RU2796589C2 - Methods for forming barriers in well zones and reducing proppant backwashing - Google Patents

Abstract

FIELD: well stimulation.

SUBSTANCE: group of inventions relates to the field of well stimulation to facilitate production, more specifically, to proppants used in such stimulation, in particular, in a method for treating a part of a wellbore, as well as in a method for forming a near-wellbore zone barrier and for creating the barrier itself. A method for treating a portion of a wellbore includes introducing a first treatment fluid into a distal zone of a subterranean formation, the first treatment fluid comprising a first proppant; introducing a second treatment fluid into a downhole zone of the subterranean formation, the second treatment fluid comprising a second proppant different from the first proppant. In this case, the wellbore zone extends on average 0-10 m from the wellbore, and the far zone extends on average 10-300 m from the wellbore. Moreover, the second proppant has an increased length and a reduced internal volume compared to the first proppant. Reducing the flowback of the first proppant into the wellbore while allowing fluid to flow into the wellbore by forming a wellbore barrier containing the second proppant. Also proposed is a barrier created by the above method, and a method for forming a barrier near the borehole zone.

EFFECT: effective performance.

16 cl, 12 dwg

Description

BACKGROUND OF THE INVENTION

[1] This application claims priority over U.S. Provisional Application No. 62/783,564, filed Dec. 21, 2018, which is incorporated herein by reference in its entirety.

[2] The statements in this section merely provide background information relating to the present invention and may not represent prior art.

[3] The present invention relates generally to the field of well stimulation to facilitate production, and more particularly to proppants used in such stimulation.

[4] Hydrocarbons (such as oil, condensate, and gas) can be produced from wells that are drilled in subterranean formations containing them. For a number of reasons, such as low reservoir permeability or formation damage caused by drilling and completion of the well, or other reasons resulting in low hydrocarbon conductivity in the well, the flow of hydrocarbons into the well may be undesirably weak. In this case, the well is "stimulated" by, for example, hydraulic fracturing, chemical (eg, acid) stimulation, or a combination thereof (often referred to as acid fracturing or acid fracturing).

[5] Treatment by hydraulic fracturing and acid fracturing may include two stages. The first stage involves pumping a viscous fluid, called a pad, which usually does not contain proppants, into the formation at a rate and pressure high enough to fracture the formation and create a fracture in it. In the subsequent second stage, a proppant-containing slurry is pumped into the formation to transport the proppant into the fracture(s) formed in the first stage. In “acidic” fracturing, the second-stage fluid may contain an acid or other chemical, such as a chelating agent, that can dissolve some of the rock, causing uneven erosion of the fracture surface and removal of some of the minerals, resulting in the fracture not being completely closed. when the download stops. Sometimes hydraulic fracturing can be performed without the use of a high viscosity fluid (eg, water) to minimize the damage caused by polymers or the cost of other viscosity enhancers. After injection is complete, the fracture is closed with proppant, which keeps the fracture open to allow flow of formation fluid (eg, hydrocarbons) into the wellbore.

[6] Proppant is usually made from materials such as sand, glass beads, ceramic beads, or other materials. Sand is often used as a proppant for treating hydraulic fractures. However, fractures with high closure stress, such as greater than 6,000 psi (41.3 MPa), in deep or high stress wells require a higher strength proppant. The closure stress that sand can withstand is typically around 6,000 psi. inch (41.3 MPa), so the clamping stress is more than 6,000 psi. inch (41.3 MPa) can crush the sand into small particles and destroy the sand plug, which will lead to insufficient conductivity of the formation fluid flow into the wellbore. In addition, fine particles may continuously flow backwards during production from the well, and thus the conductivity of the well may be further reduced, resulting in a short well life or costly re-fracturing of the well. In addition, some of the proppant may leak out of the fracture and block flow or reduce the conductivity of the fracture.

[7] Ceramic proppant is used to maintain the conductivity of wells with high closure stress. Typically, the higher the content of alumina (Al ₂ O ₃ ), the higher the hardness and viscosity of the ceramic proppant, but also the higher its specific gravity. If a high viscosity fracturing fluid is not used, high specific gravity can lead to rapid gravitational settling of the proppant, making it difficult to transport the proppant into the fracture, especially at locations far from the wellbore. Also, rapid settling in the fracture leads to the absence of proppant in the upper part of the fracture, which reduces the productivity of the well. To transport high specific gravity proppant with a low viscosity fracturing fluid, fibers can be added to the fluid as an additive. See, for example, US Patent No. 8,657,002, the entire contents of which are incorporated herein by reference. In order to effectively use fiber to transport proppant, it should be taken into account that there may be an interaction force between the fiber and the proppant.

[8] Other proppant shapes have been proposed for fracturing applications. See, for example, US Patent/Application Nos. 2011/0180259; 8 562 900; 2016/0115375; 8 562 900; U.S. Patent Nos. 4,060,497; 5 500 162; 6 197 073; and 2006/0016598. See also co-pending US Patent Applications Nos. 2017/0145298 and 2017/0198191, the entire contents of which are incorporated herein by reference.

[9] Despite advances in proppant application technology, there is still a need to effectively stimulate wellbores while preventing contamination of the wellbore by proppant injected into the formation.

SUMMARY OF THE INVENTION

[10] The following description is a general summary of some aspects of the invention to provide a basic understanding of the present invention. In this summary of the invention presents a selection of concepts, which are further described below in the detailed description. This summary is not an extensive overview of the invention and is not intended to identify key or critical elements or to indicate the scope of the claims. The present summary is also not intended to determine the optimal features of the claimed subject matter and is not intended to be used as an aid in limiting the scope of the claimed subject matter. The following summary simply presents some of the concepts of the present invention in general form as an introduction to the more detailed description set forth below.

[11] One aspect of the present invention is a method for treating a portion of a wellbore. The method includes introducing a first treatment fluid into a far zone of a wellbore of a subterranean formation, the first treatment fluid comprising a first proppant; introducing a second treatment fluid into a downhole zone of the subterranean formation, the second treatment fluid comprising a second proppant, the second proppant being different from the first proppant; and reducing backwashing of the first proppant into the wellbore while allowing fluid to flow into the wellbore by forming a wellbore barrier containing the second proppant.

[12] A near-wellbore barrier is formed when a second proppant is placed and interconnected in a near-wellbore zone of a subterranean formation, wherein the near-wellbore barrier comprises gates between the interconnected second proppant, the gate being smaller than the average size of the first proppant. The wellbore barrier may have a fluid permeability of 0.001 to 1×10 ^-5 cm ² . The wellbore barrier can reduce the amount of first proppant backwash by 1-100%. The far zone of the wellbore of the subterranean formation may extend an average of 10-300 meters from the wellbore opening. The near-wellbore zone of the underground formation can pass on average 0-10 meters from the hole in the wellbore. The first proppant may have an average particle size of 0.1 mm to 5 mm. The first proppant may have a spherical particle shape with a roundness and sphericity of more than 0.7 mm and an average diameter of 0.2 mm to 5 mm. The concentration of the first proppant can be from about 0.01% wt. up to about 80% wt. the first fluid to be processed.

[13] The second proppant has an average particle length of 2 mm to 10 mm, an average particle width of 0.2 mm to 1.5 mm, and an average particle length to width ratio of 2:1 to 10:1. The second proppant may have a cross-sectional shape selected from the group consisting of a triangle shape, a two-rod shape, a trefoil shape, a quatrefoil shape, a star shape, and a pentagon shape. The second treatment fluid may contain a second proppant and a third proppant, with the second proppant making up at least 100 grams and up to 30 weight percent of the total amount of proppants in the second treatment fluid. The second treatment fluid may contain a second proppant at a concentration of 100 to 2,400 grams per liter. The first treatment fluid may be introduced as part of the first treatment fluid group, wherein the first treatment fluid group contains 1 to 4 proppants in different fluids.

[14] Another aspect of the present invention is a wellbore barrier formed in accordance with any of the methods described in the previous paragraph.

[15] Another aspect of the present invention is a method for forming near-wellbore barriers, the method comprising introducing a first proppant into a distant subterranean formation; introducing a second proppant into a nearby subterranean formation; and forming a barrier of a nearby subterranean formation, when the second proppant is placed and interconnected in the area of the nearby underground formation, and the barrier of the nearby underground formation contains gates between the mutually connected second proppant, and the size of the gate is less than the average size of the first proppant, and the barrier of the nearby underground formation allows the passage of liquid and reduced first proppant backwash.

[16] Although the foregoing description is provided herein with reference to specific means, materials, and embodiments, it is not intended to limit the details disclosed herein; rather, it extends to all functionally equivalent structures, methods, and uses that fall within the scope of the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

[17] For simplicity and clarity of illustration, the graphics and/or figures illustrate the general mechanism of the method disclosed herein and its components. Description and details of well-known features and methods may be omitted in order to avoid unnecessarily obscuring the present invention.

[18] For a detailed understanding of the present invention, reference should be made to the following detailed description of several aspects, considered in conjunction with the accompanying drawings, in which the same elements are designated by the same reference positions and in which the following is presented.

[19] FIG. 1 illustrates the distribution of the proppant-containing fracturing fluid (slurry) and the displacement fluid (water) at the end of the displacement process.

[20] FIG. 2 is a schematic view of a portion of a wellbore in which a near-wellbore barrier is formed in the near-wellbore zone of a subterranean formation between the wellbore and the far zone of the wellbore.

[21] FIG. 3 is a schematic view of a wellbore barrier where the nearborehole barrier includes gates, the gates having an average size smaller than the average proppant size such that proppant backwash into the wellbore is reduced while fluids are allowed to flow.

[22] FIG. 4.1 is a schematic view of various proppant cross sections.

[23] FIG. Figure 4.2 is a schematic view of particles used for laboratory testing of frictional forces arising from simulated displacement.

[24] FIG. 5 illustrates proppant curvature.

[25]

[26] FIG. 6 is a flow chart of a method for treating a portion of a wellbore.

[27] FIG. 7.1 is a schematic view of improved interactions between a proppant or solid additive and a near-wellbore fracture.

[28] FIG. Figure 7.2 is a schematic view of the measurement of the friction force (f) between particles and the pipe wall when placement forces (F) are applied to the particles.

[29] FIG. 8 is a plot of friction force (F) versus mass (W) of particles including trefoil 418, rod 416, oblate shape 414, and sphere 412.

[30] FIG. 9 is a particle size distribution analysis plot for a conventional 20/40 mesh ceramic proppant and a three-sheet solid rod additive before and after a crush test at 10,000 psi. inch (68.9 MPa).

[31] FIG. 10 is a plot of solid volume fraction (SVF) versus proppant concentration (pounds per gallon added (PPA)).

DESCRIPTION OF THE PREFERRED EMBODIMENTS

[32] It should be noted at the outset that in the development of any actual implementation, numerous decisions may be made, depending on the implementation, to achieve the specific goals of the developer, such as compliance with system and business related constraints, which may vary depending on the implementation. . Furthermore, it should be understood that such development efforts can be complex and lengthy, but will nonetheless be routine for those skilled in the art taking advantage of the present invention.

[33] Before describing the present methods, it should be understood that the present invention is not limited to the specific method or apparatus described, as such may vary. One skilled in the art should understand that the terminology used herein is only intended to describe possible aspects, embodiments and/or implementations and is not intended to limit the scope of the present invention, which will be limited only by the appended claims.

[34] The description and examples are provided solely for the purpose of illustrating some embodiments and should not be construed to limit scope and applicability. In the Summary and Detailed Description of the Invention, each numerical value should be treated as modified by the term "about" (unless it is already explicitly so modified), and then treated as not so modified if, from the context does not follow otherwise. In addition, when reading the sections "Summary of the Invention" and "Detailed Description of the Invention", it should be understood that the range of concentrations listed or described as applicable, suitable, etc., means any and every concentration within the specified range, including extreme values . For example, "range from 1 to 10" should be taken to describe all possible numbers, without exception, on a continuum of about 1 to about 10. Thus, even if certain values are within the range, or none of the values are within the range, explicitly indicated or denoted by several specific values, it should be understood that the inventors mean and understand by this that any and all values within the range should be considered as specified, and that the authors of the present invention mean the entire range and all values \u200b\u200bwithin this range, disclosed and provided throughout the range and all values within the range.

[35] The following definitions are provided to assist those skilled in the art in understanding the detailed description.

Definitions

[36] The term "treatment" or "treat" refers to any underground operation in which a fluid is used in combination with a desired function and/or desired purpose. The term "treatment" or "treat" does not imply any particular action of the liquid.

[37] As used herein, the term "treatment fluid" refers to any pumpable and/or flowable fluid used in underground operations in combination with a desired function and/or desired purpose. In some examples, the pumpable and/or flowable treatment fluid may have any suitable viscosity, such as from about 1 centipoise to about 10,000 centipoise (0.001 Pa*s to 10 Pa*s), for example, from about 10 centipoise to about 1,000 cP (0.01 Pa*s to 1 Pa*s) or about 10 cP to about 100 cP (0.01 Pa*s to 0.1 Pa*s) at a processing temperature that may vary from surface to static temperature (in the reservoir) at the bottom of the well, for example, from about 0 °C to about 200 °C, or from about 10 °C to about 120 °C, or from about 25 °C to about 100 °C, and shear rate (for shear rate see, for example, Introduction to Rheology, Barnes, H.; Hutton, JF; Walters, K. Elsevier, 1989, the entire content of which is incorporated herein by reference) in the range of about 1 s ^-1 to about 1000 s, for example a shear rate in the range of about 100 s ^-1 to about 1000 s ^-1 , or a shear rate in the range of about 50 s ^-1 to about 500 s ^-1 as measured by conventional methods, for example, those described in rheology textbooks, including, for example, Rheology: Principles, Measurements and Applications, Macosko, CW, VCH Publishers, Inc. 1994, the entire contents of which are incorporated herein by reference.

[38] The term “fracturing” refers to the process and methods of breaking up a subterranean formation and creating a fracture, i.e., rock around a wellbore, by injecting fluid at very high pressures (pressure above a certain closure pressure) to increase production rates from hydrocarbon reservoir. Other fracturing methods use conventional techniques known in the art.

[39] The term "solid particle" or "particle" refers to a solid three-dimensional object with a maximum size significantly less than 1 meter. As used herein, the "size" of an object refers to the distance between two arbitrary parallel planes, each of which touches the object's surface at at least one point. The maximum dimension refers to the largest distance an object has between any two parallel planes, and the minimum dimension refers to the smallest distance an object has between any two parallel planes.

[40] It should be understood that the terms "first", "second", "third", etc. are arbitrary designations and are merely intended to distinguish between two or more types of object, action, etc., as the case may be, and do not indicate any particular orientation or sequence. In addition, it should be understood that the mere use of the term "first" does not require the presence of any "second", and the mere use of the term "second" does not require the presence of any "first" or "third", etc.

[41] It should also be understood that in the context of this document and the appended claims, singular forms may include plural forms, unless the context clearly indicates otherwise. Thus, for example, reference to "treatment fluid" may refer to one or more treatment fluids, and reference to "treatment method" includes reference to equivalent features and methods known to those skilled in the art, and so on.

[42] The present invention is not limited in its application to the details of construction and arrangement of components set forth in the following description or illustrated in the drawings. The invention is capable of other embodiments, implementations or aspects and may be practiced or carried out in various ways. In addition, the use of the terms "comprising", "comprising", "having", "attracting", "consisting" and their modified variants includes the elements listed after them and their equivalents, as well as additional elements.

[43] In the context of this document, the terms "rod-shaped particle", "rod-shaped particles", "retaining proppant", "elongated proppant" and "elongated proppant" refer to particle(s) having such a geometric cross section and sizes at which the length of the particle (particles) is greater than the width of the cross section of the particle (particles). The length to width/diameter ratio can be, for example, at least 2:1. The cross-sectional geometry may be substantially circular and the rod-shaped particle may have a length greater than the cross-sectional diameter of the particle. The rod-like particles are not limited to a circular cross-sectional geometry, and other cross-sectional shapes such as triangular or rectangular may be used. In addition, the rod-like particle may be substantially straight along the length of the particle, or the particle may have some degree of curvature along the length of the particle. In this case, the curvature refers to a rod-shaped particle having some bend, so that the main axis along the centerline of the rod-like particle is not straight.

[44] The term "average size" refers to the average size of the solids in the group of solids of each type. Within each group j of particles or flakes, the average size can be calculated as a mass-weighted value.

where N is the number of particles or flakes in the group, (i=1…N) is the size of individual particles or flakes; mi (i=1…N) - masses of individual particles or flakes.

[45] FIG. 1-3 are examples of well sites where a method of treating a portion of a wellbore to reduce proppant backwash can be implemented. According to the method, compositions consisting of mixtures of particles or mixtures of proppants are introduced. The method may include introducing a first treatment fluid or stimulation fluid, wherein the first treatment fluid includes a first proppant or a first proppant mixture of more than one type or size that contains the first proppant. The first treatment fluid may be included in the first group of treatment fluids. The first group of treatment fluids may contain 1-4 different proppant in 1-4 different fluids.

[46] The first proppant may be sized and shaped to extend into the distal zone of the wellbore of the subterranean formation. The method may include introducing a first treatment fluid, which may cause the first proppant, or the first proppant mixture that contains the first proppant, to become stuck, stuck, or stuck in the far zone voids of the wellbore of the subterranean formation. Such voids may be a perforation tunnel, a hydraulic fracture, or a wormhole channel. The introduction of the first treatment fluid may be a single or multiple action if it is desired to stimulate the production of subterranean fluids.

[47] As schematically depicted in FIG. 1, one problem encountered during fracturing operation 100 is that the hydraulic pressure applied in the wellbore 102 to fracture a subterranean formation and introduce proppant in the far zone of the wellbore of the subterranean formation can be so high that that pressure pushes the treatment proppant 104 and the fracturing containing proppant, or proppant mixture, from the near-wellbore zones into the far zones of the wellbore, leaving zones filled with the displacement fluid (water) 106. This phenomenon is sometimes referred to as "overflushing" or "drilling the displacement fluid." This lack of near-wellbore proppant can lead to closure of fractures or voids in the near-wellbore zone after the stimulation pressure is released before or during production. As fractures or voids close in the wellbore zone, the production of underground fluids may be reduced due to plugging or narrowing of the voids in the wellbore zone. This near-wellbore plugging can reduce the permeability of near-wellbore passage of subterranean fluids from the stimulated far zone of the wellbore, even when the far zone of the wellbore is further stimulated with proppants still in place.

[48] In addition, as shown on the right side of FIG. 3, another problem is that after the fracturing pressure is reduced, the proppant can be forced out of the far zone of the wellbore, being subjected to backwashing or re-entering the wellbore. "Backflush" refers to the flowback of proppant into the wellbore. Said backflushing can reduce the production of subterranean fluids from the far reaches of the wellbore because once maintained voids close due to proppant loss. This backwash can also return proppants to the wellbore during production, which can result in damage or wear to expensive equipment.

[49] It has been found that introducing a larger proppant can reduce or reduce this near-wellbore plugging by wedging or anchoring in the near-wellbore zone. However, it has also been found that if a larger proppant is introduced before a smaller proppant, then the larger proppant can block the entry of the smaller proppant into the far zone of the wellbore, which can lead to unsuccessful stimulation of the far zone of the wellbore. In addition, if the larger proppant occupies too much void space, then the production or passage of underground fluid can be reduced to impractical levels due to loss of permeability.

[50] As shown schematically at bottom 324 in FIG. 3, it has been found that the second proppant or retainer proppant can be configured to change the shape of the proppant while increasing the proppant length and size ratio so that the proppant is able and/or more likely to be placed in the voids or fractures of the near-wellbore zone of a subterranean formation. It has also been found that the size and shape of the proppant can be reduced in directions such as width or cross section to reduce the internal volume of the proppant while maintaining proppant strength. This increased length and reduced internal volume can accommodate these containment proppants and keep them from closing larger voids in the near-wellbore region to provide sufficient permeability while reducing or eliminating the near-wellbore washout problem.

[51] FIG. 3 schematically shows in greater detail the various stages along the length of the wellbore 300, with the stages of operations in the wellbore referring to fracturing and wedging. In the previous step 302, the stimulation proppant 304 may be injected through the perforation 312 and through the bottomhole zone 310 of the wellbore into the far zone 306 of the wellbore of the subterranean formation 308, leaving the bottomhole zone 310 of the wellbore without proppant due to overdisplacement. Upon depressurization as shown in step 314, the stimulation proppant 304 will be flushed back or flow back into the perforation 312 and the wellbore 300 . However, in the example of the wellbore fracturing stage 324 (with expanded view 316), the retaining proppant 318 may be introduced into the far zone 306 of the wellbore. The retaining proppant 318 may then be introduced into the bottomhole zone 310 of the wellbore. As depicted in exploded view 316, the proppant retainer 318 forms a near-wellbore network 320 having a gate 322, the gate being smaller than the stimulation proppant 304, which reduces or eliminates backwash or backflow of the stimulation proppant into the wellbore.

[52] As shown in FIG. 2, in a broader form of the method, the method may be part of a fracturing operation 200. In one embodiment, the wellbore 202 has a near-wellbore zone that is enclosed by a cement sheath 204. Prior to the fracturing stage, a perforating tool 206 may be inserted into the wellbore to form perforations 214 laterally out of the wellbore connecting the wellbore 202 to the subterranean formation 224. The stage 212 undergoing fracturing 210 may be isolated from the rest of the wellbore using stage separators 208 . The production module 226 may be connected to a pump 228, and the pump is connected to a first reservoir 230 containing the first proppant (P1), a second reservoir 232 containing the second proppant (P2), and a third reservoir 234 containing the third proppant (P3).

[53] The pump may also be connected to a controller 236. The controller may provide a real-time display of the fracturing process 238. As shown in display 238, a retention fluid (Rf) may be introduced and the products Prd1, Prd2 and Prd3 may be pumped sequentially.

[54] In one example, the first and third proppants may be stimulation proppants. The second proppant may be a holding proppant. At the fracturing stage 210, the first proppant or stimulation proppant 222 may be introduced through the perforation 214 into the far zone 218 of the wellbore of the subterranean formation 224. The second proppant or holding proppant 220 is then introduced into the near wellbore zone 216 to form a near wellbore network 240.

[55] Moreover, it has been found that certain sizes and shapes of the second proppant or retainer proppant can be created, which tend to be arranged to form near-wellbore barriers in the form of a net or weave of retainer proppant, which may resemble a three-dimensional cluster. It has also been found that the formed near-wellbore barrier has gates, as shown in enlarged view 316 in FIG. 3, the gates having a size, longest opening or span, which may be less than the average size of the first or stimulation proppant. The near wellbore barrier can reduce or eliminate backflushing of the stimulation proppant because the gate openings are smaller than the size of the stimulation proppant while still allowing subterranean fluids to pass or flow through the nearborehole barrier.

[56] A wellbore zone of a subterranean formation is a volume, portion or zone of a subterranean formation that extends outwardly 0-10 meters from the wellbore surface, including 0.1-3 meters outward. A wellbore far zone may be a volume or portion of a subterranean formation that extends outwardly 3-300 meters from the surface of the wellbore, or 10-300 meters outward, or 10-200 meters from the surface of the wellbore.

[57] FIG. Figures 4.1, 4.2 and 5 show examples of proppant geometries. As shown in FIG. 4.1, the proppant may have a variety of cross-sectional shapes, including triangle shape 402, double rod shape 404, trefoil shape 406, quatrefoil shape 408, star shape 410, and pentagon shape 412. As shown in FIG. 4.2, the proppant may have various geometries such as a sphere 412, an oblate shape 414, a stem 416, and a trefoil shape 418.

[58] As shown in FIG. 5, the proppant may optionally have a curvature. Curvature can be denoted as α, which is greater than D (α > D), where D is the width of the rod-shaped particle at one end, from the first edge point to the second edge point, and α is the total width at the opposite end of the particle, measured from the total edge at one end to the furthest edge from the common edge at the opposite end.

[59] FIG. 6 shows an example of a method 600 that can be applied to downhole sections 100, 200 to prevent proppant backwash into the wellbore 102, 202. As shown in FIG. 6, in an exemplary method, the method 600 typically begins by drilling a wellbore in a subterranean formation containing subterranean fluid 602. The wellbore is perforated 604 prior to fracturing. The stimulation proppant may be introduced through the perforations into the far zone 606 of the wellbore. The method may include reinjecting the stimulation proppant through the perforations into the far zone 614 of the wellbore as needed to stimulate and keep the subterranean formation from closing. The fracturing stage can be controlled and directed using a controller.

[60] Once it is determined that the stage has been sufficiently stimulated, the controller may instruct the pump to introduce a retention fluid or second treatment fluid into the wellbore zone of the subterranean formation 608. The method may include forming a network in the wellbore zone in the form of an oblong proppant deposit and connection in the near-wellbore zone of the subterranean section at step 610. In one aspect, the method may include reducing the amount of proppant backwash for stimulation from the far zone 612 of the wellbore. The method may include 616 re-executing the process, including procedures 606-612 for additional steps. The second proppant is the "finishing" proppant, and the introduction of the second treatment fluid containing the second proppant is the last injection of the treatment fluid containing the proppant into the wellbore prior to production of the subterranean fluid and/or completion of the stage and/or wellbore. The second proppant may be a tail proppant and is added at the final proppant injection stage for multi-stage fracturing treatment.

[61] A method 606 for introducing a first treatment fluid into a far borehole of a subterranean formation includes introducing a first treatment fluid containing a first proppant, sometimes referred to as a stimulation proppant. The first treatment fluid may contain the first proppant or a proppant mixture that contains the first proppant. The first treatment fluid may also contain a carrier fluid, a viscosity enhancer and/or fiber. The first proppant may have a spherical shape with a roundness and sphericity of more than 0.7, including from 0.7 to 1.0, including from 0.8 to 0.95, in accordance with the current industrial standard; and an average diameter of 0.2 mm to 5 mm, including 0.3 mm to 4 mm, including 1 mm to 3 mm. The first proppant may have an average diameter of 0.2 mm to 5 mm, including 0.3 mm to 4 mm, including 1 mm to 3 mm. The first proppant or stimulation proppant may delay and stimulate production in the far zone of the wellbore of the subterranean formation.

[62] The first proppant or the first mixture of proppants may be contained in the first treatment fluid at a concentration of from about 0.01% wt. up to about 80% wt. the first liquid for processing, including a concentration in the range from about 0.1 wt.%. up to about 25% wt. liquid for processing or concentration in the range from about 1%wt. up to about 10% wt. processing fluids.

[63] A method 608 for introducing a second treatment fluid into a downhole zone of a subterranean formation includes introducing a second treatment fluid containing a second proppant. The second treatment fluid may contain a second proppant or a second proppant mixture that contains the second proppant. The first and second treatment fluids may be different, but may have one or more components in common. In one example, the first proppant and the second proppant may be different, but may have one or more properties, materials, or sizes in common, as long as they differ in at least one shape or size. The second treatment fluid may also include a carrier fluid, a viscosity enhancer, and/or a fiber. The second proppant has an elongated or cylindrical shape. The second proppant may have a length of 2 mm to 10 mm, including 2 mm to 8 mm, including 3 mm to 7 mm. The second proppant has an average width of 0.2 mm to 1.5 mm, including 0.3 mm to 1.2 mm, including 0.5 mm to 1 mm. The second proppant may have an average length to width ratio of 2:1 to 10:1, including 2.5:8, including 3:7. The second proppant may have a cross-sectional shape selected from the group consisting of a triangle shape 402, a double rod shape 404, a trefoil shape 406, a quatrefoil shape 408, a star shape 410, and a pentagon shape 412, as shown in FIG. 4.1.

[64] The second treatment fluid contains from 100 to 2,400 grams per liter of the second proppant, including from 150 to 2,200 grams per liter, including from 200 to 2,000 grams per liter of the second proppant. The second treatment fluid may contain a second mixture of proppants, including at least a second proppant and a third proppant. The second treatment fluid may contain a fourth, fifth, sixth, and so on. proppant. The third proppant may be the same as or different from the first or second proppant. The second treatment fluid may contain a second proppant and a third proppant, wherein the second proppant is at least 100 grams and up to 30 weight percent of the total amount of proppants in the second treatment fluid, including at least 120 grams and up to 25 weight percent. , including from 3 to 20 mass percent of the total amount of proppants in the second treatment fluid. The second treatment fluid may contain a second proppant and a third proppant, wherein the second proppant is from 0.1 to 30 mass percent of the total amount of proppants in the second treatment fluid, including from 1 to 25 mass percent, and including from 3 up to 20 percent. weight percent of the total amount of proppants in the second treatment fluid.

[65] The method 612 for reducing backwash includes reducing backwash of the first proppant or first proppant mixture from the far zone of the wellbore back into the wellbore by forming a near wellbore barrier. The wellbore barrier may be a self-assembled web or web that resembles a three-dimensional agglomeration of the second proppant as the second proppant interconnects with itself and connects to the sides of the wellbore cavities. The wellbore barrier may include gates or openings in the wellbore barrier, wherein the average gate size or the longest span through the gate opening is less than the average size of the first proppant or at least one of the proppants constituting the first proppant mixture. The design of the near-wellbore barrier can help maintain and reinforce cavities in the near-wellbore zone of a subterranean formation. In one embodiment, gates formed in the wellbore barrier allow passage of subterranean fluids while selectively eliminating or reducing passage of the first proppant or at least one of the proppants from the first proppant mixture.

[66] The wellbore barrier has a fluid permeability of 0.001 to 1x10 ^-5 cm ² , including 1x10 ^-3 to 1x10 ^-4 cm ² . The method may include reducing the amount or percentage of the first proppant that is flushed back or returned to the wellbore, as measured relative to a baseline measured previously, without forming a near-wellbore barrier. The percentage reduction in the first proppant or first proppant mixture may be from about 1% to about 100%, including from about 2% to about 80%, including from about 5% to about 50%.

[67] The method may also include 610 forming a network in a near-wellbore zone in a subterranean formation, the wellbore comprising a casing and at least one opening in the casing, the opening having a diameter, the method further comprising: providing a cushion fluid containing the stimulation proppant, wherein the stimulation proppant has the size and shape of the stimulation agent; introducing a pad fluid through the wellbore into a far zone of the wellbore of the subterranean formation; providing a retaining fluid containing an elongated proppant, the elongated proppant having an elongated size and an elongated shape; introducing a retaining fluid into a downhole zone of the subterranean formation; forming a network in the wellbore zone as a reservoir of elongated proppant and interconnecting in the near-wellbore zone of the underground formation, and the network in the near-wellbore zone contains gates between the mutually connected elongated proppant, and the size of the gate is smaller than the size for intensification of the proppant for stimulation and allows the passage of hydrocarbons; and reducing the amount of stimulation proppant that flushes the well back during production of the underground fluid. If necessary, the method can be performed in a different order and repeated.

[68] In more detail, the treatment fluid, including the first and second treatment fluids, are particles or mixtures of particles in a carrier fluid. The carrier fluid may be water: fresh water, formation water, sea water. Other non-limiting examples of carrier fluids include hydratable gels (e.g., guar gums, polysaccharides, xanthan, hydroxyethyl cellulose, etc.), cross-linked hydratable gel, viscosified acid (e.g., gel-based), emulsified acid (e.g., petroleum outer phase) , an activated fluid (eg, N ₂ or CO ₂ based foam) and an oil based drilling fluid containing gelled, foamed or otherwise thickened oil. In addition, the carrier fluid may be a brine and/or may contain a brine. The carrier fluid may include hydrochloric acid, hydrofluoric acid, ammonium bifluoride, formic acid, acetic acid, lactic acid, glycolic acid, maleic acid, tartaric acid, sulfamic acid, malic acid, citric acid, methylsulfamic acid, chloroacetic acid, aminopolycarboxylic acid, 3-hydroxypropionic acid, polyaminopolycarboxylic acid and/or any acid salt. In certain applications, the carrier fluid may include polyaminopolycarboxylic acid and is trisodium hydroxylethylethylenediaminetriacetate, monoammonium salts of hydroxyethylethylenediaminetriacetate and/or monosodium salts of hydroxylethylethylenediaminetetraacetate.

[69] Proppant selection involves many trade-offs driven by economic and practical factors. Such proppants may be natural or synthetic (including but not limited to glass beads, ceramic beads, sand, polymers, and bauxite), coated, or may contain chemicals; and in the case of more than one, they can be used sequentially or in mixtures of different sizes or different materials. The proppant can be coated with resin (cured) or pre-cured with resin. Proppants and gravel in the same or different wells or treatment fluids may be of the same material and/or the same size, and in the present invention, the term "proppant" is intended to include gravel. Irregularly shaped particles can be used. International application WO 2009/088317 describes a hydraulic fracturing method using a proppant slurry containing from 1 to 100 percent of hard, low-elasticity, and low-deformability elongated particles. US Patent Application 2007/768393 describes a proppant that is in the form of substantially rigid, elastic lamellar particles having a maximum to minimum size ratio of greater than about 5, wherein the proppant is at least one of the following: formed from a corrosion resistant material or a corrosion-resistant material is formed on it. Each of the above documents is incorporated herein by reference, so that their entire contents are incorporated herein by reference.

[70] The proppant or particle(s) may also be shaped (herein referred to as d in the form of particles of a certain shape) to improve the bridging ability and stability of the barrier near the wellbore zone. The shaped particles may be in the form of a rod, a cylinder, or a tube with a cross section such as triangular, double rod, trefoil, and quatrefoil. See fig. 4.1. It is believed that the inclusion of particles of a certain shape, such as particles having a trefoil-shaped cross-section, can (1) increase the bridging ability of the composition due to increased frictional forces between the particles and the confining geometry of the perforations and voids behind the casing (2) increase the stability of the barrier due to increased frictional forces and better interaction of particles with fibers and (3) act as a proppant in voids prone to closing behind the casing.

[71] Particle(s) can (may) be made(s) in the form of a degradable material. Non-limiting examples of degradable materials that may be used include certain polymeric materials that are capable of forming acids upon decomposition. These polymeric materials may be referred to herein as "polymeric acid precursors". These materials are usually solid at room temperature. Polymeric acid precursor materials include polymers and oligomers that hydrolyze or decompose in certain chemical environments under known and controlled conditions of temperature, time and pH to release organic acid molecules that may be referred to as "monomeric organic acids". As used herein, the expression "monomeric organic acid" or "monomeric acid" can also include a dimeric acid or an acid with a small number of associated monomeric units that act similarly to a monomeric acid consisting of a single monomeric unit.

[72] The polymeric materials may include polyesters obtained by polymerization of hydroxycarboxylic acids, such as an aliphatic polyester of lactic acid, called polylactic acid; glycolic acid, called polyglycolic acid; 3-hydroxybutyric acid, called polyhydroxybutyrate; 2-hydroxyvaleric acid, called polyhydroxyvaleric acid; epsilon-caprolactone, called polypsilon-caprolactone or polyprolactone; polyesters obtained by esterification of hydroxylamino acids such as serine, threonine and tyrosine; and copolymers derived from mixtures of the monomers listed above. The homopolyesters described above have the following general structure:

where R ₁ , R ₂ , R ₃ , R ₄ are either H, linear alkyl such as CH ₃ , CH ₂ CH ₃ (CH ₂ ) _n CH ₃ , branched alkyl, aryl, alkylaryl, an alkyl functional group (carrying groups carboxylic acid groups, amino groups, hydroxyl groups, thiol groups or other groups), or an aryl functional group (carrying carboxylic acid groups, amino groups, hydroxyl groups, thiol groups or other groups); x is an integer from 1 to 11; y is an integer from 0 to 10; and z is an integer between 2 and 50,000.

[73] Under appropriate conditions (pH, temperature, water content), polyesters such as those described herein can hydrolyze and decompose to form hydroxycarboxylic acid and compounds that belong to those acids referred to above as "monomeric acids".

[74] One example of a suitable polymeric acid precursor as mentioned above is a lactic acid polymer, sometimes referred to as polylactic acid, "PLA", polylactate, or polylactide. Lactic acid is a chiral molecule and has two optical isomers. They are D-lactic acid and L-lactic acid. The poly(L-lactic acid) and poly(D-lactic acid) forms are essentially crystalline in nature. Polymerization of a mixture of L- and D-lactic acids to poly(DL-lactic acid) results in a polymer that is more amorphous in nature. The polymers described herein are essentially linear. The degree of polymerization of linear polylactic acid can vary from a few units (2-10 units) (oligomers) to several thousand (eg 2,000-5,000). Cyclic structures can also be applied. The degree of polymerization of these cyclic structures may be less than that of linear polymers. These ring structures may include ring dimers.

[75] Another example is a polymer of glycolic acid (hydroxyacetic acid), also known as polyglycolic acid (PGA) or polyglycolide. Other materials suitable as polymeric acid precursors are all polymers of glycolic acid with itself or with other groups containing hydroxy acid, as described in US Patent Nos. 4,848,467; 4 957 165; and 4,986,355, the entire contents of which are incorporated herein by reference.

[76] Both polylactic acid and polyglycolic acid can be used as homopolymers, which may contain less than about 0.1% wt. other comonomers. As used in relation to polylactic acid, the term "homopolymer(s)" is meant to include polymers of D-lactic acid, L-lactic acid and/or mixtures or copolymers of pure D-lactic acid and pure L-lactic acid. In addition, random copolymers of lactic acid and glycolic acid and block copolymers of polylactic acid and polyglycolic acid can be used. It is also possible to use combinations of the homopolymers described and/or the copolymers described above.

[77] Other examples of polyesters of hydroxycarboxylic acids that can be used as polymer acid precursors are polymers of hydroxyvaleric acid (polyhydroxyvalerate), hydroxybutyric acid (polyhydroxybutyrate) and their copolymers with other hydroxycarboxylic acids. Polyesters derived from the ring-opening polymerization of lactones, such as epsiloncaprolactone (polypsiloncaprolactone) or copolymers of hydroxyacids and lactones, can also be used as polymeric acid precursors.

[78] Polyesters obtained by esterification of other hydroxyl-containing acid-containing monomers, such as hydroxyamino acids, can be used as precursors of polymeric acids. Naturally occurring amino acids are L-amino acids. Among the 20 most common amino acids, the three containing hydroxyl groups are L-serine, L-threonine, and L-tyrosine. These amino acids can be polymerized to polyesters at the appropriate temperature and using appropriate catalysts by reacting their alcohol and their carboxylic acid group. D-amino acids are less common in nature, but their polymers and copolymers can also be used as polymer acid precursors.

[79] NatureWorks, LLC, Minnetonka, Minnesota, USA, manufactures a solid cyclic lactic acid dimer called "lactide" and produces polymers or polylactates of lactic acid in various molecular weights and degrees of crystallinity under the generic trade name NATUREWORKS™ PLA. The PLAs currently available from NatureWorks, LLC have a number average molecular weight (Mn) up to about 100,000 and a weight average molecular weight (Mw) up to about 200,000, although any polylactide (produced by any process by any manufacturer) can be used. These materials, available from NatureWorks, LLC, typically have a crystalline melting point of about 120°C to about 170°C, but other materials are available. Poly(d,l-lactide) in various molecular weights is also commercially available from Bio-Invigor, Beijing and Taiwan. In addition, Bio-Invigor supplies polyglycolic acid (also known as polyglycolide) and various copolymers of lactic acid and glycolic acid, often referred to as "polyglactin" or poly(lactide-coglycolide).

[80] The degree of crystallinity can be controlled by the production method of homopolymers and production method, as well as the ratio and distribution of lactide and glycolide for copolymers. In addition, the chirality of lactic acid can also affect the crystallinity of the polymer. The polyglycolide may be made in a porous form. Some polymers slowly dissolve in water before hydrolysis.

[81] Amorphous polymers may be useful in certain applications. An example of a commercially available amorphous polymer is NATUREWORKS™ 4060D PLA polymer, available from NatureWorks, LLC, which is poly(DL-lactic acid) and contains approximately 12% wt. D-lactic acid and has a number average molecular weight (Mn) of about 98,000 g/mol and a weight average molecular weight (Mw) of about 186,000 g/mol.

[82] Other polymeric materials that may be useful are polyesters obtained by polymerizing polycarboxylic acid derivatives, such as dicarboxylic acid derivatives, with polyhydroxy compounds, in particular dihydroxy compounds. Polycarboxylic acid derivatives that can be used are dicarboxylic acids such as oxalic acid, propanedioic acid, malonic acid, fumaric acid, maleic acid, succinic acid, glutaric acid, pentanedioic acid, adipic acid, phthalic acid, isophthalic acid, terphthalic acid. acid, aspartic acid or glutamic acid; polycarboxylic acid derivatives such as citric acid, copolymers of poly- and oligoacrylic acid and methacrylic acid; dicarboxylic acid anhydrides such as maleic anhydride, succinic anhydride, pentanedioic anhydride, adipic acid anhydride, phthalic acid anhydride; dicarboxylic acid halides, especially dicarboxylic acid chlorides such as propanedioacyl chloride, malonyl chloride, fumaroyl chloride, maleyl chloride, succinyl chloride, glutaroyl chloride, adipoyl chloride, phthaloyl chloride. Suitable polyhydroxy compounds are dihydroxy compounds such as ethylene glycol, propylene glycol, 1,4-butanediol, 1,5-pentanediol, 1,6-hexanediol, hydroquinone, resorcinol, bisphenols such as bisphenol acetone (bisphenol A) or bisphenol formaldehyde (bisphenol F) ; polyols such as glycerol. When both the dicarboxylic acid derivative and the dihydroxy compound are used, a linear polyester is obtained. It should be understood that when one type of dicarboxylic acid and one type of dihydroxy compound is used, a linear homopolyester is obtained. When several types of polycarboxylic acids and/or a polyhydroxyl-containing monomer are used, copolyesters are obtained. According to Flory-Stockmeier kinetics, the "functionality" of polycarboxylic acid monomers (the number of acid groups per monomer molecule) and the "functionality" of polyhydroxy-containing monomers (the number of hydroxyl groups per monomer molecule) and their respective concentrations will determine the polymer configuration (linear, branched, star-shaped, slightly stitched or fully stitched). These configurations can be hydrolyzed or "decomposed" into carboxylic acid monomers and therefore can be considered polymeric acid precursors. By way of a particular example, without giving an exhaustive list of any possible polyester structures that may be considered, but only to indicate the general structure of the simplest case that may occur, the general structure of linear monopolyesters is as follows:

where R ₁ and R ₂ represent linear alkyl, branched alkyl, aryl, alkylaryl groups; and z is an integer from 2 to 50,000. Other examples of suitable polymeric acid precursors are polyesters derived from phthalic acid derivatives such as polyethylene terephthalate (PET), polybutylene teterephthalate (PBT), polyethylene phthalate (PEN) and the like.

[83] Under appropriate conditions (pH, temperature, water content), polyesters such as those described herein can "hydrolyze" and "decompose" to form polycarboxylic acids and polyhydroxy compounds, regardless of which of the polycarboxylic acid derivatives listed above, the original polyester is synthesized. Compounds of polycarboxylic acids, which are formed during the decomposition of the polymer, are also considered monomeric acids.

[84] Other examples of polymeric materials that can be used are materials obtained by polymerizing sulfonic acid derivatives with polyhydroxy compounds such as polysulfones or phosphoric acid derivatives with polyhydroxy compounds such as polyphosphates.

[85] Such a solid polymeric acid precursor material may undergo irreversible downhole degradation into basic acidic products. As mentioned herein, the term "irreversible" will imply that a solid polymeric acid precursor material, once degraded in the well, should not be recovered in the well, eg, the material should degrade in situ but should not be recovered in situ. The term "degradation" refers to both the two relatively extreme hydrolytic degradations that a solid polymeric acid precursor material may undergo, such as bulk erosion and surface erosion, and to any stage of degradation between these two states. This decomposition may be the result of, among other things, a chemical reaction. The rate at which a chemical reaction occurs may depend on the added chemicals, temperature, and time, among other things. The degradation of solid polymeric acid precursor materials may or may not depend, at least in part, on its structure. For example, the presence of hydrolyzable and/or oxidizable linkages in the backbone often results in material that will degrade as described herein. The degradation rate of such polymers depends on factors such as, but not limited to, repeat unit type, composition, sequence, length, molecular geometry, molecular weight, morphology (e.g., crystallinity, spherulite size, and orientation), hydrophilicity, hydrophobicity, surface area, and additives. . The mode of polymer degradation can also be affected by the environment to which the polymer is exposed, such as temperature, the presence of moisture, oxygen, microorganisms, enzymes, pH, and the like.

[86] Some suitable examples of solid polymeric acid precursor material that can be used include, but are not limited to, the examples described in Advances in Polymer Science, Vol. 157, entitled Degradable Aliphatic Polyesters, edited by A. C. Albertsson, pages 1-138, the entire contents of which are incorporated herein by reference. Examples of polyesters that can be used include homopolymers, random, block, graft, and star and hyperbranched aliphatic polyesters.

[87] Another class of suitable solid polymeric acid precursor material that can be used includes polyamides and polyimides. Such polymers may contain hydrolyzable groups in the polymer backbone which can be hydrolyzed under the conditions found in cement slurries and in the set cement matrix. Such polymers can also form by-products that can be sorbed into the cement matrix. Calcium salts are a non-limiting example of such by-products. Non-limiting examples of suitable polyamides include proteins, polyamino acids, nylon, and poly(caprolactam). Another class of polymers that may be suitable for use includes polymers that may contain hydrolyzable groups not in the polymer backbone, but in the form of side groups. Hydrolysis of the side groups can lead to the formation of a water-soluble polymer and other by-products that can be sorbed by the cement composition. A non-limiting example of such a polymer includes polyvinyl acetate, which upon hydrolysis forms water-soluble salts of polyvinyl alcohol and acetate.

[88] Particle(s) or flakes can be implemented as a material that reacts with chemical agents. Some examples of materials that can be removed by reaction with other agents are carbonates, including calcium and magnesium carbonates and mixtures thereof (reactive with acids and chelates); acid-soluble cement (capable of reacting with acids); polyesters, including esters of lactic hydroxycarboxylic acids and their copolymers (can be hydrolysed with acids and bases); active metals such as magnesium, aluminium, zinc and their alloys (capable of reacting with water, acids and bases), etc. Particles and flakes can also be implemented in the form of a material that accelerates the destruction of other components of the formed barrier. Some non-limiting examples of this are the use of metal oxides (eg MgO) or bases (eg Mg (OH) ₂ ; Ca (OH) ₂ ) or salts of weak acids (eg CaCO ₃ ) to promote the hydrolysis of polyesters such as polylactic or polyglycolic acids.

[89] The particle(s) or flakes can be implemented as a fusible material. Examples of fusible materials that can melt under downhole conditions are: hydrocarbons with a carbon number >30;polycaprolactones; paraffin and waxes; carboxylic acids such as benzoic acid and its derivatives; etc. Wax particles may be applied. These particles are solid at the temperature of the fluid being injected, and the fluid cools the formation sufficiently so that the particles enter the formation and remain solid. Water-based wax is commonly used in wood finishes; in the technological processing of wood; paper and cardboard recycling; in protective architectural and industrial coatings; paper covers; rubber and plastics; ink; textiles; ceramics; etc. They are manufactured by companies such as Hercules Incorporated, Wilmington, Delaware, USA, under the trade name PARACOL ^® , Michelman, Cincinnati, Ohio, USA, under the trade name MICHEM ^® , and ChemCor, Chester, New York, USA. Particularly suitable waxes include those commonly used in commercial car washes. In addition to paraffin waxes, other waxes such as polyethylenes and polypropylenes can also be used.

[90] The particle(s) or flakes can be implemented as a water soluble material or a hydrocarbon soluble material. The list of materials that can be used for dissolution in water includes water-soluble polymers, water-soluble elastomers, carbonic acids, rock salt, amines, inorganic salts. The list of materials that can be used for dissolution in oil includes oil-soluble polymers, oil-soluble resins, oil-soluble elastomers, polyethylene, carbonic acids, amines, waxes).

[91] The composition may further comprise a third number of particles/flakes having a third average particle size that is smaller than the second average particle/flake size. The composition may also contain a fourth or fifth number of particles/flakes. Also in some examples, the same chemistry can be applied to the third, fourth or fifth average particle/flake size. It is also possible in some examples to use a different chemistry for the same third average particle size: for example, in the third average particle size, half of the amount is PLA and the other half is PGA. In order to increase the PVF of a composition, no more than three or four particle sizes are usually required. However, additional particles may be added for other reasons such as the chemical composition of the additional particles, the ease of manufacture of certain materials of the same particles as compared to individual particles, the availability of commercially available particles having certain properties, and for other reasons known in the art. technology.

[92] In some additional examples, the composition further comprises a viscosity enhancer. The viscosity enhancer can be any cross-linked polymer. The polymeric viscosity enhancer may be a metal crosslinked polymer. Suitable polymers for the manufacture of metal crosslinked polymeric viscosity enhancers include, for example, polysaccharides such as substituted galactomannans such as guar gums, high molecular weight polysaccharides composed of mannose and galactose sugars, or guar derivatives such as hydroxypropyl guar (HPG), carboxymethyl hydroxypropyl guar ( CMHPG) and carboxymethyl guar (CMG), hydrophobically modified guars, guar compounds and synthetic polymers. Crosslinking agents based on boron, titanium, zirconium or aluminum complexes are commonly used to increase the effective molecular weight of the polymer and improve their suitability for high temperature well applications.

[93] Other suitable classes of polymers effective as a viscosity enhancer include polyvinyl polymers, polymethacrylamides, cellulose ethers, lignosulfonates, and their ammonium, alkali metal, and alkaline earth metal salts. More specific examples of other typical water-soluble polymers are acrylic acid-acrylamide copolymers, acrylic acid-methacrylamide copolymers, polyacrylamides, partially hydrolyzed polyacrylamides, partially hydrolyzed polymethacrylamides, polyvinyl alcohol, polyalkylene oxides, other galactomannans, heteropolysaccharides obtained by sugar fermentation, and their ammonium salts and alkali metals.

[94] To a lesser extent, cellulose derivatives such as hydroxyethylcellulose (HEC) or hydroxypropylcellulose (HPC), carboxymethylhydroxyethylcellulose (CMHEC) and carboxymethylcellulose (CMC) are used, with or without crosslinkers. Xanthan, diutan, and scleroglucan, the three biopolymers, have been shown to have excellent particle suspending properties, even though they are more expensive than guar derivatives and are therefore less frequently used unless they can be used at lower concentrations.

[95] In other examples, the viscosity enhancer is derived from a crosslinkable, hydratable polymer and a crosslinking retarder, wherein the crosslinker comprises a complex containing a metal and a first ligand selected from the group consisting of amino acids, phosphonic acids, and salts or derivatives thereof. Also, the crosslinked polymer can be obtained from a polymer containing pendant ionic fragments, a surfactant containing oppositely charged fragments, a clay stabilizer, a borate source, and a metal-based crosslinking agent. These examples are described in US Patent Publications US2008-0280790 and US2008-0280788, respectively, the entire contents of which are incorporated herein by reference.

[96] The viscosity enhancer may be a viscoelastic surfactant (VES - English: viscoelastic surfactant). The VES may be selected from the group consisting of cationic, anionic, zwitterionic, amphoteric, nonionic, and combinations thereof. Some non-limiting examples are those cited in US Pat. Viscoelastic surfactants, when used alone or in combination, are capable of forming micelles that form a structure in an aqueous medium that increases the viscosity of a liquid (also referred to as "viscosity-enhancing micelles"). These fluids are usually prepared by mixing appropriate amounts of VES to achieve the desired viscosity. The viscosity of VES fluids can be explained by the three-dimensional structure formed by the components of said fluids. When the concentration of surfactants in a viscoelastic fluid greatly exceeds a certain concentration, and in most cases in the presence of an electrolyte, surfactant molecules coalesce into particles such as micelles that can interact to form a network with viscous and elastic properties.

[97] Generally, particularly suitable zwitterionic surfactants have the formula:

where R represents an alkyl group containing from about 11 to about 23 carbon atoms, which may be branched or straight, and may be saturated or unsaturated; each of a, b, a' and b' is from 0 to 10, and each of m and m' is from 0 to 13; each of a and b is 1 or 2 if m is not 0, and (a+b) is 2 to 10 if m is 0; each of a' and b' is equal to 1 or 2 if m' is not equal to 0, and (a' + b') is from 1 to 5 if m is equal to 0; (m+m') is from 0 to 14; and CH ₂ CH ₂ O may also be OCH ₂ CH ₂ . In some examples, zwitterionic surfactants from the betaine family are used.

[98] Examples of cationic viscoelastic surfactants include the amine salts and quaternary amine salts described in US Pat. Nos. 5,979,557 and 6,435,277, the entire contents of which are incorporated herein by reference. Examples of suitable cationic viscoelastic surfactants include cationic surfactants having the structure:

where R ₁ has from about 14 to about 26 carbon atoms and may be branched or unbranched, aromatic, saturated or unsaturated and may contain carbonyl, amide, retroamide, imide, urea or amine; each of R ₂ , R ₃ and R ₄ independently represents hydrogen or an aliphatic group from C ₁ to about C ₆ which may be the same or different, branched or straight chain, saturated or unsaturated, and one or more of them may be substituted with a group which makes the R ₂ , R ₃ and R ₄ groups more hydrophilic; moreover, the groups R ₂ , R ₃ and R ₄ can be included in a heterocyclic 5 - or 6-membered ring structure, which contains a nitrogen atom; the groups R ₂ , R ₃ and R ₄ may be the same or different; R ₁ , R ₂ , R ₃ and/or R ₄ may contain one or more ethylene oxide and/or propylene oxide units; and X- is an anion. Mixtures of such compounds are also suitable. As a further example, R ₁ contains from about 18 to about 22 carbon atoms and may contain carbonyl, amide or amine, and R ₂ , R ₃ and R ₄ are the same and contain from 1 to about 3 carbon atoms.

[99] Amphoteric viscoelastic surfactants are also suitable. Examples of amphoteric viscoelastic surfactant systems include those described in US Pat. No. 6,703,352, such as amine oxides. Other examples of viscoelastic surfactant systems include those described in US Pat. Nos. 6,239,183; 6 506 710; 7 060 661; 7 303 018; and 7,510,009, for example, amidoamine oxides, the entire content of each of which is incorporated herein by reference. Mixtures of zwitterionic surfactants and amphoteric surfactants are suitable. An example is a mixture of about 13% isopropanol, about 5% 1-butanol, about 15% ethylene glycol monobutyl ether, about 4% sodium chloride, about 30% water, about 30% cocoamidopropyl betaine, and about 2% cocoamidopropylamine oxide.

[100] The viscoelastic surfactant system can also be based on any suitable anionic surfactant. In some examples, the anionic surfactant is an alkyl sarcosinate. The alkyl sarcosinate can essentially have any number of carbon atoms. Alkyl sarcosinates may have from about 12 to about 24 carbon atoms. The alkyl sarcosinate may have from about 14 to about 18 carbon atoms. Specific examples of the number of carbon atoms include 12, 14, 16, 18, 20, 22 and 24 carbon atoms. The anionic surfactant is represented by the chemical formula:

where R ₁ is a hydrophobic chain containing from about 12 to about 24 carbon atoms, R ₂ is hydrogen, methyl, ethyl, propyl or butyl, and X is carboxyl or sulfonyl. The hydrophobic chain may be an alkyl group, an alkenyl group, an alkylarylalkyl group, or an alkoxyalkyl group. Specific examples of the hydrophobic chain include a tetradecyl group, a hexadecyl group, an octadecentyl group, an octadecyl group, and a docosene group.

[101] In some examples, the carrier fluid may optionally contain fibers. The fibers may be straight, curvilinear, curved or wavy. Other non-limiting shapes may include hollow, substantially spherical, rectangular, polygonal, and so on. The fibers or elongated particles may be used in bundles. The fibers may have a length of less than about 1 mm to about 30 mm or more. In some examples, the fibers may have a length of 12 mm or less with a diameter or lateral dimension of about 200 microns or less, typically from about 10 microns to about 200 microns. In the case of elongated materials, the materials may have a ratio between any two of the three dimensions greater than 5:1. In some examples, the fibers or elongated materials may have a length of more than 1 mm, from about 1 mm to about 30 mm, from about 2 mm to about 25 mm, from about 3 mm to about 20 mm, as is typical. In certain applications, the fibers or elongated materials may be from about 1 mm to about 10 mm (eg, 6 mm) in length. The fibers or elongated materials may have a diameter or cross-sectional dimension from about 5 to 100 microns and/or fiber numbers from about 0.1 to about 20, more specifically, fiber numbers from about 0.15 to about 6.

[102] The fiber may be formed from a degradable material or a non-degradable material. The fiber may be organic or inorganic. Non-degradable materials are those in which the fiber remains substantially in its solid form within the wellbore fluids. Examples of such materials include glass, ceramics, basalt, carbon and carbon-based compounds, metals and metal alloys, and so on. Polymers and plastics that do not degrade can also be used as non-degradable fibers. These may include high density plastic materials that are resistant to acids and oils and have a crystallinity greater than 10%. Other non-limiting examples of polymeric materials include nylons, acrylics, styrenes, polyesters, polyethylene, oil resistant thermoset resins, and combinations thereof.

[103] Degradable fibers may include materials that can be softened, dissolved, reacted, or otherwise made to degrade in wellbore fluids. Such materials may be soluble in aqueous fluids or hydrocarbon fluids. Oil-degradable particulate materials that degrade in the produced fluids may be used. Non-limiting examples of degradable materials may include, but are not limited to, polyvinyl alcohol, polyethylene terephthalate (PET), polyethylene, soluble salts, polysaccharides, waxes, benzoic acid, naphthalene-based materials, magnesium oxide, sodium bicarbonate, calcium carbonate, sodium chloride, calcium chloride, ammonium sulfate, soluble resins, and the like; and combinations thereof. Degradable materials may also include materials that are formed from solid acid precursor materials. These materials may include polylactic acid (PLA), polyglycolic acid (PGA), carboxylic acid, lactide, glycolide, PLA or PGA copolymers, and the like, and combinations thereof. Such materials may also further assist in the dissolution of the formation during acid fracturing treatment.

[104] In addition, the fibers can be any fibrous material, such as, but not limited to, natural organic fibers, ground plant materials, synthetic polymer fibers (a non-limiting example is polyester, polyaramid, polyamide, novoloid, or novoloid-type polymer), fibrillated synthetic organic fibers, ceramic fibers, inorganic fibers, metal fibers, metal filaments, carbon fibers, glass fibers, ceramic fibers, natural polymer fibers, and any mixtures thereof. Particularly useful fibers are high hydrophilic coated polyester fibers such as, but not limited to, ^DACRON® polyethylene terephthalate (PET) fibers available from Invista Corp., Wichita, Kansas, USA 67220. Other examples of useful fibers include, but are not limited to , polylactic acid polyester fibers, polyglycolic acid polyester fibers, polyvinyl alcohol fibers, and the like.

[105] The carrier fluid may optionally further contain additional additives, including, but not limited to, acids, fluid loss additives, gas, corrosion inhibitors, scale inhibitors, catalysts, shale stabilizing agents, biocides, friction reducers, combinations thereof, and the like. .P. For example, in some cases it may be desirable to foam the composition with a gas such as air, nitrogen, or carbon dioxide.

[106] The treatment composition or fluid can be used in a variety of subterranean treatment operations including, but not limited to, drilling, fracturing, diversion, zonal isolation, and completion operations (eg, gravel pack). In some examples, treatment fluids may be used to treat a portion of a subterranean formation. Treatment fluids may be injected into a wellbore that is penetrating a subterranean formation as the treatment fluid. For example, the treatment fluid may be allowed to contact the subterranean formation for a period of time. The treatment fluid may be allowed to react with hydrocarbons, formation fluids, and/or subsequently injected treatment fluids. After a selected period of time, the treatment fluid may be withdrawn through the wellbore.

[107] For ease of understanding, the following examples are given. In no way should the following examples be considered to limit or define the scope of the invention as a whole.

EXAMPLES

[108] A series of experiments were conducted to demonstrate processing methods.

Example 1

[109] Referring to the schematic in FIG. 7.1, the proppant or "solid additive" is delivered at the end of the fracturing operation, which may contain any selected fracture conductivity proppant. The drag and displacement forces associated with overflushing can push the particle bundle deeper into the fracture. This scenario has been simulated in the laboratory by obtaining the appropriate physical parameters and boundary conditions. In more detail, the typical element 702 in the crack 720 is in the direction 704 displacement. As schematically depicted at 722, placement force 706 may be applied to a typical element in a laboratory setting. As shown in script 724, one way to provide this data is to place a typical element in a column to reproduce how displacement forces 710 will act against friction forces 708.

[110] Particles considered for laboratory experiments are shown in FIG. 4.2 and include a sphere shape 412, an oblate shape 414, a rod shape 416, and a trefoil shape 418. These particles were made from ceramic. A typical element of a solid additive is mechanical interaction with surfaces representing the walls of a rock crack. In addition, this geometric abstraction was modeled using a cylindrical boundary (tubular structure), with the outer layer of the solid additive interacting with the experimental surface of the tubular structure. The resistance and displacement forces were modeled using a piston in which the solid additive was mechanically displaced under the action of a force acting on the cross section of the tubular structure. During the course of the experiment, the levels of force applied to move the solid binder of additives to be moved with controlled displacement were recorded.

[111] As shown in FIG. 7.2, for laboratory experiments, the diameter of the tubular structure was 20 mm, the applied displacement rate was 0.1 mm/s, and the resulting displacements were on the order of a few centimeters. In FIG. 8 shows the experimentally measured friction forces (mean and standard deviation) as a function of the amount of material used in the test. The friction force was displayed as an equivalent mass (the ratio of the measured force and the gravitational constant). The experimental friction force did not take into account the influence of the sample's own mass. Solid additives consisting of particles with non-spherical morphology have higher friction forces compared to spherical morphology (with the exception of the oblate sample). In particular, rod-shaped particles with a trefoil-shaped cross section showed excellent friction characteristics compared to the test group, followed by rod-shaped particles with a round cross section. Depending on the application, the particle morphology can be designed to achieve the required level of frictional resistance, which in turn can withstand the forces associated with overdrive.

Example 2

[112] The characteristic size (or typical population distribution size) of the solid additive (proppant) is optimized to improve the near wellbore zone (NWZ), or near-wellbore zone of a subterranean formation. In common practice, the size of the proppants selected for the main fracturing treatment is typically smaller than, for example, 20/40 mesh (420 µm to 840 µm) for some unconventional treatments. Small proppant sizes can be beneficial due to the obvious advantages of proppant transport in order to accommodate as much proppant as possible in the formed fracture geometry.

где n ~ 2 для сферических частиц. Следовательно, увеличение размера частиц приводит к нелинейному увеличению проницаемости. В конечном итоге это влияет на перепад давления, возникающий в связке твердой добавки. На основании феноменологического закона Дарси выводят следующее уравнение:[113] Retaining proppant may be designed for a different purpose; the formation of a wellbore barrier that allows the passage of fluids, but prevents the passage of proppants used for stimulation. It has been found that a shape having a greater ability to accommodate or anchor into larger voids in the near-wellbore zone can reduce or eliminate oversold. For example, a spherical proppant tends to roll over the surface until it finds a void corresponding to its approximate diameter. Elongated proppant tends to be placed or fixed in large areas of voids. This can also be achieved by using a larger proppant, but the desirable performance characteristic would be to provide much greater permeability than conventional proppants. In addition to the previously described anchoring mechanism, greater permeability to the solid additive binder will reduce drag and displacement forces generated during overflush. Large solid particles of the additive form large pore spaces, which in turn increase the permeability of the binder. From the body of knowledge in the field of granular mechanics and bundles of particles, it is known that the permeability k of a bundle of particles with a characteristic size d is scaled in such a way that

where n ~ 2 for spherical particles. Therefore, an increase in particle size leads to a non-linear increase in permeability. Ultimately, this affects the pressure drop that occurs in the bond of the solid additive. Based on the phenomenological Darcy's law, the following equation is derived:

where the flow rate q through a porous medium is scaled in proportion to the permeability k and the pressure drop (Δp) per unit length L (μ is the viscosity, w is the width). By increasing the permeability of the system, the effective pressure drop will be minimized and a less disturbed particle bundle will result. Larger solid particles of the additive are also desirable to promote the developing mechanical interactions with the fracture walls. The size of the solid additive can be adapted to the characteristics of the formation being stimulated, such as fracture width (or typical range).

[114] A sample of a solid additive with a rod structure and a trefoil-shaped cross-section was characterized using the method of optical particle size analysis (PSA - English: particle size analysis). The PSA test determines the characteristic particle size depending on the applied reference model (for example, the maximum Feret diameter). Particle size analysis is performed on a ^CAMSIZER® ( ^RETSCH® Technology).

[115] FIG. 9 shows the PSA test results of a sample of trefoil-shaped particles (trefoil, untested - filled circles) obtained from ceramic. The results show the particle size distribution (Sd - English: size distribution) depending on the characteristic size (Cd - English: characteristic size) for an aggregate with Dv10 and Dv90 values of 2.2-4.3 mm. The Dv values correspond to the standard percentile values obtained from the statistical analysis of the distribution based on volume. For example, Dv10 is the particle size at which 10% (by volume) of the sample is smaller and 90% of the sample is larger. Also shown for comparison is a reference sample of 20/40 mesh ceramic particles with predominantly spherical morphology (spherical 20/40 mesh, untested - filled squares) with Dv10 and Dv90 values of 0.7-0.9 mm.

[116] Given the different size ranges between the standard sample and the trefoil particle sample, the permeability of the latter system is expected to be greater. However, the trefoil-shaped particle sample is subjected to the ISO 13503-2 standardized crush test, with a maximum applied load of 10,000 psi. inch (68.9 MPa). This crushed sample is tested on PSA and the result is shown in the figure (trefoil, tested at 10 ksi (68.9 MPa) - open circles). Even though the new particle size distribution has changed due to particle crushing, the Dv10 value is 1.0 mm, which is larger than the Dv90 of the standard sample. These results show that, with the appropriate manufacturing method and material structural properties, large size solid additives can impart high permeability to mitigate the forces associated with overshoot.

Example 3

[117] The characteristic size of the near-wellbore zone (NWZ), or near-wellbore zone of a subterranean formation that the solid additive must support, is more specialized than standard fracturing completion agent structures. For example, some finisher structures using standard ceramic proppants account for up to 30% of the total proppant treatment. Conversely, retaining proppant should be applied in such an amount that it can be placed in a more targeted zone near the wellbore. The estimated characteristic size of the NWZ affected by the oversold may be on the order of several meters. As an example, assume that the radial dimension of the affected NWZ is 5 m. With an initial fracture width of 12 mm, a solids volume fraction of 0.28 (equivalent to 12 PPA), and a solids additive specific gravity of 3.6, the mass of solids delivered would be about 2 000 pounds (907 kg). This is a value an order of magnitude smaller than the standard value used in finisher formulations that do not solve the oversell problem.

[118] Another aspect of the structure that is characteristic of a solid additive is the higher concentration of solids delivered to the well. Standard finisher structures with non-bulk proppants typically have lower values, such as 4-6 PPA (479-719 g/l), for practical applications. This concentration limit is such that it prevents screening, that is, the development of excessive injection pressure at the surface due to proppant agglomeration as a result of poor transportation or the presence of constrictions. The screening effect occurs when a sufficient amount of proppant is agglomerated into the bundle. As a result, the concentration of solids (or PPA) in the treatment slurry begins to increase, for example from point "a" to point "c", whereby the particles in the system become an interconnected bond or a random loose bond (FIG. 10). At this point, the permeability of the system is at its lowest, and with more accumulation, the pressure applied to the fluid flow through the bundle increases, resulting in a sifting event.

[119] In contrast, the structure of the solid additive is such that the suspension is designed for high concentrations, for example, for 12 PPA or higher (1438 g/l). At this concentration, the solid additive may become even more concentrated as the NWZ is reached. This event will contribute to the development of frictional forces to secure the solid additive in the NWZ. At the same time, this tendency to further concentration, for example from point "b" to point "c" (Fig. 10), has a lower probability of occurrence of screening, even because 1) the permeability of the solid additive is much higher than that of standard proppants (large particle size selection), and 2) a relatively small amount of solid additive material is less likely to develop high pressures when the "c" condition is reached.

[120] The above invention and description are illustrative and explanatory, and those skilled in the art will readily appreciate that various changes in size, shape, and materials, as well as details of the illustrated construction or combinations of elements described herein, can be made without deviations from the essence of the present invention.

[121] Although the foregoing description is given herein with reference to specific means, materials, and embodiments, it is not intended to limit the details disclosed herein; rather, it extends to all functionally equivalent structures, methods, and uses that fall within the scope of the appended claims.

Claims (22)

1. A method for treating a part of a wellbore, which includes the steps of: introducing a first treatment fluid into a distal zone of the subterranean formation, the first treatment fluid comprising a first proppant; introduction of the second treatment fluid into the near-wellbore zone of the underground formation, and the second treatment fluid contains the second proppant, which differs from the first proppant, while the near-wellbore zone extends on average 0-10 m from the wellbore, and the far zone extends on average 10- 300 m from the wellbore, and the second proppant has an increased length and a reduced internal volume compared to the first proppant; And reducing the flowback of the first proppant into the wellbore while ensuring the passage of fluid into the wellbore by forming a barrier near the wellbore containing the second proppant. 2. The method of claim 1, wherein the near-wellbore barrier is formed when the second proppant is placed and interconnected in the near-wellbore zone of the subterranean formation, wherein the near-wellbore barrier comprises gates between the mutually connected second proppant, wherein the gate size is less than the average size of the first proppant. 3. The method of claim. 1, in which the barrier near the wellbore zone has a permeability to liquid from 0.001 to 1×10 ^-5 cm ² . 4. The method of claim. 1, in which the barrier near the wellbore reduces the volume of backwash of the first proppant by 1-100%. 5. The method according to claim 1, wherein the first proppant has an average size of 0.1 to 5 mm. 6. The method according to Claim. 1, in which the first proppant has a spherical shape with a roundness and sphericity of more than 0.7 and an average diameter of 0.2 to 5 mm. 7. The method according to p. 1, in which the concentration of the first proppant is from 0.01 to 80% wt. the first fluid to be processed. 8. The method of claim 1, wherein the second proppant has an average length of 2 to 10 mm, an average width of 0.2 to 1.5 mm, and an average length to width ratio of 2:1 to 10:1. 9. The method of claim 1, wherein the second proppant has a cross-sectional shape selected from the group consisting of a triangle shape, a two-rod shape, a trefoil shape, a quatrefoil shape, a star shape, and a pentagon shape. 10. The method of claim 1, wherein the second treatment fluid comprises a second proppant and a third proppant, the second proppant being at least 100 grams per liter and up to 30 weight percent of the total amount of proppants in the second treatment fluid. 11. The method of claim 1, wherein the second treatment fluid has a concentration of 100 to 2400 grams per liter of the second proppant. 12. The method of claim 1, wherein the first treatment fluid is introduced as part of a first treatment fluid group, the first treatment fluid group comprising 1 to 4 proppants in different fluids. 13. The method of claim 1 wherein the second proppant is the proppant being completed. 14. The barrier of the near-wellbore zone, formed by the method according to claim 1. 15. The method of forming a barrier near the wellbore zone, which includes the steps at which the following is carried out: introduction of the first proppant into the far zone of the underground formation; introduction of the second proppant into the nearby zone of the underground formation, while the nearby zone of the underground formation extends on average 0-10 m from the wellbore, and the far zone of the underground formation extends on average 10-300 m from the wellbore, and the second proppant has an increased length and reduced internal volume compared to the first proppant; And the formation of a nearby subterranean formation barrier when the second proppant comes into contact with a nearby subterranean formation zone, wherein the nearby subterranean formation barrier comprises gates between the second proppant, the gate size being smaller than the average size of the first proppant, and the adjacent subterranean formation barrier permits fluid passage and reduces flushing into opposite direction of the first proppant. 16. The method of claim 15, wherein the first proppant has an average size of 0.1 to 5 mm.

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