into one of the fluids according to embodiments of the instant disclosure.

FIG. 5 illustrates formation of absorbent aggregates in domains in the presence of PLA fibers according to embodiments of the instant disclosure.

FIG. 6 illustrates embodiments of the instant disclosure wherein the mineral acid fluid is injected periodically into a continuous gel phase.

FIG. 7 schematically illustrates a formation fracturing system to implement a pumping sequence according to some embodiments of the instant disclosure.

DETAILED DESCRIPTION

At the outset, it should be noted that in the development of any such actual embodiment, numerous implementation—specific decisions must 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.

The description and examples are presented solely for the purpose of illustrating the preferred embodiments and should not be construed as a limitation to the scope. While the compositions are described herein as comprising certain materials, it should be understood that the composition could optionally comprise two or more chemically different materials. In addition, the composition can also comprise some components other than the ones already 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 concentration range listed or described as being useful, suitable, or the like, is intended that any and every concentration 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 and every possible number along the continuum between about 1 and about 10. Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to only a few specific, it is to be understood that inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that inventors possession of the entire range and all points within the range.

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

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 or use of the fluid.

The term “fracturing” refers to the process and methods of breaking down a geological formation and creating a fracture in the rock formation around a well bore, by pumping fluid at very high pressures (pressure above the determined closure pressure of the formation), to increase production rates from a hydrocarbon reservoir. The “formation” of a fracture includes either or both of creating or initiating a new fracture or fracture branch as well as propagating or extending a fracture.

The terms “acidizing,” “etching” or “acid etching” refer to the process and methods of dissolving or degrading a surface of a geological formation such as a fracture, by any reactant which may be, for example, an acid, acid precursor, a chelant or another reactant or combination of reactants.

The term “proppant” includes proppant or gravel used to hold fractures open and also includes gravel or proppant used in a gravel packing and/or a frac-pack operation.

As used herein, the terms “treatment fluid” or “wellbore treatment fluid” are inclusive of “fracturing fluid” or “treatment slurry” and should be understood broadly. These may be or include a liquid, a solid, a gas, and combinations thereof, as will be appreciated by those skilled in the art. A treatment fluid may take the form of a solution, an emulsion, an energized fluid (including foam), slurry, or any other form as will be appreciated by those skilled in the art.

“Carrier,” “fluid phase” or “liquid phase” refer to the fluid or liquid that is present in the fluid, including emulsions, foams and energized fluids. Reference to “aqueous phase” refers to a carrier phase comprised predominantly of water, which may be a continuous or dispersed phase. As used herein the terms “liquid” or “liquid phase” encompasses both liquids per se and supercritical fluids, including any solutes dissolved therein.

As used herein, a blend of particles and a fluid may be generally referred to as a slurry, an emulsion, or the like. For purposes herein “slurry” refers to a mixture of solid particles dispersed in a fluid carrier. An “emulsion” refers to a form of slurry in which the particles are of a size such that the particles do not exhibit a static internal structure, but are assumed to be statistically distributed. In some embodiments, an emulsion is a mixture of two or more liquids that are normally immiscible (nonmixable or unblendable). For purposes herein, an emulsion comprises at least two phases of matter, which may be a first liquid phase dispersed in a continuous (second) liquid phase, and/or a first liquid phase and one or more solid phases dispersed in a continuous (second) liquid phase. Emulsions may be oil-in-water, water-in-oil, or any combination thereof, e.g., a “water-in-oil-in-water” emulsion or an “oil-in-water-in-oil” emulsion.

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 term “energized fluid” also encompasses foams and refers to any stable mixture of gas and liquid, regardless of the foam quality. Energized fluids comprise any of:

• • (a) Liquids that at bottom hole 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. 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 a 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.

As used herein, reactivity refers to the relative rate at which a material or treatment fluid in contact with a surface of a formation can solubilize the carbonate minerals present in the formation at downhole conditions; and in embodiments, the reactivity may be measured by the rate of production of either CO₂ gas or calcium cation. A treatment fluid is essentially non-reactive with the carbonate in the formation if it is no more reactive than deionized water at a pH of 7.

In embodiments herein, a method comprises successively alternatingly injecting a plurality of modes of a treatment stage fluid through and/or from a wellbore into a fracture in a formation wherein the modes have different reactivity properties to unevenly etch surfaces of the fracture. As representative examples of a two-mode method or system wherein a first mode or first mode substage may be relatively less reactive than a second mode or second mode substage where the second mode or second mode substage may contain a reactant or combination of reactants to react with carbonate in the formation, the less reactive first mode may (1) be free of the reactant, (2) contain a lesser amount of the same reactant, (3) contain a different reactant that is less reactive, (4) contain a delayed form of the same or different reactant (which may, after activation be more or preferably less reactive than the reactant in the second mode), (5) contain a reaction inhibitor, which may be either temporary or long lasting, (6) may contain a protective coating former(s) or a system to form a temporary or long-lasting coating to protect a formation surface from reaction, e.g., a temporary or long-lasting coating that is inert to or reacts with one or more reactant(s) in the first or second modes or mode substages, or (7)

In some embodiments, the first fluid comprises mineral acid, e.g., hydrochloric, sulfuric, hydrofluoric, phosphoric, nitric or the like, including combinations. In some embodiments, the first mode/substage, the second mode/substage, or both comprise a gel, a cross-linked gel, or a combination thereof. For example, the treatment stage fluid may have a continuous gel concentration and a crosslinker may be alternately pulsed to form the cross-linked gel in one of the modes/substages. In some embodiments, the second fluid comprises a viscoelastic diverting agent. In some embodiments, the first mode/substage, the second mode/substage, or both comprise a C₁-C₄₀ carboxylic acid, a C₈-C₄₀ phosphonic acid, a C₈-C₄₀ sulfonic acid, or a combination thereof. In some embodiments, the first mode/substage, the second mode/substage, or both comprise a C₈-C₃₆ saturated carboxylic acid. In some embodiments, the first mode/substage, the second mode/substage, or both comprise a C₈-C₄₀ amine.

In some embodiments, the first mode/substage, the second mode/substage, or both comprise a solid material, e.g., proppant, fiber, pillar reinforcement material, fluid loss control material, etc. In some embodiments, the first mode/substage, the second mode/substage, or both comprise a plurality of polyolefin beads having an average particle size distribution of less than or equal to about 1000 microns (˜20 mesh). In some embodiments, at least one of the first mode/substage, the second mode/substage, or both comprise asphaltene, polylactic acid, latex, or a combination thereof, and another one of the first mode/substage, the second mode/substage, or both comprise a multivalent cation.

In some embodiments, one of the first mode/substage, the second mode/substage, or both comprise an aqueous carrier fluid and the other one of the first mode/substage, the second mode/substage, or both comprise an oleaginous carrier fluid. In some embodiments, the first mode/substage, the second mode/substage, or both comprise an emulsion, e.g., a water-in-oil emulsion, an oil-in-water emulsion, a water-in-oil-in-water emulsion, an oil-in-water-in-oil emulsion, or the like, and in some embodiments, wherein mineral acid is present in a dispersed phase.

In some embodiments, one of the first and second modes or substages is reactive with the carbonate in the formation and the other of the first and second modes or substages is essentially non-reactive with the carbonate in the formation.

In some embodiments, a viscosity of one of the first and second modes or substages is greater than the other of the first and second modes or substages.

In some embodiments, a volumetric ratio of a first low-reactivity, high-viscosity mode, low viscosity mode/substage relative to the second high-reactivity, low viscosity mode/substage is from about 1:99 to about 99:1, or from about 1:20 to 20:1, or from about 1:1 to about 1:20, or from about 1:1 to about 1:10 or from about 1:2 to about 1:10, or from about 1:3 to about 1:10. In some embodiments, the volumetric ratio of the first mode/substage relative to the second mode/substage is varied between successive injections. In some embodiments, the reactivity of the first mode/substage, the reactivity of the second mode/substage, or both, are varied between successive injections.

In some embodiments, the sustained period of time of the injections of the first and/or second modes/substages or both are from about 5 or 10 seconds to about 150 or 120, or 90, or 60, or 30 or 20 seconds, e.g., from 10 to 30 seconds or 10 to 20 seconds.

As used herein, the switching time or sustained period of time refers to the lag time between injections of the different modes/substages, e.g., the time for injection of the particular mode/substage. In embodiments, the switching time is sufficiently long to avoid complete mixing between successive pulses and retain distinct slugs of alternate fluids.

FIG. 1 shows the compartmentalizing feature of the alternate phases of the fluids within the fracture extending radially from wellbore 10, e.g., an initial viscosified pad stage, and a treatment fluid stage having a reactive mode and a viscosified mode. The upper panel represents conventional or comparative methods where, after the initial pad stage 12, the switch between the reactive modes 14 and the viscosified modes 16 is on the time domain of 10 minutes or more. The lower panel shows embodiments of the instant disclosure, where after the initial pad stage 22, the switch between the reactive modes 24 and the viscosified modes 26 is less than 2.5 minutes, e.g., less than or equal to 1 minute, less than or equal to 30 seconds, or less than or equal to about 20 seconds.

In embodiments, at least one pump is used to inject the fluids. In embodiments, the portioning of the injected fluids comprises gate switching of the input and/or output of the pumping and blending apparatus.

A drawback of using a mineral acid such as HCl, in one form or another, in fracture acidizing heretofore is its inability to generate fracture with desired length, primarily due to the rapid reaction rate of the acid with the carbonate rock surface in particular at higher reservoir temperatures. Embodiments disclosed herein take advantage of the rapid reaction rate of the acid, within a confined elongated space to generate corresponding elongated fractures.

In embodiments, the method utilizes at least two fluids which differ with respect to reactivity with the carbonate formation, viscosity, density, composition, and/or the like. For purposes of simplicity and illustration, the following discussion refers to first and second fluids in reference to both the respective first and second modes of the treatment stage fluid in the method, as well as respective first and second mode substages of the treatment fluid stage in the system. The terms “modes” and “substages” and “fluids” in this sense are used interchangeably. While the discussion herein refers to the first fluid as having a lower reactivity and/or higher viscosity and the second fluid as having a higher reactivity and/or lower viscosity by way of example and illustration, the designations “first” and “second” are for reference only and do not imply any particular order of injection. For example, if a relatively viscous, essentially inert pad stage is employed in advance of the treatment fluid stage, the initial mode or substage of the treatment stage fluid immediately following the pad stage may be either the “second” fluid having a higher reactivity and/or lower viscosity, or the “first” fluid having a lower reactivity and/or higher viscosity. Further, combinations of high-reactivity, high-viscosity first fluids and low-reactivity, low-viscosity second fluids are also contemplated.

In embodiments, the more reactive fluid comprises a mineral acid. Suitable mineral acids include hydrochloric acid, sulfuric acid, nitric acid, phosphoric acid, boric acid, hydrofluoric acid, hydrobromic acid, and/or perchloric acid. In embodiments, the mineral acid is hydrochloric acid. For purposes herein, embodiments which refer to HCl are to be interpreted as the same embodiment comprising a mineral acid, and are not limited to HCl unless expressly indicated as such. Accordingly, HCl and mineral acid are used interchangeably herein.

In embodiments, the first fluid may be at least partially soluble in the second fluid. In other embodiments, the first fluid may be at least partially miscible with the second fluid. In other embodiments, the first fluid may be immiscible with the second fluid.

In embodiments, the first fluid comprises one or more components which render the first fluid more reactive to the composition of the formation as compared to the second fluid. In embodiments, the first fluid reacts with the formation (e.g., a carbonate formation) at a first reaction rate according to the equation:

First reaction rate=k₁*[first fluid mode]

where k₁ is the rate constant; and

the second fluid reacts with the formation (e.g., a carbonate formation) at a second reaction rate according to the equation:

Second reaction rate=k₂*[second fluid mode]

where k₂ is the rate constant. In embodiments, the first reaction rate is greater than the second reaction rate. In embodiments, the second reaction rate is essentially zero. Stated in other terms, in embodiments, the second fluid is essentially non-reactive with respect to the formation under the conditions present.

In embodiments, a fracturing fluid system comprises at least two discrete phases. One of the phases comprises an inorganic acid, e.g., HCl, which may be present as an aqueous solution, or which may be a dispersed phase of a water-in-oil emulsion. The other phase is less reactive, or essentially inert, with respect to the carbonate surfaces of the formation.

Accordingly, in embodiments, the first fluid comprises an aqueous carrier fluid and the second fluid comprises an aqueous carrier fluid. In other embodiments, the first fluid comprises an aqueous carrier fluid and the second fluid comprises an oleaginous carrier fluid. In still other embodiments the first fluid comprises an oleaginous carrier fluid and the second fluid comprises an aqueous carrier fluid. In still other embodiments, the first fluid comprises an oleaginous carrier fluid and the second fluid comprises an oleaginous carrier fluid. In embodiments, the first fluid, the second fluid, or both may comprise an emulsion, particulates, proppant, anchorants, fibers, flakes, and/or the like.

The method further comprises employing a sequential pumping schedule with relatively short intervals i.e., less than 2.5 minutes or less than one minute, for example, 10-20 seconds, or a rapid frequency of pulsing one fluid then the next fluid sequentially to generate a fluid stream having relatively slim “strips” or relatively small portions of the two phases in the essentially continuous fluid stream being delivered to the wellbore. In embodiments, a lower viscosity acid phase will intermix in a non-uniform manner, e.g. via fingering, into the preceding less reactive phase. In embodiments, the less reactive phase or fluid comprises a gel phase. The intermixing or fingering achieves an extensive penetration rendering the pad phase into discrete “pockets” or “islands”. Hence the rock surface of the formation will not be contacted with all of the acid present in a particular portion of the fluid stream and thus, will not be consumed by the acid, serving as the pillar in the fracture.

FIG. 2 compares a conventional method with embodiments according to the instant disclosure, showing the interpenetration of low-viscosity and high-viscosity fluid modes 14, 16 in the form of fingering 18 caused by the viscosity differential between the first mode fluid 16 and the second mode fluid 18 in a comparative method where the slugs are relatively large, versus the interpenetration of low-viscosity and high-viscosity fluid modes 24, 26 in the form of fingering 28 caused by the viscosity differential between the first mode fluid 26 and the second mode fluid 28 according to embodiments of the instant disclosure, having much shorter pumping intervals. The resultant isolated islands of the second fluid modes 26 serve as masks to shield the rapid etching reaction on formation surface, hence leading to pillars and other heterogeneous formations.

In embodiments, the relative phase viscosities of the two fluids may be determined according to: “The Unstable Displacement Theory (“A Method for Predicting the Performance of Unstable Miscible Displacement in Heterogeneous Media,” E. J. Koval, SPE 450-PA, volume 3, #2, pp. 145-154, 1963), which may be adapted according to the present disclosure by one having minimal skill in the art.

In addition, the brief retention time of HCl at any given location as a result of the rapidly moving discrete portions of the fluids along the fracture also serves to minimize the spend rate of HCl on a given carbonate surface within the fracture. Accordingly, in embodiments, the method may include providing a rapidly pulsing fracturing pump system to sequentially, and repetitively, inject two or more phases of distinct viscosity and/or acidity at desirable frequencies modulated by, for example, a programmable logic control board, and/or using a programmable digital attenuator, and/or the like, without switching on and then switching off various pumps which inevitably delays pumping rate changes, and which results in much broader intervals of fluids, and thus lacks the level of intermixing achieved by embodiments according to the present disclosure.

As shown in FIG. 3, the concentration profiles of different fluid modes 24, 26 alternate over time. The overlapping portions of the fluid modes 24, 26 indicate the intermixing of the two fluids in the treatment fluid that may be produced, e.g., in the wellbore in transit to the formation, according to some embodiments of the instant disclosure.

Suitable gels include both aqueous gels and non-aqueous or oleaginous gels, which may include one or more gellants dispersed or at least partially dissolved in a carrier fluid. In embodiments, the second fluid comprises hydratable gels, e.g., gels containing polysaccharides such as guars, xanthan and diutan, hydroxyethylcellulose, polyvinyl alcohol, other hydratable polymers, colloids, and the like; or an oil-based gelled fluid or otherwise viscosified oil. In embodiments, the second fluid may comprise an at least partially cross-linked gel to further increase the viscosity of the second fluid.

In embodiments, the first fluid may comprise a mineral acid and the second fluid may comprise a gel and/or one or more organic acids. In embodiments, the first fluid (the acid phase) contains an appropriate level of HCl concentration from about 1 wt % to about 35 wt %, and pumped in between portions of the second fluid comprising organic acids. Organic acids suitable for use herein include those having from 1 to 40 carbon atoms, may be saturated and/or unsaturated, and may comprise aliphatic and/or aromatic moieties, and a carboxyl group, a sulfonic acid group, a phosphonic acid group, and/or the like characterized in that the proton(s) of the acid is only partially dissociable. Accordingly, the organic acids are selected for being weakly acidic. These organic acids form salts and thus attach to the carbonate formation. In addition, the organic acids may be selected to function as masking agents to HCl. In embodiments, the organic acids may contain an alkyl chain having from about 8 to 30 carbon atoms, which repels HCl from accessing the carbonate surface underneath. These materials, including C₈-C₄₀ alkylcarboxylic acid such as octadecanoic acid, C₈-C₄₀ alkylphosphonic acid such as octadecylphosphonic acid, and/or C₈-C₄₀ alkylsulfonic acid such as octadecylsulfonic acid, or their polymerized versions. In embodiments, the organic acids are selected for an ability to bind to the carbonate surface at the cationic sites through a self-assembly mechanism, while their alkyl chains forming a hydrophobic barrier inhibiting the access of HCl to the formation, thus reducing the spend rate of the HCl or other mineral acid present in the first fluid.

In embodiments, the first fluid comprises a mineral acid and the second fluid comprises one or more degradable polymers or one or more degradable polymers in addition to a gel.

Suitable degradable polymers may include, but are not limited to, polyethylene, polyhydroxyalkanoates, poly[R-3-hydroxybutyrate], poly[R-3-hydroxybutyrate-co-3-hydroxyvalerate], poly[R-3-hydroxybutyrate-co-4-hydroxyvalerate], starch-based polymers, polylactic acid and copolyesters, aliphatic-aromatic polyesters, poly(ε-caprolactone), polyethylene terephthalate, polybutylene terephthalate; proteins such as gelatin, wheat and maize gluten, cottonseed flour, whey proteins, myofibrillar proteins, caseins, and combinations thereof. The degradable polymers may degrade through thermal, optical and/or biological routes and may take the form of fiber, bead, flake and/or the like. In embodiments, the degradable polymer may comprise acidic polymers, for example polylactic acid (PLA), polyglycolic acid (PGA), copolymers thereof, and the like. In embodiments, the degradable polymers are selected according to a rate of hydrolysis such that they facilitate sustainable conductivity into the fracture via reducing the spend rate of the mineral acid through delayed hydrolysis.

In embodiments, the first fluid comprises a gellant in combination with the mineral acid. Accordingly, the viscosity of the first fluid may be increased to further mask the mineral acid thus further delaying the contact of the mineral acid with the formation. In embodiments, the gelled first fluid may be utilized with a gelled second fluid, and/or a crosslinked gelled second fluid.

In embodiments, the first fluid may comprise a gelled mineral acid and the second phase may comprise an organic acid as described herein. In some embodiments, the second fluid may comprise a solid acid such as polylactic acid, polyglycolic acid, citric acid, sulfamic acid or the like, including combinations. In embodiments the second fluid may additionally or alternatively comprise chelants. Likewise, in embodiments, the first fluid may comprise a gelled mineral acid and the second fluid may comprise a degradable polymer, a gel, and/or the like as described herein.

In embodiments, one of the first and second fluids may comprise a mineral acid present as a dispersed phase of a water-in-oil emulsion in an oleaginous first fluid. Examples of an emulsified mineral acid include emulsions available under the trade designation SUPER X* EMULSION™ (Schlumberger, Houston, Tex.), which is a 70:30 HCl-in-oil dispersion. In embodiments, the second emulsified mineral acid fluid may be utilized with another fluid such as gelled fluid, a crosslinked fluid, a fluid comprising organic acids, a second fluid comprising degradable polymers, or any combination thereof.

In embodiments, the first fluid may comprise a mineral acid and may further comprise one or more organic acids, one or more degradable polymers, one or more water soluble polymers, and/or the like. In embodiments, the organic acids and/or degradable polymers may be selected to comprise a slower rate of hydrolysis, most likely after the spending of HCl, creating lasting reactivity in the acid fluid and hence, improved heterogeneity within the formation surface initially occupied by the mineral acid fluid. The presence of weaker acid species in the first fluid results in a portion of the carbonate surface having reduced exposure to the mineral acid, which further reduces the spend rate of the mineral acid.

Degradable polymers and/or water soluble polymers of various configurations and compositions (e.g., fibers, beads, flakes and the like) may be selected to function analogously to organic acids of comparable molecular weight, but which may have even slower hydrolysis rates as compared to organic acids. Water soluble polymers may further serve to modulate the viscosity of the first mineral acid fluid to provide improved control over the extent of fingering into the second fluid. In addition, such polymeric species selected for their slow rates of hydration may also contribute to control the rate of leak-off and other issues prevalent during acid fracturing of carbonate formations.

In embodiments, the degradable polymers and/or water soluble polymers may be selected for having slow rates of hydration to provide support to formation strength, which may be particularly beneficial for those regions weakened by mineral acid etching and on a larger scale to so-called soft formations. In embodiments, degradable polymers may be selected for having a percolation threshold which does not weaken the rock subsequent to HCl leak off, such that they also provide for additional conductivity between the formation and the wellbore.

FIG. 4 illustrates the effect of formation stabilization by the degradable polymers 28 loaded in the first mode fluid 24. Subsequent to fluid leak off and closure between the fracture surfaces 30, 32, these slowly hydrating species provide mechanical support to the regions 34 weakened by mineral acid etching.

In embodiments, the first fluid may further include a plurality of degradable polymers selected to provide extended release of acidic species upon hydrolysis, and hence provide continuous etching of the carbonate surface. Up to the point where the hydrolysis takes place, these species act as a temporary mask for the carbonate surfaces underneath, thereby reducing the spend rate of the acid and providing improved heterogeneity to the conductive channels.

In embodiments, the second fluid may comprise a viscoelastic diverting agent (VDA) which leads to differential reactivities in the fingering regions against the rest of the phase. Suitable VDA include anionic surfactants which form a thin film of viscous fluid on the formation surface, hence retarding the mineral acid reactivity when present. By further shielding discrete portions of formation, the presence of a viscoelastic diverting agent further enhances the formation of discrete islands or columns resultant from fingering of the first fluid into the second fluid.

In embodiments, suitable viscoelastic diverting agents may include anionic surfactants, which include alkyl sulfates, alkyl ether sulfates, alkyl ester sulfonates, alpha olefin sulfonates, linear alkyl benzene sulfonates, branched alkyl benzene sulfonates, linear dodecylbenzene sulfonates, branched dodecylbenzene sulfonates, alkyl benzene sulfonic acids, dodecylbenzene sulfonic acid, sulfosuccinates, sulfated alcohols, ethoxylated sulfated alcohols, alcohol sulfonates, ethoxylated and propoxylated alcohol sulfonates, alcohol ether sulfates, ethoxylated alcohol ether sulfates, propoxylated alcohol sulfonates, sulfated nonyl phenols, ethoxylated and propoxylated sulfated nonyl phenols, sulfated octyl phenols, ethoxylated and propoxylated sulfated octyl phenols, sulfated dodecyl phenols, ethoxylated and propoxylated sulfated dodecyl phenols. In embodiments, the viscoelastic diverting agents includes dodecylbenzene sulfonic acid.

In embodiments, suitable viscoelastic diverting agents may include nonionic surfactants, which may include amine oxides, ethoxylated or propoxylated alkyl phenols such as dodecyl phenols, decyl phenols, nonyl phenols, and octyl phenols, etc., ethoxylated or propoxylated primary linear C₄ to C₂₀ alcohols, polyethylene glycols of all molecular weights and reactions, and polypropylene glycols of all molecular weights and reactions.

In embodiments, suitable viscoelastic diverting agents may include hydrotropic surfactants, which may include dicarboxylic acids, phosphate esters, sodium xylene sulfonate, and/or sodium dodecyl diphenyl ether disulfonate.

In embodiments, the second fluid may include one or more weak organic bases, such as amine-containing species. The accelerated reaction between the mineral acid present in the first fluid and the organic base present in the second fluid directs the spending of the mineral acid along the second fluid while retarding its spending toward the carbonate surface of the formation. In addition, the reaction between the mineral acid and the carbonate formation raises the localized pH of the fluid. In embodiments, the organic base may be selected such that this increase in pH is sufficient to precipitate the organic base onto the carbonate surface, thus further masking the surface and preventing further consumption of the mineral acid.

In embodiments, the second fluid may comprise saturated fatty acids, which produce a thin film of hydrophobic coatings on the carbonate surface upon attachment to cationic sites present on the formation, which thus serve to reduce the consumption rate of mineral acid as subsequent portions of the first fluid contact the formation.

In embodiments, the first fluid, the second fluid, or both may comprise a solid particulate, which may include a proppant. In embodiments, the first fluid, the second fluid, or both may comprise an amount of plastic beads. In embodiments, the plastic beads comprise an average particle size distribution of less than or equal to about 1000 microns. In embodiments, the plastic beads have a size domain of 20-40 mesh, or 40-70 mesh, such that the beads function as near-permanent pillars in the formation after the decomposition of the second fluid, to facilitate the formation of a conductive network. In embodiments, the beads comprise polystyrene, polyethylene, polypropylene, poly(methyl methacrylate), and/or the like.

In embodiments, the first fluid, the second fluid, or both may include amounts of one or more solid filler(s) having particle size distributions, and present at concentrations suitable for the modulation or control of a leak-off rate of one or more of the fluids. In embodiments, the solid fillers may be selected to control the viscosity differential between the two phases, and the like.

FIG. 5 shows aggregation in the fracture 36 of the particles into domains 38A, 38B, 38C, 38D of various morphologies in the presence of PLA fibers, which produce a conductive channel network.

In embodiments, the treatment fluid produced according to the instant disclosure is formed by pumping of rapidly alternating oil and mineral acid phases, in the absence of any surfactant or solid species. Such embodiments induce sufficient differential rates of etching on carbonate surface that lead to conductive channel network and also produce a clean fracture ready for further treatment and/or subsequent completion operations.

In embodiments, the treatment fluid produced according to the instant disclosure is formed by pumping of rapidly alternating non-aqueous second fluids and mineral acid containing first fluids, where the second fluid comprises an appropriate concentration of a bifunctional species having at least one terminal moiety having affinity toward carbonate surfaces, while the other moiety functions as a masking agent to the mineral acid fluid. Suitable moieties which function as masking agents include polar hetero-aromatic molecules comprising oxygen, nitrogen and/or sulfur atoms. Suitable moieties which may function as masking agents may comprise C₈-C₄₀ alkyl chains.

In embodiments, the bifunctional species may comprise asphaltenes and/or structural analogues thereof. Asphaltenes may be present as granules, flakes, and/or as fibers. In embodiments, the phase change behavior of asphaltenes may be modulated using various combinations of solvents, and the presence of multivalent (high valent) cations (e.g. Al³⁺, Fe³⁺), and/or precipitation inhibitors, which may be controlled by fluid placement as exerted through pumping. Accordingly, in embodiments, the composition of one or more of the fluids may be controlled to deliver components which produce the onset of asphaltene precipitation at a desirable timing, and hence the location in the fracture. In such embodiments, the extent of aggregation may be controlled to produce a patch size, as well as an interval between individual patches to further maximize a sustained conductivity for the formation fluids. In embodiments, the first fluid, the second fluid, or both may further include PLA and/or latex in the form of fibers, flakes and/or beads to further facilitate aggregation of the aforementioned adsorbents into tightly packed domains that results in a network of conductive channels with high and sustaining performances. Accordingly, in embodiments, at least one of a plurality of second portions comprise asphaltene, polylactic acid, latex, or a combination thereof, and another of the plurality of second portions comprise a multivalent cation.

In embodiments, especially wherein a formation may comprise a mixture of carbonate and clay minerals, the treatment fluid produced according to the instant disclosure is formed by pumping rapidly alternating non-aqueous second fluids and HCl containing first fluids, where the second fluids further comprise species having preferential affinity toward a negatively charged clay surface. Suitable species include quaternary amines, which may include mono, di and/or tri aliphatic chains with carbon numbers between 10 and 30, for example, between 12 and 24, which are selected to anchor the component on the clay, such that the expansive aliphatic chains produce a kinetic barrier (i.e., a mask) to the mineral acid.

In embodiments, a volume to volume ratio of individual portions of the first fluid injected relative to a subsequent or preceding portion of the second fluid is from about 1:99 to about 99:1, for example, 1:9 to 9:1, or 1:5 to 5:1, or 1:3 to 3:1 or 2:1 to 1:2. In embodiments, the treatment fluid according to the instant disclosure is produced by pumping portions of the fluids at a constant ratio to one another. For example, in embodiments, the volumetric ratio of the first fluid pumped relative to the second fluid is held constant at 1:3, or 1:2, or 1:1, or 2:1, or 3:1, etc.

In another embodiment, the treatment fluid according to the instant disclosure is produced by pumping the various fluids such that a volume ratio of the portion of the first fluid injected relative to the portion of the second fluid injected into the wellbore increases (or decreases), e.g., linearly and/or exponentially over a period of time and/or between successive stages or pulses.

In another embodiment, the treatment fluid according to the instant disclosure is produced by pumping the various fluids such that a volume ratio of the portion of the first fluid injected relative to the portion of the second fluid injected into the wellbore is varied in blocks or other intervals over a period of time or between successive stages or pulses.

In embodiments, the concentration of a first component present in the first fluid, a second component present in the second fluid, or both, vary over a period of time. In embodiments, the concentration of a particular component may increase (or decrease), e.g., linearly or exponentially over a period of time or between successive stages, and/or may be varied in blocks or other discrete intervals over a period of time or between successive stages.

In embodiments, the acid concentration in the first fluid is incrementally increased (or decreased) along the pumping sequence, such that the acid capacity at the early acid stages is partially retarded, thus minimizing undue damage to the formation surface while pumping.

In embodiments, the first fluid is pumped directly into the continuously pumping second fluid. Accordingly, the rapid cycling comprises forming discrete intervals of the acid phase in a continuous gel or other second fluid phase. In such embodiments, the mineral acid may be gelled upon mixing with the second fluid, hence retarding acid reactivity.

FIG. 6 shows such another pumping scheme in which a continuous viscosified mode 40 of a treatment stage fluid is pumped while a reactivity mode 42, e.g., such as HCl, is injected periodically. The rate of pulses between the two phases is in the time domain, for example, of less than 2.5 minutes, or less than about 1 minute, or less than or equal to about 30 seconds.

Likewise, in embodiments, the second fluid may be intermittently pumped into a continuously pumped first fluid acid phase. In such embodiments, the difference in the reactivities of the two fluids results in heterogeneous etching rates on carbonate surfaces and therefore improves conductivity in the formation. Such embodiments may be suitable when acid species having slower reaction rates, such as formic acid, acetic acid, and so on are employed in the first fluid, and/or in acid fracturing formations having relatively lower temperatures wherein acid spend rate are not as prevalent.

With reference to FIG. 7, a system 50 used to implement a pumping sequence according to embodiments of the instant disclosure may include a pump system 52 comprising one or more pumps to supply the alternating viscosity and/or reactivity slugs 54, 56 to the wellbore 58 and fracture 60. In embodiments as illustrated, the wellbore 58 may include a substantially horizontal portion 58A, which may be cased or completed open hole, wherein the fracture 60 is transversely or longitudinally oriented and thus generally vertical or sloped with respect to horizontal. A switching station 62 in some embodiments may be provided at the surface to supply feed line 64 with various modes of treatment fluids and/or components from sources 66, 68, 70, 72 which may for example be premixed pad, treatment, transition and/or flush stage fluids, and/or a carrier fluid and neat or concentrated masterbatches of acid(s) or other reactant(s) and viscosifier(s) to allow reliable alternation of reactivity and/or viscosity modes, and any other additives which may be supplied with or in any of the sources 66, 68, 70, 72, in any order, such as, for example, proppants, crosslinkers, loss control agents, friction reducers, clay stabilizers, biocides, breakers, breaker aids, corrosion inhibitors, and/or proppant flowback control additives, or the like. In some embodiments, concentrations of one or more additives, including other or additional reactants and/or viscosifiers, to the fracturing fluid may be alternated, e.g., in addition to alternating acid or chelant concentration. For example breaker for the carrier fluid may be added only to high-viscosity mode fluid, or a higher breaker concentration may be added to high-reactivity mode fluid and a lower breaker concentration may be added to high-viscosity mode fluid. Two or more additives (including reactants and/or viscosifiers) may also be alternated independently.

A programmable controller 74, which may be a programmable logic control board, digital attenuator or the like, may be provided in some embodiments to modulate the frequency of rapidly pulsing for the sequential and repetitive injection of two or more modes of distinct reactivity and/or viscosity. The well may if desired also be provided with a shut in valve 76 to maintain pressure in the wellbore 58 and fracture 60, flow-back/production line 78 to flow back or produce fluids either during or post-treatment, as well as any conventional wellhead equipment.

In some embodiments, the system 50 may be or include blenders commercially available under the trade designations PodSTREAK™ or SuperPOD™ or the like, with appropriate gate switch pulsing.

Embodiments

As is evident from the disclosure herein, a variety of embodiments are contemplated:

• E1. A method comprising: injecting a treatment stage fluid into a subterranean formation above a fracturing pressure to form a fracture in the formation; successively alternating reactivity modes in the treatment stage fluid, in either order, between at least first and second reactivity modes to react with carbonate in the formation at different rates or times to unevenly etch surfaces of the fracture; sustaining injection of the treatment stage fluid during each of the first and second reactivity modes for a period of time from 1 second up to 10 minutes; repeating the successive alternation of reactivity modes for a plurality of cycles; and reducing pressure to facilitate fracture closure and form interconnected, hydraulically conductive channels between opposing fracture surfaces.
• E2. The method of Embodiment E1, wherein one of the first and second reactivity modes comprises a reactant reactive with the carbonate in the formation and the other of the first and second reactivity modes comprises the reactant at a lesser concentration, or in a less reactive form, or is free of the reactant.
• E3. The method of Embodiment E2, wherein the reactant is selected from the group consisting of mineral acids, organic acids, chelants and combinations thereof.
• E4. The method of Embodiment E2 or Embodiment E3, wherein the reactant comprises a solid acid.
• E5. The method of any one of Embodiments E2 to E4, wherein the reactant comprises HCl.
• E6. The method of any one of Embodiments E2 to E5, wherein the reactant is encapsulated.
• E7. The method of any one of Embodiments E2 to E6, wherein the reactant is selected from C₁-C₄₀ organic acids to form a coating on the surfaces of the fracture to inhibit further reaction on the coated surfaces.
• E8. The method of Embodiment E7, wherein the organic acid is selected from carboxylic acids, phosphonic acids, sulfonic acids (including methane sulfonic acid), and combinations thereof.
• E9. The method of Embodiment E8, wherein the organic acid comprises a C₈-C₃₆ organic acid.
• E10. The method of any one of Embodiments E7 to E9 wherein the first reactivity modes comprise the organic acid and the second reactivity modes comprise a mineral acid, wherein the second reactivity modes are more reactive with the carbonate in the formation relative to the first reactivity modes.
• E11. The method of any one of Embodiments E1 to E10 wherein the first reactivity modes comprise a weak organic base to coat surfaces of the fracture to inhibit reaction on the coated surfaces with a subsequent one of the second reactivity modes.
• E12. The method of Embodiment E11, wherein the weak organic base comprises a C₈-C₄₀ amine or ammonium, or a combination thereof.
• E13. The method of any one of Embodiments E1 to E12, further comprising: successively alternating viscosity modes in the treatment stage fluid, in either order, between at least first and second viscosity modes, wherein one of the first and second viscosity modes has a higher viscosity than the other; sustaining injection of the treatment stage fluid during each of the first and second modes for a period of time from 1 second up to 10 minutes; and repeating the successive alternation of viscosity modes for a plurality of cycles.
• E14. The method of Embodiment E13, wherein the relatively low viscosity modes form fingers penetrating into a respective one of any preceding high viscosity mode in the fracture.
• E15. The method of Embodiment E14, wherein the fingers break through the penetrated high viscosity mode into a preceding low viscosity mode.
• E16. The method of Embodiment E14 or Embodiment E15 wherein the fingers form channels between islands of the high viscosity modes.
• E17. The method of any one of Embodiments E13 to E16, wherein the first and second reactivity modes coincide with the first and second viscosity modes, respectively.
• E18. The method of Embodiment E17, wherein the first modes comprise a high viscosity and low reactivity relative to the second modes.
• E19. The method of Embodiment 18, wherein the first mode comprises a viscoelastic diverting agent.
• E20. The method of any one of Embodiments E1 to E19, wherein the treatment stage fluid comprises a gel, a cross-linked gel, an emulsion, a foam, or a combination thereof.
• E21. The method of any one of Embodiments E1 to E20, wherein the treatment stage fluid comprises a solid material slurried in a carrier fluid.
• E22. The method of Embodiment E21, wherein the treatment stage fluid comprises a plurality of polyolefin beads having an average particle size distribution of less than or equal to about 1000 microns (˜20 mesh).
• E23. The method of any one of Embodiments E1 to E22, wherein one of the first and second reactivity modes comprises asphaltene, polylactic acid, latex, or a combination thereof, and the other one of the first and second reactivity modes comprises a multivalent cation.
• E24. The method of any one of Embodiments E1 to E23, wherein one of the first and second reactivity modes comprises an aqueous carrier fluid, and the other one of the first and second reactivity modes comprises an oleaginous carrier fluid.
• E25. The method of any one of Embodiments E1 to E24, wherein the treatment stage fluid comprises a water-in-oil emulsion wherein a reactant with carbonate in the formation is in a dispersed phase.
• E26. The method of any one of Embodiments E1 to E25, further comprising gelling the first reactivity mode, the second reactivity mode or both in the fracture.
• E27. The method of any one of Embodiments E1 to E26, wherein a volumetric ratio of the first reactivity mode to the second reactivity mode is from about 1:99 to about 99:1.
• E28. The method of any one of Embodiments E1 to E27, wherein the sustained periods of time are from about 5 seconds to about 1 minute.
• E29. The method of any one of Embodiments E1 to E28, further comprising injecting a pad stage in advance of the treatment fluid stage, injecting a terminal flush stage, or a combination thereof.
• E30. A method comprising: injecting a treatment stage fluid above a fracturing pressure to form a fracture in a subterranean formation penetrated by a wellbore; successively alternating modes in the treatment stage fluid, in either order, between at least first and second modes; wherein the first modes have a high viscosity relative to the second modes for viscous fingering of the second mode into the first mode in the fracture; wherein the second modes have high reactivity with carbonate in the formation relative to the first mode to unevenly etch surfaces of the fracture; sustaining injection of the treatment stage fluid during each of the first and second modes for a period of time from 5 seconds up to 150 seconds; repeating the successive alternation of modes for a plurality of cycles; and reducing pressure to facilitate fracture closure and form interconnected, hydraulically conductive channels between opposing fracture surfaces.
• E31. The method of Embodiment E30, wherein the viscous fingering from one of the second modes breaks through a respective preceding one of the first modes into a preceding one of the second modes to form channels between islands of the respective preceding first modes.
• E32. The method of Embodiment E30 or Embodiment E31, wherein the first modes comprise gel and the second modes comprise mineral acid.
• E33. The method of Embodiment E32, wherein the gel is crosslinked.
• E34. The method of Embodiment E32 or E33, wherein the second modes comprise gel.
• E35. The method of Embodiment E34, wherein the gel in the second modes is crosslinked.
• E36. The method of any one of Embodiments E30 to E35, wherein the first modes comprise an organic acid having from 1 to 40 carbon atoms.
• E37. The method of Embodiment E36, wherein the organic acid in the first mode forms a coating on the fracture surface to inhibit reaction with the mineral acid.
• E38. The method of any one of Embodiments E30 to E37, wherein the second modes comprise an organic acid having from 1 to 40 carbon atoms.
• E39. The method of Embodiment E38, wherein the organic acid in the second mode initially inhibits reaction of the carbonate in the formation with the mineral acid, or after reduction of a concentration of the mineral acid in the second mode facilitates reaction with the carbonate in the formation, or both.
• E40. The method of any one of Embodiments E30 to E39, wherein the first modes comprise a degradable polymer.
• E41. The method of Embodiment E40, wherein the degradable polymer in the first mode forms a coating on the fracture surface to inhibit reaction with the mineral acid.
• E42. The method of any one of Embodiments E30 to E41, wherein the second modes comprise a degradable polymer.
• E43 The method of Embodiment E42, wherein the degradable polymer in the second mode initially inhibits reaction of the carbonate in the formation with the mineral acid, or after reduction of a concentration of the mineral acid in the second mode facilitates reaction with the carbonate in the formation, or both.
• E44. The method of any one of Embodiments E40 to E43, wherein the degradable polymer(s) is (are independently) selected from the group consisting of: polyethylene, polyhydroxyalkanoates such as poly[R-3-hydroxybutyrate], poly[R-3-hydroxybutyrate-co-3-hydroxyvalerate], and poly[R-3-hydroxybutyrate-co-4-hydroxyvalerate], starch-based polymers, polylactic acid and copolyesters, polyglycolic acid and copolyesters, aliphatic-aromatic polyesters, poly(ε-caprolactone), polyethylene terephthalate, polybutylene terephthalate; proteins such as gelatin, wheat and maize gluten, cottonseed flour, whey proteins, myofibrillar proteins, caseins, and combinations thereof.
• E45. The method of any one of Embodiments E40 to E43, wherein the degradable polymer(s) is (are independently) selected from polylactic acid, polyglycolic acid and copolymers thereof.
• E46. The method of any one of Embodiments E40 to E45, wherein the degradable polymer comprises a mixture in the respective mode(s) of at least two polymer species that degrade to form acid, wherein each of the at least two polymer species have a different rate of hydrolysis.
• E47. The method of any one of Embodiments E30 to E46, wherein the second mode comprises an emulsion of the mineral acid in an oleaginous carrier fluid.
• E48. The method of any one of Embodiments E30 to E47, wherein adjacent ones of the first and second modes have a viscosity difference in the fracture of at least 50 mPa-s.
• E49. The method of any one of Embodiments E30 to E48, wherein adjacent ones of the first and second modes have a second mode:first mode volumetric ratio of 1:1 or more.
• E50. The method of Embodiment E49, wherein the second mode:first mode volumetric ratio is from 1:1 to 10:1.
• E51. The method of Embodiment E49 or Embodiment E50, wherein the second mode:first mode volumetric ratio in adjacent ones of later-injected modes is greater than in adjacent ones of earlier-injected modes.
• E52. The method of any one of Embodiments E30 to E51, wherein a concentration of mineral acid in later-injected second modes is greater than in earlier-injected second modes.
• E53. The method of any one of Embodiments E30 to E52, wherein one or more of the first modes comprises a viscoelastic diverting agent.
• E54. The method of Embodiment E53, wherein the viscoelastic diverting agent comprises anionic surfactant.
• E55. The method of any one of Embodiments E30 to E54, wherein the first modes comprise a non-aqueous phase.
• E56. The method of Embodiment E55, wherein the non-aqueous phase comprises asphaltene.
• E57. The method of Embodiment E56, further comprising precipitating patches of the asphaltene on a surface of the formation in the fracture.
• E58. The method of any one of Embodiments E55 to E57, wherein the first modes comprise fibers, flakes, beads or combinations thereof.
• E59. The method of Embodiment E58 wherein the fibers, flakes, beads or combinations thereof comprise polylactic acid, polyglycolic acid, latex or combinations thereof.
• E60. The method of any one of Embodiments E55 to E59, comprising modulation phase change behavior of one or more components of the nonaqueous phase by adjusting solvent composition, multivalent cation concentrations, precipitation inhibitors or a combination thereof.
• E61. The method of any one of Embodiments E1 to E60, wherein the treatment stage fluid comprises proppant.
• E62. The method of any one of Embodiments E1 to E61, wherein the formation comprises clay and the treatment stage fluid comprises C₈-C₄₀ amine or ammonium, or a combination thereof to form a hydrophobic coating on the clay.
• E63. A system, comprising: a subterranean formation penetrated by a wellbore; a treatment fluid stage disposed in the wellbore, the treatment fluid stage comprising a plurality of first mode substages disposed in the wellbore in an alternating sequence with a plurality of second mode substages, wherein the first mode substages have a high viscosity relative to the second mode substages and wherein the second mode substages have a high reactivity with carbonate in the formation relative to the first mode substages; and a pump system to continuously deliver the treatment fluid stage from the wellbore to the formation at a pressure above fracturing pressure to inject the treatment fluid stage into a fracture in the formation, and at a rate wherein each substage is injected into the formation over a period of time from 5 seconds to 2.5 minutes.
• E64. The system of Embodiment E63, wherein the first mode substages comprise a reactant reactive with the carbonate in the formation and the second mode substages comprise the reactant at a lesser concentration, or in a less reactive form, or is free of the reactant.
• E65. The system of Embodiment E64, wherein the reactant is selected from the group consisting of mineral acids, organic acids, chelants and combinations thereof.
• E66. The system of Embodiment E64 or Embodiment E65, wherein the reactant comprises a solid acid.
• E67. The system of any one of Embodiments E64 to E66, wherein the reactant comprises HCl.
• E68. The system of any one of Embodiments E64 to E67, wherein the reactant is encapsulated.
• E69. The system of any one of Embodiments E64 to E68, wherein the reactant is selected from C₁-C₄₀ organic acids to form a coating on the surfaces of the fracture to inhibit further reaction on the coated surfaces.
• E70. The system of Embodiment E69, wherein the organic acid is selected from carboxylic acids, phosphonic acids, sulfonic acids, and combinations thereof.
• E71. The system of Embodiment E70, wherein the organic acid comprises a C₈-C₃₆ organic acid.
• E72. The system of any one of Embodiments E69 to E71 wherein the first mode substages comprise the organic acid and the second mode substages comprise a mineral acid, wherein the second reactivity modes are more reactive with the carbonate in the formation relative to the first reactivity modes.
• E73. The system of any one of Embodiments E63 to E72 wherein the first mode substages comprise a weak organic base to coat surfaces of the fracture to inhibit reaction on the coated surfaces with a subsequent one of the second mode substages.
• E74. The system of Embodiment E73, wherein the weak organic base comprises a C₈-C₄₀ amine or ammonium, or a combination thereof.
• E75. The system of any one of Embodiments E63 to E74, further comprising: successively alternating ones of the first and second mode substages in the fracture.
• E76. The system of Embodiment E75, further comprising fingers of the relatively low viscosity mode substages penetrating into a respective one of any preceding high viscosity mode substage in the fracture.
• E77. The system of Embodiment E76, wherein the fingers break through the penetrated high viscosity mode substage into a preceding low viscosity mode substage.
• E78. The system of Embodiment E76 or Embodiment E77 wherein the fingers form channels between islands of the high viscosity modes.
• E79. The system of any one of Embodiments E63 to E78, wherein the first mode comprises a viscoelastic diverting agent.
• E80. The system of any one of Embodiments E63 to E79, wherein the treatment fluid stage comprises a gel, a cross-linked gel, an emulsion, a foam, or a combination thereof.
• E81. The system of any one of Embodiments E63 to E80, wherein the treatment fluid stage comprises a solid material slurried in a carrier fluid.
• E82. The system of Embodiment E81, wherein the treatment fluid stage comprises a plurality of polyolefin beads having an average particle size distribution of less than or equal to about 1000 microns (˜20 mesh).
• E83. The system of any one of Embodiments E63 to E82, wherein one of the first and second mode substages comprises asphaltene, polylactic acid, latex, or a combination thereof, and the other one of the first and second reactivity mode substages comprises a multivalent cation.
• E84. The system of any one of Embodiments E63 to E83, wherein one of the first and second reactivity mode substages comprises an aqueous carrier fluid, and the other one of the first and second reactivity mode substages comprises an oleaginous carrier fluid.
• E85. The system of any one of Embodiments E63 to E84, wherein the treatment fluid stage comprises a water-in-oil emulsion wherein a reactant with carbonate in the formation is in a dispersed phase.
• E86. The system of any one of Embodiments E63 to E85, further comprising gelled first or second mode substages or both in the fracture.
• E87. The system of any one of Embodiments E63 to E26, wherein a volumetric ratio of the first mode substages to the second mode substages is from about 1:99 to about 99:1.
• E88. The system of any one of Embodiments E63 to E87, wherein the period of time is from about 5 seconds to about 1 minute.
• E89. The system of any one of Embodiments E63 to E88, further comprising a pad stage ahead of the treatment stage fluid, a terminal flush stage behind the treatment stage fluid, or a combination thereof.
• E90. The system of any one of Embodiments E63 to E88, comprising a pad stage ahead of the treatment stage fluid in the fracture; successively alternating ones of the second and first mode substages in the fracture behind the pad stage; viscous fingering in the fracture of the second mode substages into the first mode substages; wherein the fingers break through the penetrated first mode substage into a preceding second mode substage to form channels between islands of the first mode substages.
• E91. The system of Embodiment E90, comprising viscous fingering from a first one of the second mode substages into a pad stage.
• E92. The system of Embodiment E90 or Embodiment E91, wherein the first mode substages comprise gel and the second mode substages comprise mineral acid.
• E93. The system of Embodiment E92, wherein the gel is crosslinked.
• E94. The system of Embodiment E92 or E93, wherein the second mode substages comprise gel.
• E95. The system of Embodiment E94, wherein the gel in the second mode substages is crosslinked.
• E96. The system of any one of Embodiments E90 to E95, wherein the first mode substages comprise an organic acid having from 1 to 40 carbon atoms.
• E97. The system of Embodiment E96, wherein the organic acid in the first mode forms a coating on the fracture surface to inhibit reaction with the mineral acid.
• E98. The system of any one of Embodiments E90 to E97, wherein the second mode substages comprise an organic acid having from 1 to 40 carbon atoms.
• E99. The system of Embodiment E98, wherein the organic acid in the second mode initially inhibits reaction of the carbonate in the formation with the mineral acid, or after reduction of a concentration of the mineral acid in the second mode facilitates reaction with the carbonate in the formation, or both.
• E100. The system of any one of Embodiments E90 to E99, wherein the first mode substages comprise a degradable polymer.
• E101. The system of Embodiment E100, wherein the degradable polymer in the first mode forms a coating on the fracture surface to inhibit reaction with the mineral acid.
• E102. The system of any one of Embodiments E90 to E101, wherein the second mode substages comprise a degradable polymer.
• E103 The system of Embodiment E102, wherein the degradable polymer in the second mode initially inhibits reaction of the carbonate in the formation with the mineral acid, or after reduction of a concentration of the mineral acid in the second mode facilitates reaction with the carbonate in the formation, or both.
• E104. The system of any one of Embodiments E100 to E103, wherein the degradable polymer(s) is (are independently) selected from the group consisting of: polyethylene, polyhydroxyalkanoates such as poly[R-3-hydroxybutyrate], poly[R-3-hydroxybutyrate-co-3-hydroxyvalerate], and poly[R-3-hydroxybutyrate-co-4-hydroxyvalerate], starch-based polymers, polylactic acid and copolyesters, polyglycolic acid and copolyesters, aliphatic-aromatic polyesters, poly(ε-caprolactone), polyethylene terephthalate, polybutylene terephthalate; proteins such as gelatin, wheat and maize gluten, cottonseed flour, whey proteins, myofibrillar proteins, caseins, and combinations thereof.
• E105. The system of any one of Embodiments E100 to E103, wherein the degradable polymer(s) is (are independently) selected from polylactic acid, polyglycolic acid and copolymers thereof.
• E106. The system of any one of Embodiments E100 to E105, wherein the degradable polymer comprises a mixture in the respective mode(s) of at least two polymer species that degrade to form acid, wherein each of the at least two polymer species have a different rate of hydrolysis.
• E107. The system of any one of Embodiments E90 to E106, wherein the second mode comprises an emulsion of the mineral acid in an oleaginous carrier fluid.
• E108. The system of any one of Embodiments E90 to E107, wherein adjacent ones of the first and second mode substages have a viscosity difference in the fracture of at least 50 mPa-s.
• E109. The system of any one of Embodiments E90 to E108, wherein adjacent ones of the first and second mode substages have a second mode:first mode volumetric ratio of 1:1 or more.
• E110. The system of Embodiment E109, wherein the second mode:first mode volumetric ratio is from 1:1 to 10:1.
• E111. The system of Embodiment E109 or Embodiment E110, wherein the second mode:first mode volumetric ratio in adjacent ones of later-injected mode substages is greater than in adjacent ones of earlier-injected mode substages.
• E112. The system of any one of Embodiments E90 to E111, wherein a concentration of mineral acid in later-injected second mode substages is greater than in earlier-injected second mode substages.
• E113. The system of any one of Embodiments E10 to E112, wherein one or more of the first mode substages comprises a viscoelastic diverting agent.
• E114. The system of Embodiment E113, wherein the viscoelastic diverting agent comprises anionic surfactant.
• E115. The system of any one of Embodiments E90 to E114, wherein the first mode substages comprise a non-aqueous phase.
• E116. The system of Embodiment E115, wherein the non-aqueous phase comprises asphaltene.
• E117. The system of Embodiment E116, further comprising precipitating patches of the asphaltene on a surface of the formation in the fracture.
• E118. The system of any one of Embodiments E115 to E117, wherein the first mode substages comprise fibers, flakes, beads or combinations thereof.
• E119. The system of Embodiment E118 wherein the fibers, flakes, beads or combinations thereof comprise polylactic acid, polyglycolic acid, latex or combinations thereof.
• E120. The system of any one of Embodiments E115 to E119, wherein the nonaqueous phase comprises solvent composition, multivalent cation concentrations, precipitation inhibitors or a combination thereof to modulate phase change behavior in the fracture.
• E121. The system of any one of Embodiments E63 to E120, wherein the treatment stage fluid comprises proppant.
• E122. The system of any one of Embodiments E63 to E121, wherein the formation comprises clay and the treatment stage fluid comprises C₈-C₄₀ amine or ammonium, or a combination thereof to form a hydrophobic coating on the clay.
• E123. A system, comprising: a subterranean formation penetrated by a wellbore; means for injecting a treatment stage fluid above a fracturing pressure to form a fracture in the formation; means for successively alternating modes in the treatment stage fluid, in either order, between at least first and second modes; wherein the first modes have a high viscosity relative to the second modes for viscous fingering of the second mode into the first mode in the fracture; wherein the second modes have high reactivity with carbonate in the formation relative to the first mode to unevenly etch surfaces of the fracture; means for sustaining injection of the treatment stage fluid during each of the first and second modes for a period of time from 5 seconds up to 2.5 minutes; means for repeating the successive alternation of modes for a plurality of cycles; and means for reducing pressure to facilitate fracture closure and form interconnected, hydraulically conductive channels between opposing fracture surfaces.

The foregoing disclosure and description is illustrative and explanatory thereof and it can be readily appreciated by those skilled in the art that various changes in the size, shape and materials, as well as in the details of the illustrated construction or combinations of the elements described herein can be made without departing from the spirit of the disclosure.

Claims

1. A method comprising

injecting a treatment stage fluid into a subterranean formation above a fracturing pressure to form a fracture in the formation;

successively alternating reactivity modes in the treatment stage fluid, in either order, between at least first and second reactivity modes to react with carbonate in the formation at different rates or times to unevenly etch surfaces of the fracture;

sustaining injection of the treatment stage fluid during each of the first and second reactivity modes for a period of time from 5 seconds up to 2.5 minutes;

repeating the successive alternation of reactivity modes for a plurality of cycles; and

reducing pressure to facilitate fracture closure and form interconnected, hydraulically conductive channels between opposing fracture surfaces.

2. The method of claim 1, wherein one of the first and second reactivity modes comprises a reactant reactive with the carbonate in the formation and the other of the first and second reactivity modes comprises the reactant at a lesser concentration, or in a less reactive form, or is free of the reactant.

3. The method of claim 2, wherein the reactant is selected from the group consisting of mineral acids, organic acids, chelants and combinations thereof.

4. The method of claim 1, further comprising:

successively alternating viscosity modes in the treatment stage fluid, in either order, between at least first and second viscosity modes, wherein one of the first and second viscosity modes has a higher viscosity than the other;

sustaining injection of the treatment stage fluid during each of the first and second modes for a period of time from 5 seconds up to 2.5 minutes; and

repeating the successive alternation of viscosity modes for a plurality of cycles.

5. The method of claim 4, wherein the first and second reactivity modes coincide with the first and second viscosity modes, respectively.

6. The method of claim 5, wherein the relatively low viscosity modes form fingers penetrating into the high viscosity modes in the fracture.

7. The method of claim 6, wherein the fingers break through the penetrated high viscosity mode into a preceding low viscosity mode.

8. The method of claim 5, wherein the first reactivity and viscosity modes have a high viscosity and low reactivity relative to the second reactivity and viscosity mode.

9. The method of claim 8, wherein the first reactivity and viscosity modes comprises a viscoelastic diverting agent and has a viscosity higher than that of the second reactivity and viscosity modes.

10. The method of claim 1, wherein the treatment stage fluid comprises a gel, a cross-linked gel, an emulsion, a foam, or a combination thereof.

11. The method of claim 1, wherein the treatment stage fluid comprises a solid material slurried in a carrier fluid.

12. The method of claim 1, wherein the treatment stage fluid comprises a plurality of polyolefin beads having an average particle size distribution of less than or equal to about 1000 microns (˜20 mesh).

13. The method of claim 1, wherein one of the first and second reactivity modes comprises asphaltene, polylactic acid, latex, or a combination thereof, and the other one of the first and second reactivity modes comprises a multivalent cation.

14. The method of claim 1, wherein one of the first and second reactivity modes comprises an aqueous carrier fluid, and the other one of the first and second reactivity modes comprises an oleaginous carrier fluid.

15. The method of claim 1, wherein the treatment stage fluid comprises a water-in-oil emulsion wherein a reactant with carbonate in the formation is in a dispersed phase.

16. The method of claim 1, further comprising gelling the first reactivity mode, the second reactivity mode or both in the fracture.

17. The method of claim 1, wherein a volumetric ratio of the first reactivity mode to the second reactivity mode is from about 1:99 to about 99:1.

18. The method of claim 1, wherein the sustained periods of time are from about 5 seconds to about 1 minute.

19. The method of claim 1, further comprising injecting a pad stage in advance of the treatment fluid stage, injecting a terminal flush stage, or a combination thereof.

20. A method comprising:

injecting a treatment stage fluid above a fracturing pressure to form a fracture in a subterranean formation penetrated by a wellbore;

successively alternating modes in the treatment stage fluid, in either order, between at least first and second modes;

wherein the first modes have a high viscosity relative to the second modes for viscous fingering of the second mode into the first mode in the fracture;

wherein the second modes have high reactivity with carbonate in the formation relative to the first mode to unevenly etch surfaces of the fracture;

sustaining injection of the treatment stage fluid during each of the first and second modes for a period of time from 5 seconds up to 2.5 minutes;

repeating the successive alternation of modes for a plurality of cycles; and

reducing pressure to facilitate fracture closure and form interconnected, hydraulically conductive channels between opposing fracture surfaces.

21. The method of claim 20, wherein the viscous fingering from one of the second modes breaks through one of the first modes into another one of the second modes.

22. A system, comprising:

a subterranean formation penetrated by a wellbore;

a treatment fluid stage disposed in the wellbore, the treatment fluid stage comprising a plurality of first mode substages disposed in the wellbore in an alternating sequence with a plurality of second mode substages, wherein the first mode substages have a high viscosity relative to the second mode substages and wherein the second mode substages have a high reactivity with carbonate in the formation relative to the first mode substages; and

a pump system to continuously deliver the treatment fluid stage from the wellbore to the formation at a pressure above fracturing pressure to inject the treatment fluid stage into a fracture in the formation, and at a rate wherein each substage is injected into the formation over a period of time from 1 second to 2.5 minutes.

23. A system, comprising:

a subterranean formation penetrated by a wellbore;

means for injecting a treatment stage fluid above a fracturing pressure to form a fracture in the formation;

means for successively alternating modes in the treatment stage fluid, in either order, between at least first and second modes;

wherein the first modes have a high viscosity relative to the second modes for viscous fingering of the second mode into the first mode in the fracture;

wherein the second modes have high reactivity with carbonate in the formation relative to the first mode to unevenly etch surfaces of the fracture;

means for sustaining injection of the treatment stage fluid during each of the first and second modes for a period of time from 5 seconds up to 2.5 minutes;

means for repeating the successive alternation of modes for a plurality of cycles; and

means for reducing pressure to facilitate fracture closure and form interconnected, hydraulically conductive channels between opposing fracture surfaces.