Method for inducing fracture complexity in hydraulically fractured horizontal well completions

[0001] Hydrocarbon wells are often stimulated by hydraulic fracturing operations in which fracturing fluid can be introduced into a portion of the geological formation penetrated by the well under a hydraulic pressure sufficient to make or enlarge at least one fracture in it. Stimulating or treating a wellbore by such methods increases hydrocarbon production from the wellbore. Fissures are formed when a geological formation is subjected to stress or loads. Document D1 5318123 discloses a method of reconciling perforation positions made by a perforating device with a predetermined direction of propagation of a slit crack.

[0002] In some cases where multiple cracks propagate, these cracks may form a network of interconnected gaps, referred to herein as a "gap network". In some cases, fracture networks may affect fluid flow rates (permeability or conductivity) through formations, and may therefore improve to obtain hydrocarbons from geological formation. Gap networks may vary to some extent in terms of complexity and degree of branching.

[0003] Fracture networks may include induced cracks leading to the geological formation, naturally occurring cracks in the geological formation or combinations thereof. Non-uniform geological formations may contain natural crevices, which may or may not be conductive in their original state. As the fracture is formed in the geological formation, for example in hydraulic fracturing, the natural fractures may change from their original state. For example, natural crevices can expand, contract or otherwise change. In the case of expansion of natural fractures as a result of fracturing, induced cracks and expanded natural fractures can form a network of fractures, in contrast to double-leaf fractures, which are traditionally associated with fracturing operations. Such a network of fractures may result in greater connectivity with deposits, which allows hydrocarbon extraction from a larger number of tracks.

[0004] Some geological formations may exhibit such stress conditions that the multidirectional expansion of the fracture produced in such geological formation is impeded or prevented (e.g. in a manner that would form a branched bite) or such that it is hindered or prevented from expanding sufficiently natural crevices, which makes it difficult to create complex fracture networks. Therefore, the creation of gap networks is often limited by traditional fracturing methods. Therefore, there is a need for an improved method of forming branched gaps and gap networks.

SUMMARY OF THE INVENTION [0005] According to one aspect of the present invention, a method has been developed for causing complex fracturing in a fracturing interval of a geological formation, which includes determining a dimension of stress anisotropy change, providing a well support device configured to vary stress anisotropy in a fracturing interval of a geological formation, changing the stress anisotropy in the fracturing interval and creating a fracture in the fracturing interval in which the stress anisotropy has changed, characterized in that the change in stress anisotropy in the fracturing interval involves creating a fracture in the first fracturing interval, and

ΕΡ 2 456 952 Bl to create a gap in the third fracturing interval, the fracturing interval in which the stress anisotropy is changed is between the first fracturing interval and the third fracturing interval.

[0006] According to a second aspect of the present invention, a wellbore apparatus has been developed comprising a first controlled fracturing tool, a second controlled fracturing tool and a third controlled fracturing tool, the wellbore apparatus being configured to cause a branched fracture in the compartment fracturing a geological formation characterized by that the distance between the first controlled fracturing tool and the second controlled fracturing tool is selected so as to predictably change the anisotropy in the fracturing interval, and that the distance between the second controlled fracturing tool and the third controlled fracturing tool is selected so that predictably change anisotropy in the fracturing interval.

[0007] The present disclosure also provides a method of operating a wellbore which includes producing a gap in a first fracturing interval, producing a gap in a third fracturing interval and producing a gap in a second fracturing interval in which the second fracturing interval is between the first fracturing interval and the third fracturing interval, and wherein the gap in the second fracturing compartment is produced after forming the slots in the first fracturing compartment and in the third fracturing compartment.

[0008] The present disclosure further provides a method of operating a wellbore that includes producing a gap in a first fracturing interval, producing a gap in a third fracturing interval and producing a gap in a second fracturing interval in which the second fracturing interval is between the first fracturing interval and the third fracturing interval, and wherein the gap in the second fracturing compartment is produced after forming the slots in the first fracturing compartment and in the third fracturing compartment.

BRIEF DESCRIPTION OF THE DRAWINGS [0009] Reference is now made to the accompanying drawings.

Fig. 1 is a partial cross-sectional view of a well that penetrates a geological formation.

Fig. 2 is a block diagram of an embodiment of a method for causing a complex crack in a geological formation according to the invention.

Fig. 3 is a block diagram of a method for selecting the dimension of stress anisotropy change.

Fig. 4 is a block diagram of a method for varying stress anisotropy in a fracturing interval of a geological formation or part thereof.

Fig. 5A shows a horizontal cross-section (i.e., top view) through a geological formation that illustrates the main stresses therein.

Fig. 5B shows a vertical cross-section (i.e., side view) through a geological formation that illustrates the main stresses therein.

Fig. 6A is a horizontal cross-section through a geological formation that illustrates the main stress occurring in it during initiation of a crack.

Fig. 6B is a horizontal cross-section through a geological formation that illustrates the main stress occurring therein after the formation of the fracture.

Fig. 7 is a partial cross-sectional view of a well penetrating a geological formation that illustrates multiple fracturing intervals along a deflected well section.

ΕΡ2 456 952 Bl

Fig. 8A is a graph, for a semi-infinite gap, of the relationship between the ratio of stress change to the resulting overpressure of crack propagation and the ratio of distance from crack to crack height.

Fig. 8B is a graph, for the elliptical gap, of the relationship between the ratio of stress change to the resulting overpressure of crack propagation and the ratio of distance from crack to crack height.

Fig. 8C is a graph, for a semi-infinite gap and an elliptical gap, of the relationship between the ratio of stress change to resulting overpressure of crack propagation and the ratio of distance from crack to crack height.

Fig. 9 is a graph of the relationship between the change in stress anisotropy and the distance between the first and second fractures.

Fig. 10 is a graph of the relationship between the change in stress anisotropy and the distance between the first gap and the second gap for the various resulting crack propagation pressures.

Fig. 11 is a partial cross-sectional view of a well drilling the geological formation in which a well handling device comprising a plurality of controlled fracturing tools is shown.

Fig. 12 shows, in partial section, a controlled fracturing tool.

Fig. 13 is a partial cross-sectional view of the mechanical sliding tool.

Fig. 14 is a partial cross-sectional view of a well that penetrates a geological formation in which a mechanical shifting tool is shown, attached to a column of tubing and placed in a well-handling device.

Fig. 15A is a partial cross-sectional view of a well penetrating a geological formation in which the production of the fracture in the first fracturing interval is shown.

Fig. 15B is a partial cross-sectional view of a well penetrating a geological formation in which the production of a fracture in a second fracturing interval is shown.

Fig. 15C is a partial cross-sectional view of a well that penetrates a geological formation in which the formation of a fracture is shown in the third fracturing interval between the first fracturing interval and the second fracturing interval.

Fig. 16 is a partial cross-sectional view of a well that penetrates a geological formation in which multiple fracturing intervals along a deflected well section are shown.

DETAILED DESCRIPTION OF IMPLEMENTATION EXAMPLES [0010] In the following drawings and in the description of the invention given below, similar parts are generally designated, in their entirety in the description of the present invention and in the drawings, by the same corresponding reference numerals. The drawing figures are not necessarily shown on the same scale. Some elements of the invention may be exaggerated in their dimensions or somewhat schematic in their form, and some details of traditional elements may be not shown, for the sake of clarity and conciseness. The present invention allows it to be implemented in various forms. Particular embodiments are described in detail and shown in the drawings, assuming that the present disclosure is considered to be an exemplary illustration of the principles of the invention and is not intended to limit the invention to the embodiments thereof shown and described herein. You should be fully aware of the fact that all technical knowledge passed on through various

ΕΡ 2,456 952 Bl of the embodiments described below may be used alone or in any combination suitable for obtaining the desired results.

[0011] Unless otherwise stated, the use of the terms "combine", "couple", "attach", "attach" or any other term describing the interaction between elements does not imply a limitation to direct interaction between the elements and may also include indirect interaction between the described elements.

[0012] Unless otherwise stated, the terms "top", "top", "up", "upward opening", "above" or other similar terms used should be understood to refer generally to the direction of the surface of the formation; similarly, the terms "down", "bottom", "down", "deep into the hole" or other similar terms should be understood to refer generally to the direction of the formation ending deep in the shaft, regardless of the orientation of the well. The use of one or more of the above terms is not to be understood as meaning positions along an ideally vertical axis.

Unless otherwise stated, the term "geological formation" as used herein should be understood to include both exposed underground and underground covered water such as ocean water or fresh water.

[0014] Fig. 1 is an exemplary working environment of embodiments of the methods, systems and devices disclosed herein. Unless otherwise stated, the horizontal, vertical and deflected nature of any of the figures should not be understood to limit the well to any particular configuration. As shown, the working environment may suitably include a drilling rig 106 located on the surface 104 of the earth and extending over the wellbore 114 pen etching the geological formation 102 and around it to extract hydrocarbons. Wellbore 114 may be drilled in geological formation 102 using any suitable drilling technique. In one embodiment, the drilling rig 106 includes a drilling rig 108 with a drilling rig floor 110. The drilling rig 106 may be conventional and may include an electric motor driven winch ί / or other associated equipment for lowering the work conduit, piping column or both deep into wellbore 114.

[0015] In one embodiment, the wellbore 114 may extend substantially vertically from the ground surface 104 in the vertical well section 115 and may be tilted at any angle to the surface 104 of the earth in the deflected or horizontal well section 116. In one embodiment, the wellbore, such as wellbore 114, may include one or more deflected or horizontal wellbore sections 116. In alternative working environments, the sections or substantially all of the wellbore 114 may be vertical, deflected, horizontal ί / or curved.

[0016] Although the working environment shown in Fig. 1 relates to stationary drilling rig 106, it is obvious to those of ordinary skill in the art that movable drilling towers for refurbishing, well-handling units (e.g., coiled tubing assemblies) can be used similarly similar. In addition, although the exemplary work environment shown in Fig. 1 applies to a well penetrating land on dry land, it should be understood that one or more of the methods, systems and devices presented herein may alternatively be used in other work environments, such as, for example, a work environment within a sea well, i.e. a well penetrating formation geological under the water reservoir.

[0017] This document discloses one or more methods, systems or devices used respectively to cause a complex fracture in a geological formation. References to

ΕΡ 2,456 952 Bl to cause a complex crack in a geological formation, as used herein, includes the formation of branched fractures, fracture networks and the like. Referring to Fig. 2, it graphically illustrates an embodiment of a method used to cause a complex crack, referred to herein as a method of causing a complex crack (JPA) 1000. In one embodiment, the JPA 1000 generally includes characterizing the geological log formation, determining the dimension of the anisotropy change 20, providing a well support device configured to allow anisotropy of the geological formation 30 to change in the fracturing process, changing the stress anisotropy of the geological formation in the fracturing interval 40, and producing a gap in the fracturing interval 50 in which stress anisotropy has been changed. With reference to Fig. 3, an embodiment of the above step is shown in more detail to determine the dimension of the anisotropy change 20. With reference to Fig. 4, an embodiment of the above step to change the stress anisotropy in the fracturing interval of the geological formation is discussed in more detail. The term "fracturing interval" as used herein refers to that part of the geological formation in which a crack may be caused and / or to any adjacent or adjacent part of the geological formation.

[0018] This document also discloses one or more methods, systems and devices used respectively to determine the dimension of the stress anisotropy change in a geological formation. With reference to fig. 3, it presents graphically an example of the implementation of the method used appropriately to select the dimension of the stress anisotropy change in the geological formation and / or its fracturing range, defined in this document as a method of selecting the dimension of the stress anisotropy change (DWZ) 2000. In one embodiment, DWZ 2000 generally includes determining stress anisotropy in a geological formation and / or its fracturing interval 11, predicting the degree of change in stress anisotropy within a fracturing interval for surgery performed with a given dimension of stress anisotropy change 21 and selecting the dimension of stress anisotropy so as to predict change in stress anisotropy in a fracturing interval in a predictable way. [0019] This document also discloses one or more methods, systems and devices used respectively to alter stress anisotropy in the target fracture range of a geological formation. Referring to Fig. 4, it presents graphically an example of the implementation of the method used respectively to change stress anisotropy in the target fracturing range of the geological formation, referred to herein as the method of changing stress anisotropy (ZAN) 3000. In one embodiment, ZAN 3000 generally includes providing a wellhole handling device configured to allow the geological formation anisotropy to change in the fracturing process 30, enabling fluid communication with the first fracturing compartment 41 (wherein the first fracturing compartment is adjacent to the fracturing compartment in stress anisotropy is to be changed), causing the first fracturing compartment 42 to crack, blocking fluid communication with the first fracturing compartment 43, enabling fluid communication with the third fracturing compartment 44 (with the third fracturing compartment adjacent to the fracturing compartment in which stress anisotropy is to be changed), cracking the third fracturing compartment 45 and blocking fluid communication with the third fracturing compartment 46.

[0020] Referring to Fig. 1, in one embodiment, JPA 1000 may optionally include characterizing a geological formation. In such an embodiment, characterize 10 formations

452 456 952 Bl geological may include determining stress anisotropy in a geological formation and / or its fracturing range, determining the presence, extent and / or orientation of any natural crevices, determining the mechanical properties of a geological formation, or a combination of these activities.

[0021] In one embodiment, the characterization of the geological formation may suitably include determining the stress anisotropy in the geological formation r / a in its fracturing range. In one embodiment, DWZ 2000 also includes determining stress anisotropy in the geological formation and / or in its fracturing range 11. The term "stress anisotropy" as used herein refers to the difference between the maximum horizontal stress value and the minimum horizontal stress value.

[0022] As will be appreciated by those skilled in the art, stresses of various values ​​and orientations may occur in a hydrocarbon-containing geological formation. Although individual stresses may be numerous, they can be effectively simplified to three main stresses. For example, referring to Figs. 5A and 5B, different forces acting at a specific point in a geological formation are shown. FIG. 5A shows the horizontal plane passing through the geological formation 102 (i.e., from above, looking deep into the well) and the forces acting horizontally along the x axis and along the y axis (in this figure, the forces acting vertically, e.g. along the z axis, run in the direction perpendicular to this plane). Similarly, Fig. 5B shows a vertical plane passing through geological formation 102 (i.e. side view of the well) and forces acting horizontally along the y axis and forces acting vertically along the z axis (in this figure, forces acting horizontally, e.g. along the x axis, run in a direction perpendicular to this plane). As shown in Figs. 5A and 5B, these forces can be simplified to two horizontally acting forces (i.e. x axis and y axis) and one vertically acting force (i.e. z axis).

[0023] In one embodiment, it can be assumed that the stress acting along the z axis is approximately equal to the weight of the formation above (e.g. towards the surface) of the given location in the geological formation 102. With respect to the stress acting along the horizontal axes, together referred to as the horizontal stress field, for example in Fig. 5A of the x axis and y axis, one of these principal stresses may naturally be greater than the other. The term 'maximum horizontal stress', i.e._HMaxi refers to the orientation of the main horizontal stress with the highest value, and the term "minimum horizontal stress", i.e._ΗΜίη, refers to the orientation of the main horizontal stress with the smallest value. As specialists in the field will notice, c_HMax can be perpendicular to σ_ΗΜΐη · Unless otherwise stated, the term "stress anisotropy" as used herein refers to the difference between the value and_HMax a σ_ΗΜίη · [0024] In one embodiment, the determination of stress anisotropy in a geological formation includes determining_HMax, σ_ΗΜίη or both. In one embodiment, Fr._HMax, σ_ΗΜίπ or both can be determined by any suitable method, system or device. For non-limiting examples of methods, systems or devices suitable for determining Fr._HMin should be input with recording using a dipole instrument for acoustic recording of the well, analysis of the well damage structure, fracturing analysis, testing of fracturing pressure or combinations thereof. In one embodiment, Fr._HMax can be calculated on the basis of σ_ΗΜίη · [0025] Because stress anisotropy refers to the difference between the value of c_HMax a σ_ΗΜΐη, therefore stress anisotropy can be calculated by determining o_HMax and cr_HMin. For example, as shown in Equation I:

Stress anisotropy = a_hmax - σ_ΗΜίη6

ΕΡ2 456 952 Bl [0026] In one embodiment, characterization of the geological formation may suitably include determining the presence, extent and / or orientation of any natural fractures. As will be explained in more detail below, the presence, extent, and orientation of naturally occurring fissures in a geological formation may affect the way the fissure forms in it. Unlimiting (examples of methods, systems or devices suitable for determining the presence, extent, orientation, or combinations thereof, of any naturally occurring gaps are well imaging of the well (e.g. by image recording), extracting and analyzing the core sample, the like, or combinations thereof .

[0027] In one embodiment, the characterization of the geological formation may suitably include determining the mechanical properties of the geological formation, part thereof, or fracturing interval. Non-limiting examples of mechanical properties to be obtained include the Young's modulus of a geological formation, the Poisson's ratio of a geological formation, the Biot constant of a geological formation, or combinations thereof.

[0028] In one embodiment, the mechanical properties obtained for a geological formation can be used to calculate or determine the "fragility" of different parts of this geological formation. Alternatively, in one embodiment, the fragility can be measured in any suitable way. As will be discussed in more detail below, it may be desirable to locate those parts of the geological formation that can qualitatively be characterized as fragile. Alternatively, it may be desirable to quantify the extent to which the geological formation, or part thereof, can be characterized as fragile so as to determine which portion of the geological formation 102 is the most / least fragile. Characteristics of fragility are discussed in more detail in the work entitled "A Composite Determination of Mechanical Rock Properties for Stimulation Design (What To Do When You Don't Have a Sonic Log)", SPE 108139, by Mike Mullen et al., Presented in 2007 at the SPE Rocky Mountain Oil & Gas Symposium Technology Symposium in Denver, Colorado; in the work entitled "Proper Evaluation of Shale Gas Reservoirs Leads to a Mora Effective Hydraulic-Fracture Stimulation", SPE 123586, by Donald Kundert et al., presented in 2009 at the SPE Rocky Mountain Oil & Gas Technology Symposium in Denver, Colorado; and in the work "A Practical Use of Shale Petrophysic for Stimulation Design Optimization: Ali Shale Plays Are Not Clones of the Barnett Shale", SPE 115258, by Rick Rickman et al., presented in 2008 at the SPE Annual Technica conference! Conference and Exhibition in Denver, Colorado.

[0029] Methods for determining the mechanical properties of a geological formation 102 are generally known to those skilled in the art. Non-limiting examples of methods, systems or devices suitable for determining the mechanical properties of a geological formation include recording with a dipole borehole recording instrument, extracting and analyzing a core sample, the like, or combinations thereof. In one embodiment, one or more of the methods used to determine one or more characteristics of a geological formation 102 may be implemented in a vertical well bore section 115, deflected bore section 116, or both. In one embodiment, one or more of the methods used to determine one or more characteristics of the geological formation 102 may be implemented in an adjacent or substantially nearby well (e.g., adjacent or monitoring well).

ΕΡ2 456 952 Bl [0030] Referring to Fig. 1, in one embodiment, the method for causing a complex fracture may conveniently include providing a horizontal or deflected well section 116. In one embodiment, one or more of the characteristics of the geological formation 102 may be used in making and / or orienting the deflected section 116 of the well. In one embodiment, the deflected bore section 116 may be oriented approximately parallel to the σ orientation_Ηωΐη^and approximately perpendicular to the orientation c_HMax. [0031] In one embodiment, the deflected bore section 116 may be present to penetrate, lie adjacent, and / or lie directly at the portion of geological formation 102 that is more fragile (i.e., exhibits relatively high brittleness ) than any other part of the geological formation 102 (for example, in relation to the adjacent, directly adjacent and / or nearby geological formation). Without being limited by theory, the presence of the deflected bore section 116 in and / or near the fragile portion of the geological formation 102 means that the fracture created in this portion of the geological formation may have a lower tendency to close or "fuse". For example, highly susceptible or plastic parts of a geological formation (for example, those parts that have relatively low brittleness) may have a stronger tendency to close or "fuse" after forming a gap in them. In one embodiment, it may be desirable to produce fractures in that portion of the geological formation 102 and / or its fracturing interval that has a slight tendency to close or "fuse" after the fracture is formed therein.

[0032] In one embodiment, the deflected well section 116 may be present to penetrate, lie adjacent, and / or lie directly at a portion of the geological formation that has one or more naturally occurring fractures. In an alternative embodiment, the deflected bore section 116 may be present to penetrate, lie adjacent, and / or lie directly at the part of the geological formation that does not have, alternatively has very few naturally occurring gaps. Without being limited by theory, the presence of the deflected bore section 116 in and / or near the part of the geological formation 102 that has naturally occurring fractures means that the fracture formed therein may have a stronger tendency to open natural fractures, thus achieving greater fracturing complexity .

[0033] In one embodiment, JPA 1000 may conveniently include determining at least one dimension for changing anisotropy 20, The term "dimension for changing anisotropy" as used herein refers to a dimension (e.g., value, measurement , quantity, parameter or the like) which, when used to cause a crack in the geological formation 102 for which it was determined, may change the stress anisotropy in the geological formation, giving a predictable result or approaching it.

[0034] Without being limited by theory, the occurrence of horizontal stress anisotropy, that is, the difference between the value of Οημϊπ and the value of_HMax in geological formation 102 and / or its fracturing range may affect the way the crack caused by it will spread. The occurrence of horizontal stress anisotropy may impede the creation of hydraulic communication with complex fracture networks. For example, the occurrence of horizontal stress anisotropy can cause the crack caused by it to open in substantially only one direction. Without being limited by theory, when a fracture forms in a geological formation and / or its fracturing range, the geological formation is expanded into a shaping fracture or crevices. Be not limited by theory because of the stress in the geological formation and / or its fracturing range in orientation parallel to the orientation

EP 2 456 952 Bl c? HMax greater than the stress in the geological formation and / or its fracturing range in an orientation parallel to the orientation σ_ΗΜίη> a fissure in a geological formation may oppose opening it perpendicular to (i.e. spreading in a direction perpendicular to) the orientation cf_Hmsx · For example, opening a gap in a direction perpendicular to direction c_Hr -_sx may be more difficult than anisotropy.

[0035] Referring to Fig. 6A, it depicts a horizontal plane passing through the geological formation 102. The borehole section 116 passes through the geological formation 102. Σ lines_χ and σ_γ means the major and minor major resultant horizontal stresses occurring in the geological formation 102. The formation of the gap 150 in the geological formation 102 is shown. In the embodiment according to Fig. 6A, σ_χ means σ_ΗΜίη, a ^Qy means o_HMax (it should be noted that the length of the line about_s and σ_χcorresponds to the value of stress exerted along these axes; line length σ_γ is greater than the length of the σ line_χ, which means that the stress value is greater along the line o_s). As shown in Fig. 6A, due to exerting less resistance on the geological formation 102 along the line σ_χ (i.e._HMin), the gap 150 may be formed so that the geological formation 102 is expanded in a direction perpendicular to the line σ_χ. Thus, the gap 150 may typically be formed in such a way that the gap width 151 (i.e., the distance between the walls of the gap 150) may be approximately parallel to c_HMin, and the length 152 of the gap may be approximately parallel to σ_ΗΜ₃[0036] In one embodiment, the formation of the gap 150 in the geological formation 102 may change the value and / or direction by_HMin, <T-iMa_X or both. In one embodiment, the values ​​of_HMin and σ_ΗΜ3χ may change at different rates. Referring to Fig. 6B, it shows the effect of producing a gap 150 in geological formation 102. In one embodiment, the values ​​of a_HMin. N_Hwax or both may increase as a result of the formation of a gap 150 in the geological formation 102. Unbound by theory, due to the expansion of the geological formation 150 in a direction parallel to σ_ΗΜίη due to the formation of the gap 150, value σ_ΗΜίη may increase. Change in the value of σ_ΗΜίη. referred to herein as Δ σκΜίη, may be greater than the change in the value of σ ^ χ, referred to herein as Δ o_HMax- For example, referring to Figs. 6A and 6B, the change in σ value is graphically depicted in them_ΗΜίη and a_HMax, caused by the formation of the gap 150 in the geological formation 102. As shown in Fig. 6A, the value value along the line σ_γwhich means a_HMax, is much greater than the value along the line σ_χwhich means σ_ΗΜίπ · Referring to Fig. 6B, after the formation of the gap 150 in the formation, the values ​​of both c_HMax and σ_ΗΜίη, with σ_ΗΜίη increased more than <JHMax · Namely, in this embodiment, both Δ σ_ΚΜίη as well as Δ c_HMax, are positive, with Δ o_Hwiin is greater than Δ a_HMax- In an embodiment in which the formation of the gap 150 in the geological formation 102 causes the value of Οημιπ to increase at a rate greater than the rate at which the value of e increases_HMax, σ value_ΗΜϊη may approach o_HMax, catch up with_HMax and even exceed c_HMax · Therefore, the difference between the value of a_HMax a σ_ΗΜίη, i.e. stress anisotropy after the creation of the gap 150 in the geological formation 102 and / or its fracturing interval, may be smaller than the stress anisotropy before the creation of the gap 150. In one embodiment, the value of Δ σ_ΗΜίη, Δ o_HMax or both may depend on various other factors, as will be discussed in more detail below (for example, overpressure, crack propagation), and may vary depending on the distance to the gap wall.

[0037] Without being limited by theory, when the value of stress exerted along the line σ_χ (i.e. σ_ΗΜίπ before fracturing) is equal to the stress value along the σ line_γ (i.e. c_HMax before

ΕΡ 2,456 952 Bl fracturing), then the horizontal stress anisotropy is zero. In the event that the horizontal stress anisotropy in the geological formation and / or its fracturing interval is zero, alternatively about or substantially zero, alternatively approximately zero, the fracture that has been created therein need not be limited to opening in only one direction. Without being limited by theory, because of the alternatively equal or substantially equal value of stresses exerted in the geological formation and / or afbo of its fracturing range, the fracture produced in it may open in any, alternatively substantially any direction, because the geological formation does not impede the opening slots in a certain direction. Accordingly, in an embodiment in which stress anisotropy is equal, alternatively roughly or substantially equal, alternatively close to zero, it is possible to form branched fractures resulting in complex fracture networks.

[0038] Alternatively, in one embodiment, the value along tinii σ_χ (i.e._KMin before fracturing) may increase so that it exceeds the value along the line o_s (i.e. a_HMax before fracturing). In such an embodiment, the stress field can be changed such that o_HMax becomes σ before creating the gap_ΗΜίη, and σ_ΗΜίη becomes a before forming the gap_HMax (i.e. value along the line σ_χ after fracturing, it is greater than the value along the line σ_γ after fracturing). In an embodiment in which the stress field in the geological formation and / or its fracturing compartment is inverted in such a way, the gap produced in it may open perpendicular to the direction in which the gap produced in the formation could open before inversion of the stress field, which promotes creating complex gap networks.

[0039] In one embodiment, the dimension for changing anisotropy can be calculated or otherwise determined so that when one or more fractures are formed in the geological formation and / or its fracturing intervals, then anisotropy in a certain portion of the geological formation can change predictably and / or so to obtain predictable anisotropy. For example, in one embodiment, the dimension for changing anisotropy can be calculated such that when a fracture is formed in the geological formation and / or its fracturing range, then anisotropy in the adjacent and / or nearest fracturing range of the geological formation in which the gel is produced, it can change in a substantially predictable manner. Referring to Fig. 7, the gap produced in the fracturing interval 2 of the geological formation 102 can change stress anisotropy both in it and in the fracturing intervals 4 and 6. Similarly, the fractures produced in the fracturing intervals 4 and 6 of the geological formation 102 can change stress anisotropy anywhere, in other fracturing intervals geological formation 102.

[0040] In one embodiment, the dimension of the anisotropy change can be calculated so that the gap formed in the geological formation 102 can reduce anisotropy (i.e. the difference between and_HMax a after forming the gaps (y) is less than the difference between st_HMax a σ_ΗΜίη before creating these gaps), alternatively reduce the anisotropy to almost zero (i.e. the difference between and_HM_ax and σ_ΗΜιη Ρθ formation of gaps (y) is about zero). In one embodiment, the dimension for changing anisotropy can be calculated such that the gap produced in the geological formation 102 reverses the anisotropy (i.e., after creating the fractures, the value in the initial orientation by_HMin is greater than the value in the initial orientation σ _HMax) · As explained above, creating a gap in the fracturing interval (e.g., 2, 4, 6 etc.) of the geological formation 102 may change the horizontal stress field in the geological formation (i.e. in the fracturing interval in which the fracture was created in the fracturing process) , as well as in the compartment adjacent to the fracturing compartment in which it remained

ΕΡ 2 456 952 Bl, the created gap, in the fracturing interval located directly at the fracturing interval in which the fracture was created, or in their combinations.

[0041] In one embodiment, the dimension for changing anisotropy includes a gap between fracturing intervals. The term "gap between fracturing intervals," as used herein, refers to the distance, parallel to the axis of the deflected bore section 116, between the first fracturing interval and the second fracturing interval (for example, the point where the first fracture is formed in formation 102 and the point where a second slit is formed in formation 102).

[0042] In one embodiment, the dimension for changing anisotropy includes the resulting hypertension of the crack propagation. The resulting "hypertension of the crack propagation", as used herein, refers to the pressure that is required to cause further crack formation or spread in the geological formation. In one embodiment, the resulting overpressure of the crack propagation may be influenced by various factors, including non-limiting examples of fracture length, presence of proppant and / or fracturing fluid, fracturing fluid viscosity, fracturing pressure, the like, and combinations thereof.

[0043] In one embodiment, determining the dimension for changing anisotropy may include predicting the degree of change in stress anisotropy over the fracturing interval for surgery performed at a predetermined dimension for changing stress anisotropy. In one embodiment, DWZ 2000 may also include predicting the degree of change in stress anisotropy within the fracturing interval for surgery performed at a predetermined dimension to change stress anisotropy 21.

[0044] In one embodiment, the prediction of the degree of change in stress anisotropy within a fracturing interval includes the development of a fracturing mode indicating the effect of creating one or more fractures in a geological formation. Fracture models can be developed according to any suitable methodology. In one embodiment, graphic analysis can be used to develop the fracturing mode. In one embodiment, the fracturing model developed for a given predefined area can be used anywhere in that area (for example, a correlation can be determined between a fracturing model developed for a predetermined location and another location within the same or similar formation, area, borehole or the like).

[0045] In one embodiment, the graphical analysis approach to develop a fracturing model involves using the mechanical properties of a geological formation (e.g., Young's modulus, Poisson's ratio, Biot constant, or a combination thereof) to calculate the expected resulting overpressure during hydraulic fracture production.

[0046] In the case of a stress field (for example, values ​​and orientation o_HMax and Fr._HMin, as discussed above), which is known, the change in stress in the area around or around the gap due to the formation of this gap can be calculated using an analytical or numerical approach. The change in stress can be directly correlated with the resulting fracturing overpressure (for example by being its function).

[0047] In one embodiment, any suitable analytical solutions can be used. In one embodiment, the solution presented by Sneddon and

ΕΡ2 456 952 Bl

Efliott for calculating the stress distribution (or stresses) in the area of ​​fracture in an elastic medium. To simplify this problem, Sneddon and Elliott assumed that the gap is rectangular and has limited height, and the length of the gap is infinite. In practice, this means that the length of the gap is much greater than its height, namely at least five times greater. It was also assumed (reasonably) that the width of the gap is very small compared to its height and length. Under such a semi-infinite system, it is possible to influence the component stresses. The final solution worked out by Sneddon and Eliiott is given in the equations below and shown in Fig. 8A. In fig. 8A, dimensionless values ​​are shown, namely the ratio of stress to overpressure, along a line perpendicular to the center of the gap, plotted as a function of the dimensionless distance being the ratio of the distance to the height of the gap.

₊ Δ & Χ

2 \ p_about Poęy ~ something (0 - 0.50! - Oh, 50₂) - lj (1) / Δσ ^, Δσ_χ\

V Po Po)

2rcos6 and H²\ 4rjr something

FROM³ (2^

<img file="PL2456952T3_D0001.tif" />

(2)

Po \ po Po '(3)

Where:

θ is the angle from the center of the gap to the point, θ! is the angle from the bottom of the gap to the point, θ₂ is the angle from the top of the gap to the point, r is the distance from the center of the gap to the point, η is the distance from the bottom of the gap to the point, r₂ is the distance from the top of the gap to the point,

H is the height of the gap,

P_about is the resultant hypertension of the crack propagation, av is the Poisson's ratio.

[0048] In an alternative embodiment, any other suitable analytical solution may be used to calculate the effect of the fracture in the case of an elliptical fracture, a random-shaped fracture or other tub. In the embodiment where the gap passes through the boundary at which the mechanical properties of the rock change, a numerical solution may be necessary.

[0049] In an alternative embodiment, calculating the effect of creating two or more slots may include applying the superposition principle. The superposition principle is the mathematical property of linear differential equations with linear boundary conditions. To calculate the effect caused by multiple slots using the superposition principle at a given point, you can calculate the effect of each slot at that point as if the slot existed in an infinite system. 12

ΕΡ2 456 952 Bl

The algebraic addition of the effect of various (e.g. two or more) gaps gives the combined effect of producing these gaps. The slots need not be identical in size in order to apply this principle. The identity of the crevices was adopted only for convenience.

[0050] Referring to Figs. 8A, 8B and 8C, respective models are shown. Fig. 8A shows the variation in the ratio of the change in stress to the resulting overpressure of the crack propagation relative to the ratio of the distance from the gap (L) to the height of the gap (H) for a semi-infinite gap (e.g. for which slot it is assumed that its length is infinite). Similarly, fig. 8B shows the variation in the ratio of stress change to the resulting overpressure of the crack propagation relative to the ratio of the distance from the gap (L) to the height of the gap (H) for the elliptical gap (e.g. for which gap it is assumed that its height is approximately equal to its length). FIG. 8C shows the variation in the ratio of the change in stress to the resulting overpressure of the crack propagation relative to the ratio of the distance from the gap (L) to the height of the gap (H) for both semi-infinite and elliptical gaps.

[0051] In one embodiment, determining the dimension to change anisotropy may include selecting a dimension to change stress anisotropy so as to predict change stress anisotropy in a predictable manner. In addition, referring to Fig. 3, in one embodiment, DWZ 2000 may include selecting a dimension for changing stress anisotropy so as to predict change in stress anisotropy 22 in a predictable manner. In one embodiment, assuming the resulting overpressure of the crack propagation and using at least one of the relationship between the ratio of stress change to the resulting overpressure of the crack propagation and the ratio of the distance from the gap (L) to the height of the gap (H) (for example, as shown in Figures 8A, 8B and 8C) allow the development of a stress anisotropy change model as a function of the effect of the distance between multiple slots. For example, referring to Fig. 9, it shows the change in stress anisotropy in the geological formation and / or its fracturing interval between two slits as a function of distance along the deflected section of the well between the first and second slots. Thus, the gap between fracturing intervals can be selected to achieve the desired change in anisotropy.

[0052] In an alternative embodiment, assuming the gap between fracturing intervals and using at least one of the relationship between the ratio of stress change to the resulting overpressure of the crack propagation and the ratio of the distance from the gap (L) to the height of the gap (H) (e.g. as shown in fig 8A, 8B and 8C) enables the development of a model of stress anisotropy change as a function of the effect of distance on the change of stress anisotropy at a point between these gaps. For example, referring to Fig. 10, it shows the change in stress anisotropy in a portion of the geological formation and / or its fracturing interval between two fractures as a function of the resulting overpressure of crack propagation. Thus, the resulting hypertension of the crack propagation can be selected to achieve the desired change in anisotropy.

[0053] In an alternative embodiment, a mathematical approach may be used to predict the change in stress anisotropy within the fracturing interval, calculating the gap between fracturing intervals, calculating the resulting overpressure, crack propagation, or a combination thereof. In one embodiment, the gap may be designed (e.g., in terms of the gap between fracturing intervals, the resulting overpressure, crack propagation or their combination) using a simulator that can be a two-dimensional, pseudo-triangular measure

ΕΡ2 456 952 Bl or fully three-dimensional. The simulator results give the expected resultant overpressure for the crack of the specified structure and estimated dimensions. In two-dimensional models, the height of the gap can be pre-adopted input information and can be estimated in advance on the basis of various registers determining the lithological and stress diversity of the formation sequence. In pseudo tri-dimensional and fully three-dimensional models, these lithological and stress differences can be part of the input data and contribute to the calculation of the gap height. The resulting overpressure of crack propagation may be a function of the bed's mechanical properties, fracture dimensions and fracture complexity. The gap height and length can be checked using monitoring techniques such as placing the tilt meter inside the well or using microseismic phenomena.

[0054] In one embodiment, the gap dimensions may be designed to achieve optimal complexity. After determining the height and resulting overpressure for a given gap design, the technique described above is used to calculate the distance from the first gap so that when placing the second gap, stress anisotropy is effectively or to some extent neutralized.

[0055] In one embodiment, one of two situations can occur at this point. In the event that at least three slots are to be formed in the geological formation, a third of them is formed between the first slit and the second slit. First, in an embodiment in which the distances between the second and third fractures cannot be modified during fracturing, it may be necessary to monitor the formation of the first fracture in real time using techniques such as resulting hypertension analysis (known as "Nolte-Smith analysis" ), tilt meters, microseismic analysis, or combinations thereof The fracturing treatment can be modified to ensure that tolerance is achieved to a certain extent, gap design parameters. This procedure can be applied to the second or third slot. Secondly, in an embodiment in which the location of the second and third fractures can be modified during fracturing, a stress model may be used to calculate new locations for the second and / or third fractures so as to change (e.g. neutralize) stress anisotropy at least in some part of the geological formation. In one embodiment, the third slot may be at a location other than exactly halfway between the first and second slots. The location of the third slot may depend on the dimensions of the first and second slots and the resulting overpressures measured during the formation of the first and second slots. In one embodiment, the traditional Nolte technique can be used during machining to identify periods in which gaps (e.g., by pushing) open other than the gap created in the formation (e.g., secondary gaps). Alternatively, any suitable technique that is known to or known to those of skill in the art may be used to identify the opening (e.g., push) of the secondary slots.

[0056] In one embodiment, JPA 1000 comprises providing a wellhole handling device configured to vary stress anisotropy in a geological formation 30. Referring to Figure 11, at least a portion of the respective wellhole handling device 200 is integrated in the piping column 180 . In an alternative embodiment, at least a portion of the respective well-handling device may be integrated in a casing pipe, coiled tubing, the like, or combinations thereof.

ΕΡ 2,456 952 Bl [0057] In one embodiment, the wellbore apparatus configured to change stress anisotropy in geological formation 102 includes one or more controlled fracturing tools (SNS) 220. Referring to the embodiment of Fig. 11, the wellbore handling device 200 includes a first SNS 220 tool, a second SNS 220 tool, and a third SNS 220 tool. In an alternative embodiment, the well management device further includes a fourth SNS tool, a fifth SNS tool, a sixth SNS tool or more. In one embodiment, the wellbore handling device 200 may include one or more wire sections (e.g., tubing members, casing pipe members, etc.) connecting adjacent SNS 220 tools.

[0058] Still referring to Figure 11, in one embodiment, the wellbore handling device 200 may include one or more sealants 210. Such one or more sealant may include any device suitable for isolating adjacent or immediately adjacent bore sections 114 and / or geological formation 102 to thereby create two or more fracturing compartments. In one embodiment, such one or more sealants 210 may be present between one or more SNS 220 tools that, when inserted, effectively isolate the fracturing compartments from each other. Isolating the fracturing compartments from each other may involve using some form of ring insulation. Ring insulation refers to the preservation of an axial hydraulic seal in the space between the pipe member (e.g., piping 180) and the wellbore wall 114. Ring insulation can be obtained by using a suitable sealant or using cement. In one embodiment, as such one or more of the sealants 210, intumescent sealants, e.g., SweliPacker® intumescent sealant, commercially available from Halliburton Energy Services based in Duncan, Oklahoma, can be used. Such an intumescent sealant can expand, swelling when it comes in contact with the activation fluid (e.g., water, kerosene, diesel, or other), which provides a seal or barrier between adjacent fracturing compartments. In such an embodiment, isolating the fracturing compartment may include placing the intumescent sealant adjacent the fracturing compartment to be isolated, and bringing the intumescent sealant into contact with the activation fluid.

[0059] In alternative embodiments, mechanical or pumped sealants may be used as one or more sealants 210. In such an embodiment, isolating the fracturing compartments (e.g., 2, 4 and / or 6) from each other may include locating the intumescent sealant between adjacent fracturing compartments (e.g., 2, and / or 6) to be isolated, and activating mechanical seal or inflation of the pumped sealant. Alternatively, a combination of intumescent sealants and mechanical sealants can be used for such one or more sealants 210. [0060] In one embodiment, providing the wellbore handling device configured to change stress anisotropy in the geological formation 102, may include placing the wellbore handling device 200 in the wellbore 114, (e.g., vertical wellbore section 115, horizontal section 116 well or combinations thereof). Once positioned, each of the SNS 220 tools included in the wellbore handling device 200 may be adjacent, substantially adjacent, and / or directly adjacent to at least a portion of the geological formation 102 in which the fracture is to be formed (e.g., in a fracturing compartment). For example, in the embodiment of Fig. 11, the SNS tool 220 is located substantially adjacent to the first compartment

ΕΡ2 456 952 Bl fracturing 2, another tool SNS 220 is placed adjacent to the second fracturing compartment 4, and yet another tool SNS 220 is located adjacent to the third fracturing compartment 6. In addition, in the embodiment where the wellbore apparatus includes a fourth SNS tool, a fifth SNS tool, a sixth or more SNS tool, each of the fourth SNS tool, a fifth SNS tool, a sixth or more SNS tool can be placed essentially adjacent to the fourth fracturing compartment, fifth bristling compartment, sixth fracturing compartment, etc.

[0061] In one embodiment, providing a wellbore handling device configured to change stress anisotropy in a geological formation, includes mounting at least a portion of the well handling device in position at the geological formation. In one embodiment, the tubing 180 or section thereof is attached in a conventional manner with cement 170, in position at the geological formation 102.

[0062] In one embodiment, the SNS 220 tools are configured to transfer fluid between the internal flow line of the SNS 220 tool and the wellbore 114, the nearest fracturing compartment 2, 4 or 6, geological formation 102 or combinations thereof, or not to transfer fluid . In one embodiment, each SNS 22 0 tool is configured independently of any other SNS 220 tool that may be located along the same tubular member (e.g., piping column). Thus, for example, the first SNS 220 tool may be configured to drain fluid into the surrounding wellbore 114 and / or geological formation 102, while the second SNS 220 tool or third SNS 220 tool may be configured not to throw out fluid.

[0063] Referring to Fig. 12, in one embodiment, the SNS tools 220 include a body 221. In the embodiment of Fig. 12, the body 221 of the SNS tool 220 is a generally cylindrical or tubular structure. Alternatively, the SNS 220 tool body may have any suitable structure or configuration; such appropriate structures will be apparent to those skilled in the art from the present disclosure.

[0064] As shown in Fig. 12, in one embodiment, SNS tools 220 can be configured to attach them to the piping column 180. In this embodiment, the body 221 may include a corresponding connection to the piping column 180 (e.g., to piping column). For example, as shown in fig. 12, the connection ends of the body 221 of the SNS tool 220 include one or more internally or externally threaded surfaces used respectively to form a threaded connection with the piping column 180. Alternatively, the SNS 220 tool can be attached to the piping column 180 by any suitable connection. Suitable connections to the tubing member are known to those skilled in the art.

[0065] In one embodiment, a given set of controlled fracturing tools 220 may be separated by one or more pipe sections (e.g., tubing members). Each SNS 220 tool can be configured to be threaded to a pipe section or to another SNS 220 tool. Thus, during operation, when using multiple controlled fracturing tools 220, the highest tool SNS 220 can be threaded to the deep end of the piping column. A threaded pipe section is attached to the deep end of the highest tool SNS 220, which extends over a certain section, reaching

ΕΡ 2 456 952 Bl of the place where the downhole end of the pipe section is threaded to the upper end of the second highest tool SNS 220. According to this pattern, a gradual downward descent can extend for any desired number of SNS 220 tools along the wellbore apparatus 200. Accordingly, the distance between any two SNS 220 tools can be adjusted to meet the requirements of a particular situation. The length of the tensile pipe between any two SNS 220 tools can be approximately the same as the distance between the fracturing compartment nearest to which the first SNS 220 tool is to be placed and the fracturing compartment closest to which the second SNS 220 tool is to be placed. The same applies any additional SNS 220 tools to support any additional fracturing intervals 2, 4 or 6. In addition, a section of piping can be threaded to the lower end of the lowest SNS tool and can extend a certain distance toward the connection end of the well.

[0066] In one embodiment, the pipe lengths may be such that the distance between two SNS tools can be approximately equal to the gap between fracturing intervals that has been specified previously (e.g., approximately the same as the distance between desired fracturing intervals ). For example, in the embodiment according to Fig. 11, the distance between the first SNS 220 tool and the second SNS 220 tool may be approximately the same as the distance between the first fracturing interval 2 and the second fracturing interval 4. Similarly, the distance between the second SNS 220 tool and the third SNS 220 tool may be approximately the same as the distance between the second fracturing compartment 4 and the third fracturing compartment 6. Accordingly, in one embodiment, the wellbore handling device 200 may be configured to produce two or more slots in the geological formation 102 at an equal distance or approximately equal to a specified spacing between fracturing intervals.

[0067] In the embodiment of Fig. 12, the inner surface of the body 221 defines an axial flow conduit 225. Referring again to Fig. 11, the SNS tools 220 are attached to the piping column 180 so that the axial flow conduit 225 of the SNS 220 tool is located in fluid communication with the axial flow conduit 225 piping column 180.

[0068] In one embodiment, each SNS 220 tool includes one or more exit slots or holes 230. SNS 220 outlet outlets 230 can be controlled selectively and independently (e.g., by opening or closing, completely or partially) to allow, limit, reduce, or otherwise control one or more fluid communication paths between the tool's internal axial flow line 225 SNS 220 and borehole 114, the nearest fracturing compartment 2, 4 or 6, geological formation 102 or combinations thereof. In one embodiment, due to the independent configuration of each SNS 220 tool, the outlet holes 230 of a given SNS 220 tool may be open to the surrounding wellbore 114 and / or fracturing compartment 2, 4 or 6, and the outlet holes of another SNS 220 incoming tool in the wellbore apparatus 200, may be closed.

[0069] In the embodiment of Fig. 12, such one or more outlet orifice 230 may pass through the body of the SNS tool. In this embodiment, the outlet holes 230 extend radially outwardly from the axial flow conduit 225. Therefore, the outlet holes 230 may provide a fluid communication path between the axial flow conduit 225 and the wellbore 114 and / or geological formation 102 when the SNS tool 220 is configured accordingly (on

ΕΡ2 456 952 Bl example when the outlet holes 230 are not blocked). Alternatively, the SNS tool may be configured such that no fluid is passed through the outlet holes 230 between the axial flow conduit 225 and the wellbore 114 and / or geological formation 102 (e.g., when the outlet holes 230 are blocked).

[0070] As shown in Fig. 12, in one embodiment, SNS tools 220 may include a slide sleeve 226. The slide sleeve includes an outer surface that is configured to slide into the inner surface of the body 221. In the embodiment of Fig. 12, the sliding sleeve or part of it may be configured to slide slidably over the outlet openings 230 of the SNS 220 tool and thereby obstruct them. As shown in fig. 12, the sliding sleeve 226 may allow, reduce or prevent fluid passage through the outlet openings 230 depending on whether the slide sleeve 226 or a portion thereof covers or partially overlaps the outlet openings 230. In one embodiment, the sliding sleeve 226 includes one or more outlet 236. In such an embodiment, when the outlet openings 236 of the sliding sleeve are aligned with the outlet openings mi 230, then a fluid communication path can be provided, so that fluid transfer between the axial flow conduit 225 and the well 114 and / or the geological formation 102 can be provided through outlet holes 230 and / or outlet holes 236 of the sliding sleeve. Alternatively, when the outlet openings 236 of the sliding sleeve are misaligned with the outlet openings 230, then the fluid communication path may be blocked so that fluid is not transferred to the wellbore 114 and / or geological formation 102 through the outlet openings 230 or the outlet openings 236 of the sleeve sliding.

[0071] In one embodiment, controlling or configuring the SNS tool 220 to provide, block, or otherwise change the path or flow path and / or eject fluid by the SNS tool 220 may include moving the slide sleeve 226 relative to the body 221 of the SNS tool 220 . For example, the slide sleeve 226 may be moved relative to the body 221 to align the through holes 230 coaxially with the outlet holes 236 of the slide sleeve, thereby providing a fluid communication path, or the slide sleeve 226 may be moved relative to the body 221 to align the holes ports 230 misaligned with the outlet openings 236 of the sliding sleeve, thereby blocking the fluid communication path. Configuration of the SNS tool 220 (e.g., by sliding the sliding sleeve 226 relative to the body 221) can be accomplished by several different means, such as electrical, electronic, pneumatic, hydraulic, magnetic or mechanical means.

[0072] In one embodiment, the SNS tool 220 can be controlled by a mechanical sliding tool. Referring to Fig. 13, it shows an embodiment of a suitable mechanical sliding tool (MNP) 300. In one embodiment, the MNP tool 300 generally includes a body 310, an extendable member 320, and a seat 330.

[0073] Referring to Figure 14, in one embodiment, the MNP tool 300 may be attached to a pipe column 190 (e.g., a rolled pipe) such that the MNP 300 tool axial flow line 315 is in fluid communication with through the axial flow conduit of the pipe column 190. In one embodiment, the MNP tool attached to the pipe column 190 may be introduced into the pipe column 180. In one embodiment, the pipeline column 190 may be introduced into the piping column to such a depth that the MNP 300 tool is placed in the device 220 for handling

ΕΡ2 456 952 Bl of the well or parts of it, alternatively so that the MNP tool is essentially directly at SNS 220.

[0074] Referring again to Figure 13, in one embodiment, the body 310 includes a corresponding connection to the pipe column. For example, the body 310 may include one or more internally or externally threaded surfaces, so that the MNP 300 tool can be combined with a pipe column (e.g., a coiled tubing). In one embodiment, the body 310 substantially defines an internal axial flow line 315. [0075] In one embodiment, the seat 330 may be configured to engage a plug member that is inserted into the axial flow conduit 315. Non-limiting examples of plug members include balls, mechanical anchors, foam anchors, and the like, and their combinations. When engaged with the seat 330, such a stopper member may substantially block or stop fluid flow from one side of the stopper member to the other. In such an embodiment, a pressure difference may arise on at least one side of the stopper member coupled to the seat 330.

[0076] In one embodiment, the seat 330 may be operably coupled to the extendable member 320. Non-limiting examples of a suitable extendable member include a projection, protrusion, wedge or hook. Therefore, after inserting the stopper member into the axial flow conduit 315 of the MNP 300 tool and starting to engage it with the seat 330, the plug member and / or seat 330 may experience increasing pressure, which causes the extendable member 320 to become pulled out.

[0077] In one embodiment, the sliding sleeve 226 includes one or more complementary projections, projections, wedges or latches 227, the functioning of which will be discussed in more detail below. Referring to Fig. 15, in one embodiment, after insertion of the stopper member into the pipeline column 190 and actuation so as to engage it with the MNP 300 tool seat 330, the extendable member 320 is extended outward and can engage the slide sleeve 226 of the substantially nearest SNS tool 220. In one embodiment, the extendable member 320 may engage the complementary projections, protrusions, wedges or catches 227 of the slide sleeve 226. This coupling with the slide sleeve 226 attaches the MNP 300 tool and pipe column 190 to the slide sleeve 226. Therefore, moving the SNS 300 tool and pipe column 190 changes the position of the slide sleeve 226 relative to the body 221 of the MNP 220 tool. In the embodiment in which the MNP 300 tool is attached to the slide sleeve 226, the MNP 300 tool and the pipe column 190 can be used to move the slide sleeve 226 so as to align the outlet holes 230 coaxially with the outlet holes 236 here of the sliding fet, thus providing a fluid communication path leading to well 114 and / or geological formation 102. Alternatively, the MNP 300 tool and pipeline column 190 may be used to move the slide sleeve 226 so as to position the outlet holes 230 in misalignment with the outlet holes 236 of the slide sleeve, thereby blocking the fluid communication path leading to wellbore 114 and / or geological formation 102. The SNS tool and mechanical shifting tools, as well as how they work, are described in more detail in U.S. Patent Application Ser. 12/358 079, the content of which is fully incorporated herein by reference.

ΕΡ2 456 952 Bl [0078] In one embodiment, the outlet openings 230 may be configured to discharge fluid at a pressure sufficient to decompose the adjacent bristling compartment 2, 4 or 6 located directly thereon. For example, the outlet openings 230 may be fitted with nozzles (for example, perforation or hydro-jet nozzles). In one embodiment, the nozzles may disintegrate, so that as fluid ejects from the nozzles, they disintegrate completely. Thus, as the nozzles break down, the coaxial outlets 230 and the outlets 236 of the slide sleeve align with each other function in such a way that they provide a relatively larger volume of fluid and / or at a lower pressure than may be necessary for perforation (e.g. in a manner that could be desirable in later fracturing operations). In other words, as the nozzle erodes, the fluid escaping through the outlets 230 passes from perforation and / or initiation of cracks in the geological formation 102 to the expansion and / or propagation of cracks in the geological formation 102, Eroding nozzles and methods of their use are disclosed in more detail in the US patent application Ser. No. 12/274 193.

[0079] In one embodiment, providing a wellbore apparatus 200 configured to change the stress anisotropy of a geological formation 102 may include isolating one or more fracturing intervals 2, 4, or 6 of the geological formation 102. In one embodiment, isolating fracturing intervals 2, 4 or 6 can be done with one or more sealants 210. As explained above, after inserting such one or more sealants 210, they can effectively isolate different parts of the geological formation 102 from each other, forming two or more fracturing compartments (e.g., by providing a barrier between fracturing compartments 2, 4 and or 6). In an embodiment in which the sealants 210 include intumescent sealants, isolating one or more of the fracturing compartments from each other may include contacting the intumescent sealant with the activation fluid. In an embodiment in which such an activation fluid has been introduced, it may be desirable to remove any remaining portion of the activation fluid, for example, by introducing the fluid into the circulation or reverse circulation.

[0080] In one embodiment, the JPA 1000 method includes changing the stress anisotropy in at least one range of biting the geological formation 102. In one embodiment, the change in anisotropy in the geological formation 102 and / or its fracturing interval generally includes creating a first fracture in the first fracturing interval (e.g., the first fracturing interval 2) and creating a second fracture in the third fracturing interval (e.g., the third fracturing interval 6 ), the fracturing interval being in which the stress anisotropy is to be changed (e.g., the second fracturing compartment 4) is between the first fracturing compartment 2 and the third fracturing compartment 6. In one embodiment, the first fracturing compartment 2 and the third fracturing compartment 6 may be adjacent, substantially adjacent or another way is directly at the fracturing interval in which the stress anisotropy is to be changed.

[0081] In one embodiment, the formation of a first fracture in the first fracturing interval 2 and a second fracture in the third fracturing interval 6 can change the stress anisotropy in the second fracturing interval 4 which is between the first fracturing interval 2 and the third fracturing interval 6.

452 456 952 Bl [0082] In one embodiment, the change in stress anisotropy in at least one geological formation range 102 involves forming a first fracture in a first fracturing compartment. Referring to Fig. 15A, in one embodiment, making the first slot in the first fracturing compartment 2 may include providing a fluid communication path leading, via the first SNS tool 220A, to the first fracturing compartment 2, fluid transfer to the first fracturing compartment 2 via the first tool SNS 220A and blocking the fluid communication path leading through the first SNS 220A tool, to the first fracturing compartment 2.

[0083] In one embodiment, creating the first slot in the first fracturing compartment 2 via the first SNS 220A tool includes placing the MNP member 300 directly at the first SNS 220A tool. A plug member may be introduced into the column of pipe 190 and circulated forward to couple it to the seat 330 of the MNP 300. After coupling of the stopper member to the seat 330, further pumping of fluid may cause the stopper member to exert pressure on the seat, thereby actuating the extendable member 320. The actuation of the extendable member may engage the extendable member 320 with the slide sleeve 226 of the first SNS220A tool (e.g., via complementary projections, wedges or catches), which allows the slide sleeve 226 to be displaced relative to the body 221 of the first SNS 220A tool, thereby providing a fluid communication path between the axial flow conduit 225 of the first SNS tool 220A and the first fracturing compartment 2 by aligning the outlet openings 230 coaxially with the outlet openings 236 of the slide sleeve and providing a fluid communication path through it. When the outlet holes 230 are aligned with the outlet holes 236 of the sliding sleeve, the pressure in the pipe column 190 can be released so that it stops acting via the seat 330, which allows the withdrawable member 320 to disengage from the sliding sleeve 226.

[0084] In one embodiment, creating the first fracture in the first fracturing compartment 2 includes transferring fluid to the first fracturing compartment 2 via the first tool SNS 220A. In one embodiment, the fluid transfer to the first fracturing compartment 2 via the first SNS 220A tool includes the insertion of the plug member into the reverse circulation, such that the plug member is decoupled from seat 330, returns through the pipe column 190, after which it can remain deleted. After removing the stopper member, the fluid pumped through the tubing column 190 and the inner flow conduit 315 of the MNP 300 member can be ejected through the lower (e.g., deep) end of the MNP 300 member. In one embodiment, the MNP 300 member can be introduced further piping columns 180, so that the MNP 300 is lower (e.g., deeper) than the first SNS 220A tool.

[0085] In one embodiment, the fluid may be passed to the first fracturing compartment 2 by a first flow path, a second flow path, or combinations thereof. In such an embodiment, a suitable first flow path may include an internal flow conduit of the pipeline column 190 and an MNP 300 member (e.g., as indicated by flow direction arrow 60), and a suitable second flow path may include an annular space between the pipeline column 190 and the piping column 180, or both (e.g., as indicated by the flow direction arrow 50).

ΕΡ2 456 952 Bl [0086] In one embodiment, the fluid passed into the fracturing compartment (e.g., 2, 4 or 6) may include a multi-component fluid that includes two or more component fluids. In one embodiment, the first component fluid may be transferred by a first flow path (e.g., indicated by arrow 60 or 50 flow direction), while the second fluid may be conveyed by a second flow path (e.g., indicated by arrow 50 or 60 flow direction). The first component fluid and the second component fluid may mix in the downhole section of the well or piping column before entering the geological formation 102 and / or its fracturing compartment 2, 4 or 6 (e.g., as indicated by arrow 70 of the flow direction).

[0087] In such an embodiment, the first component fluid may comprise a concentrated fluid, while the second component fluid may be a diluted fluid. The first component fluid may be pumped at a rate independent of the second component fluid, and the second component fluid at a rate similarly independent of the first component. As will be appreciated by those skilled in the art, wellbore fluids (e.g., fracturing fluids, hydrofluiding fluids and the like) may tend to erode or wear off wellbore handling equipment. Therefore, operators have traditionally been limited in the speed at which abrasive fluid could be transferred. For example, operators have traditionally been unable to achieve pumping speeds greater than about 35 feet / sec. Deep mixing of two or more component fluids enables the operator to achieve a higher effective pumping speed (e.g., the rate at which a multi-component fluid is introduced into geological formation 102). In one embodiment, the concentrated fluid component may be pumped through the first flow path or the second flow path at a rate that does not damage or abrasion the well equipment, while the diluted fluid component may be pumped at the higher rate remaining from these flow paths, or first For example, because the diluted liquid component contains no or very little abrasive, so it can be pumped at a higher speed without the risk of damaging (e.g. abrasion or etching) of the well handling equipment or component thereof, e.g. at a speed greater than about 35 feet / sec. Therefore, the operator can achieve a higher effective rate of pumping abrasive fluids.

[0088] Furthermore, due to the varying fluid pumping rates, the in-depth mixing of two or more component fluids allows the operator to adjust the speed of the first component fluid, the second component fluid, or both, thereby implementing real-time changes in the concentration of the multi-component fluid. Numerous flow paths, in-depth mixing of component fluid fluids, variable speed pumping methods, and related devices are disclosed in more detail in US Patent Application No. 12/358 079, the content of which is incorporated herein in its entirety.

[0089] In one embodiment, the multi-component fluid may include a hydrofluiding fluid. In such an embodiment, the concentrated liquid component may be pumped through the flow conduit of the pipeline column 190 and the internal flow conduit 315 of the MNP member 300 (e.g., as indicated by arrow 60), while the solvent (e.g. water) may be pumped through the annular space (e.g. as indicated by arrow 50) to form a hydrofluid cutting fluid (e.g. as indicated by arrow 70). The component fluids of the hydrofluid cutting fluid can be pumped at an effective speed (e.g., transferred to the geological formation 102) sufficient and / or at a pressure sufficient to abrasive the geological formation 102 and / or to initiate the formation of cracks in it.

452 456 952 Bl [0090] In one embodiment, the multi-component fluid may be a fracturing fluid. In such an embodiment, the concentrated fluid component may be a concentrated propellant transfer fluid. In this embodiment, the concentrated proppant transfer fluid may be pumped through the flow conduit of the pipeline column 190 and the internal flow conduit 315 of the MNP member 300 (e.g., as indicated by arrow 60), while the solvent (e.g. water) may be pumped through the annular space ( for example as indicated by arrow 50) to form a fracturing fluid (for example as indicated by arrow 70). The fracturing fluid constituents may be pumped at an effective speed (e.g., transferred to geological formation 102) sufficient to initiate and / or propagate the fracture in the first fracturing compartment. In one embodiment, the fracturing fluid may enter the geological formation 102, causing or spreading a crack within it.

[0091] In one embodiment, creating the first gap in the first fracturing compartment 2 includes blocking the fluid communication path leading, via the first SNS tool 220A, to the first fracturing compartment 2. In one embodiment, blocking the fluid communication path leading, via the first SNS 220A tool, to the first fracturing compartment 2 includes placing the MNP 300 member directly at the first SNS 220A tool. A plug member may be re-introduced into the column of pipe 190 and circulated forward to engage it with the seat 330 of the MNP 300. After coupling of the stopper member to the seat 330, further pumping of fluid may cause the stopper member to exert pressure on the seat, thereby actuating the extendable members 320. Activation of the extending members may cause the extending members 320 to engage the sliding tool sleeve of the first SNS 220A tool, which allows displacement of the sliding sleeve relative to the body of the first tool SNS 220A to block the fluid communication path between the internal flow conduit 225 of the first SNS tool and the first fracturing compartment 2 by setting the outlet holes 230 misaligned with outlet holes 236 of the sliding sleeve. When the outlet holes 230 are misaligned with the outlet holes 236 of the sliding sleeve, the pressure in the pipe column 190 can be released so that it ceases to interact via the seat 330, and this allows the withdrawable member 320 to disengage from the sliding sleeve. The MNP 300 member can be moved to another SNS 220 tool located directly at another fracturing interval. Alternatively, the MNP 300 may be removed from the interior of the piping column 180.

[0092] In one embodiment, the change in stress anisotropy in at least one geological formation range 102 includes forming a second fracture in the third fracturing compartment 6. Referring to Fig. 15B, in one embodiment, making the second slit in the third fracturing compartment 6 may include providing a fluid communication path leading, via the second SNS tool 220B, to the third fracturing compartment 6, transferring fluid to the third fracturing compartment 6 via the second SNS tool 220B and blocking the fluid communication path leading through the second tool SNS 220B, to the third fracturing compartment 6.

[0093] In one embodiment, providing a fluid communication path leading, via the second SNS 220B tool, to the third fracturing compartment 6 includes placing the MNP 300 member directly at the second SNS 220B tool. To the column of the duct

ΕΡ 2 456 952 Bl tubular 190 can be inserted and circulated forward the plug member to engage it with the seat of the 330 MNP 300 member. After coupling the plug member to the seat 330, further fluid pumping can cause the plug member to exert pressure on the seat , thereby actuating the pull-out members 320. The actuation of the extending members may cause the extending members 320 to engage the sliding sleeve 226 of the second SNS 220B tool (e.g., through projections, wedges or catches), which allows the sliding sleeve 226 to be moved relative to the body 221 of the second SNS 220B tool to provide fluid communication path between the internal flow conduit 225 of the second SNS 220B tool and the third fracturing compartment 6 by positioning the outlet holes 230 coaxial with the outlet holes 236 of the sleeve. When the outlet holes 230 are aligned with the outlet holes 236 of the sliding sleeve, the pressure in the pipe column 190 can be released so that it ceases to act via the seat 330, and this allows the withdrawable member 320 to decouple from the sliding sleeve. [0094] In one embodiment, the creation of the second gap in the third fracturing compartment 6 includes fluid transfer to the third fracturing compartment 6 via the second tool SNS 220B. In one embodiment, the fluid transfer to the third fracturing compartment 6 via the second tool SNS 220B involves introducing the plug member into reverse circulation, such that the plug member decouples from the seat 330, returns through the pipe column 190, after which it can become deleted. After removing the stopper member, the fluid pumped through the pipeline column 190 and the internal flow conduit 315 of the MNP member 300 may be ejected through the lower (e.g., deep) end of the MNP member 300. In one embodiment, the MNP member may be introduced further into the column piping 180, so that the MNP 300 is lower (e.g., deeper) than the second tool SNS 220B.

[0095] In one embodiment, as explained above with respect to the production of the first gap, the fluid may be passed to the third fracturing compartment 6 by the first flow path, the second flow path or combinations thereof (e.g. as indicated by arrows 50 and / or 60 direction flow). In such an embodiment, a suitable first flow path may include an internal flow conduit of the pipeline column 190 and an MNP 300 member (e.g., as indicated by flow direction arrow 60), and a suitable second flow path may include an annular space between the pipeline column 190 and the piping column 180, or both (e.g., as indicated by the flow direction arrow 50). In one embodiment, the fluid passed to the third fracturing compartment 6 may include two or more component fluids. [0096] In one embodiment, the fluid may be a hydrofluid mining fluid that can be pumped (e.g., transferred to geological formation 102) at a sufficient effective speed and / or pressure sufficient to wipe the geological formation 102 and / or initiate crack formation. In another embodiment, the fluid may be a fracturing fluid that can be pumped (e.g., transferred to geological formation 102) at an effective speed sufficient to initiate and / or propagate the fracture in the first fracturing compartment. In another embodiment, the fracturing fluid may enter the geological formation 102, causing a crack to spread or spread therein.

[0097] In one embodiment, creating a second gap in the third fracturing compartment 6 includes blocking the fluid communication path through

ΕΡ2 456 952 Bl of the second SNS 220B tool, to the third fracturing compartment 6. In one embodiment, blocking the fluid communication path, via the second SNS 220B tool, to the third fracturing compartment 6 involves placing the MNP 300 member directly at the second SNS 220B tool . The plug member may be re-introduced and circulated forward into the column 190 to engage it with the seat 330 of the MNP 300 member. After coupling the plug member to the seat 330, further pumping of the fluid may cause the plug member to exert pressure on the seat. thereby activating the extendable members 320. Activation of the extending members may cause the extending members to engage the sliding sleeve (for example, through complementary projections, wedges or catches) of the second SNS 220B tool, which allows the sliding sleeve 226 to be moved relative to the body 221 of the second SNS 220B tool to block the fluid communication path between the internal flow conduit 225 of the second SNS 220B tool and the third fracturing compartment 6 by positioning the outlet holes 230 misaligned with the outlet holes 236 of the sliding sleeve. When the outlet openings 230 are misaligned with the outlet openings 236 of the sliding sleeve, the pressure in the pipe column 190 can be released so that it ceases to interact via the seat 330, which allows the withdrawable member 320 to disengage from the slide sleeve 226.

[0098] In one embodiment, creating a gap in the first fracturing interval 2 and creating a gap in the third fracturing interval 6 may change the stress anisotropy in the second fracturing interval 4. Referring to Figures 15A, 15B and 15C, the second fracturing interval 4 may located along the deflected bore section 116, between the first fracturing compartment 2 and the third fracturing compartment 6. Without being limited by theory, the slots created in the first fracturing interval 2 and the third fracturing interval 6 may cause an increase in the value of c_HMax and amum in the second fracturing interval 4. As explained in this document, the σ value increases_ΗΜίη may be greater than the increase in the value of a_Hwiax · Accordingly, stress anisotropy in the second fracturing interval 4 may decrease. In one embodiment, the creation of a gap or slits under certain resulting crack propagation overpressure (e.g., in a predetermined resultant fracture propagation pressure) and at certain intervals (e.g., predetermined intervals between fracturing intervals) can predictably alter stress anisotropy in geological formation 102 and / or its fracturing range. In one embodiment, creating a gap or slits in adjacent fracturing compartments can reduce, equalize, or reverse stress anisotropy in the fracturing interval therebetween.

[0099] In one embodiment, the JPA 1000 process involves producing a gap in the fracturing interval in which the stress anisotropy has changed. Without being limited by theory, as disclosed herein, reducing, equalizing, or reversing stress anisotropy within a fracturing interval and / or part of a geological formation 102 may promote the formation of branched fractures, which leads to the formation of at least one complex fracture network. Without being limited by theory, because the gap need not be limited to opening along only one axis, therefore a change in the stress field in the fracturing interval may allow branching branching and the complexity of the fractures.

[0100] Referring to Fig. 15C, in one embodiment, creating a gap in a second fracturing compartment 4 in which stress anisotropy has been altered may include

ΕΡ2 456 952 Bl providing a fluid communication path leading, via the third SNS 220C tool, to the second fracturing compartment 4, fluid transmission to the second fracturing compartment 4 via the third SNS 220C tool, and blocking the fluid communication path, via the third SNS 220C tool, to the second fracturing compartment 4.

[0101] In one embodiment, creating a gap in the second fracturing compartment 4 in which stress anisotropy has been altered may include providing a fluid communication path leading, via the third SNS 220C tool, to the second fracturing compartment 4. In one embodiment, providing a fluid communication path leading, through the third SNS 220C tool, to the second fracturing compartment 4 includes placing the MNP 300 member directly at the third SNS 220C tool. A plug member may be introduced into the column of pipe 190 and circulated forwards so as to couple it to the seat 330 of the MNP 300. After coupling of the stopper member to the seat 330, further pumping of fluid may cause the stopper member to exert pressure on the seat, thereby actuating the extendable members 320. Activation of the extending members may cause the extending members to engage the sliding sleeve 226 of the third SNS 220C tool, which allows the sliding sleeve 226 to be displaced relative to the body 221 of the third SNS2 20C tool to provide fluid communication between the internal flow line 225 of the third SNS 220C tool and the second fracturing compartment 4 through positioning the outlet holes 230 coaxially with the outlet holes 236 of the sleeve. When the outlet holes 230 are aligned with the outlet holes 236 of the sliding sleeve, the pressure in the pipe column 190 can be released so that it ceases to interact via the seat 330, which allows the withdrawable member 320 to disengage from the sliding sleeve.

[0102] In one embodiment, creating a gap in the second fracturing compartment 4 in which stress anisotropy has been altered may include transferring fluid to the second fracturing compartment 4 via the third tool SNS 220C. In one embodiment, fluid transfer via the third tool SNS 220C includes introducing the plug member into reverse circulation, such that the plug member is decoupled from seat 330, returns through the column 190, and can be removed therefrom. After removal of the stopper member, fluid pumped through the tubing column 190 and internal flow conduit 315 of the MNP member 300 may be ejected through the end of the MNP member 300. In one embodiment, the MNP member may be inserted further deep into the tubing cradle 180, such that the MNP member 300 is lower (e.g., deeper) than the third SNS 220C tool.

[0103] In one embodiment, as explained above with respect to the production of the first and second slots, the fluid may be passed to the second fracturing compartment 4 by the first flow path, the second flow path or combinations thereof (e.g., as indicated by arrows 50 and / or 60 flow direction). In such an embodiment, a suitable first flow path may include an internal flow conduit of the pipeline column 190 and an MNP 300 member (e.g., as indicated by flow direction arrow 60), and a suitable second flow path may include an annular space between the pipeline column 190 and the piping column 180 (e.g., as indicated by the flow direction arrow 50), or both. In one embodiment, the fluid passed to the third compartmentalization compartment 6 may include two or more component fluids.

ΕΡ 2 456 952 Bl [0104] In one embodiment, the fluid may be a hydrofluid mining fluid that can be pumped (e.g., transferred to geological formation 102) at a sufficient effective speed and / or pressure sufficient to abrasion the geological formation 102 and / or initiate a crack. In another embodiment, the fluid may be a fracturing fluid that can be pumped (e.g., transferred to geological formation 102) at an effective speed sufficient to initiate and / or propagate the fracture in the first fracturing compartment. In another embodiment, the fracturing fluid may enter the geological formation 102, causing a branched and / or complex fracture network to arise or spread therein.

[0105] In one embodiment, the operator can change the complexity of the fracture produced in the geological formation. For example, by changing the speed at which fluid is injected, pumping small solids at low concentrations, using a sticky gel lump or a combination of these, the operator can prevent the formation of excessive fracture complexity. Alternatively, for example, by changing injection rates, pumping larger solids at high concentrations, using low-viscosity liquids or combinations thereof, the operator may cause complex cracks. The use of microseismic analysis of fissures to determine the effectiveness of machining operations aimed at creating branched fissures in real time is discussed in the work entitled "The Relationship Between Fracture Complexity, Reservoir Properties, and Fracture Treatment Design", SPE 115769, by Cipolla, CL et al., Presented in 2008 at the SPE Annual Technical Conference and Exhibition in Denver, Colorado. Stresses in the process zone (NSP) resulting from the complexity of fractures in coal deposits and the recommended actions to remedy excessive NSP are discussed in the paper entitled "Effects of High-Pressure-Dependent Leakoff and High-Process-Zone Stress in Coal Stimulation Treatments", SPE 107971, by Muthukumarappan Ramurthy et al., Presented in 2007 at the SPE Rocky Mountain Oil &amp; Gas Technology Symposium in Denver, Colorado .

[0106] In one embodiment, creating a gap in the second fracturing compartment 4 in which stress anisotropy has been altered may include blocking the fluid communication path leading, via the third SNS 220C tool, to the second fracturing compartment 4. In one embodiment, blocking the fluid communication path leading, via the third SNS 220C tool, to the second fracturing compartment 4 includes placing the MNP 300 member directly at the third SNS 220C tool. A plug member may be re-introduced into the column of pipe 190 and circulated forward to engage it with the seat 330 of the MNP 300. After coupling the plug member to the member seat 330, further pumping of fluid may cause the plug member to exert pressure on the seat, thereby actuating the extendable members 320. Activation of the extending members may cause the extending members to engage the sliding tool sleeve of the third SNS 220C tool, which allows the sliding sleeve to be displaced relative to the body of the third tool SNS 220C to block the fluid communication path between the internal flow line 225 of the third tool SNS 220C and the second fracturing compartment 4 by setting the outlet holes 230 misaligned with outlet 236 sleeves. When the outlet openings 230 are misaligned with the outlet openings 236 of the sliding sleeve, the pressure in the pipe column 190 can be released so that it ceases to interact via the seat 330, which allows the withdrawable member 320 to disengage from the sliding sleeve.

ΕΡ 2 456 952 Bl [0107] Referring to Fig. 16, in an additional embodiment, the method of inducing a complex crack may suitably include changing the anisotropy in the fourth fracturing compartment 8, for example by creating one or more slots in two or more cavity compartments adjacent and / or less adjacent to it more or substantially adjacent to it (e.g. in the third fracturing compartment 6 and the fifth fracturing compartment 10), so as to predict change in stress anisotropy in a predictable way. Such a method may include creating a gap in the fourth fracturing interval 8 after a change (e.g., reduction, equalization or inversion) of stress anisotropy in a predictable manner. Based on the present disclosure, those skilled in the art will readily understand how the methods, systems and devices disclosed therein can be used to produce complex fractures in additional fracturing compartments.

[0108] Referring again to Fig. 16, in one embodiment, the method of inducing a complex fracture generally comprises creating at least one gap in the fracturing interval in which stress anisotropy has been altered, by creating at least one gap in at least one, alternatively both of the adjacent fracturing compartments. In one embodiment, the gap may be produced in fracturing compartments in any appropriate order. The appropriate order in which the fractures are made can be any order that allows you to change the stress anisotropy in the fracturing interval in which it is desirable to create a composite fracture (e.g., by introducing the fracture into adjacent fracturing compartments) before forming the fracture. Referring to Fig. 16, non-limiting examples of suitable orders in which fissures may be formed in particular chewing intervals include 2-6-4-10-8-14-12-18-16; 2-6-10-14-18-4-8-12-16; 2-6-10-14-18-16-12-8-4; 18-14-16-1012-6-8-2-4; 18-14-10-6-2-4-8-12-16; 18-14-10-6-2-16-12-8-4 or parts or combinations thereof. Based on the present disclosure, those skilled in the art will recognize alternative suitable sequences in which fractures may be produced in individual fracturing intervals.

[0109] In one embodiment, one or more methods disclosed herein may further include providing a fluid communication path to the piping to allow the extraction of hydrocarbons from the geological formation to the surface. In one embodiment, providing a fluid communication path may include configuring one or more SNS tools to provide a fluid communication path as disclosed above. In one embodiment, the SNS tool may include an inflow adjustment assembly. Devices for regulating the inflow and methods of their use are disclosed in detail in US Patent Application Ser. 12/166 257.

[0110] At least one embodiment is disclosed, wherein variations, combinations and / or modifications of the embodiment (or examples) of the embodiment and / or features of the embodiment (or examples) of the embodiment are included within the scope of the present disclosure. Alternative embodiments that are the result of combining, integrating and / or disregarding the features of the embodiment (or embodiments) are also included within the scope of the present disclosure. In cases where numerical ranges or restrictions are clearly defined, such explicit ranges or restrictions should be understood to include iterative ranges or restrictions of similar values ​​that fall within clearly defined ranges or restrictions (for example, from about 1 to about 10 includes 2, 3, 4 etc .; above 0.10 includes 0.11; 0.12; 0.13 etc.). For example, wherever a numerical range with a lower limit and an upper limit is disclosed, R_at,

ΕΡ2 456 952 Bl is specifically disclosed to any number within this range. In particular, the following numbers are disclosed that are within the range: R = Ri + k * (R_at - R ^, where k is a variable from 1 percent to 100 percent in increments of 1 percent, i.e. k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, ... 50 percent, 51 percent, 52 percent, ..., 95 percent, 96 percent, 97 percent, 98 percent, 99 percent afbo 100 percent. Furthermore, any numerical range defined by the two R numbers defined above is also specifically disclosed. The use of the term "optional" in relation to any element of the claim means that this element is required or, alternatively, not required, both of which alternatives are within the scope of the claim. The use of broad terms such as "comprises", "includes" and "possesses" should be understood to support narrower terms such as "consisting of", "consisting essentially of" and "consisting essentially of". Accordingly, the scope of protection of the invention is not limited to the description given above, but is defined by the following claims, which scope covers all equivalents of the subject matter of the claims. Each of the claims is attached as a further disclosure of the description of the invention, the claims being an example (or examples) of implementing the present invention.