RU2637255C2 - Method for checking fracture geometry for microseismic events - Google Patents

Abstract

FIELD: measuring equipment.

SUBSTANCE: drilling site is located near a subterranean formation with a borehole drilled in it and a complex fracture network. The complex fracture network includes intrinsic fractures. The drilling site is intensified by injecting a pumped fluid with a propping agent into the complex fracture network. The method includes creating drilling site data including measurements of microseismic events of the subterranean formation, simulating a network of hydraulic fractures and a discrete fracture network for the complex fracture network based on the drilling site data, and performing a seismic moment operation. The method includes determining the actual seismic moment density based on the drilling site data and the predicted seismic moment density based on the shear and stretch components of the simulated hydraulic fracture network and checking the discrete fracture network based on the comparison of the predicted moment density and the actual moment density.

EFFECT: improved efficiency of the fracturing operation at the drilling site.

12 cl, 7 tbl, 85 dwg

Description

CROSS RELATIONS TO RELATED APPLICATIONS

[0001] This application claims priority according to provisional application US No. 61/842257, filed July 2, 2013, which is incorporated herein by reference in full.

[0002] This application is also a partial continuation of application for US patent No. 14/133687, filed December 19, 2013, which claims priority according to provisional application US No. 61/746183, filed December 27, 2012, which is incorporated herein by reference in its entirety, and which is a partial continuation of US Patent Application No. 61/628690, filed November 4, 2011, which is incorporated herein by reference in its entirety.

[0003] This application is also related to provisional application US No. 61/451843, filed March 11, 2011, entitled "Method, system, device and machine-readable medium for unconventional gas geomechanical intensification"; and this application is related to international application No. WO2012125558, filed September 20, 2012, under the name "System and Method for Performing Microseismic Gap Operations"; and this application is related to provisional application US No. 61/684588, filed August 17, 2012, entitled "System and Method for Performing Intensification Operations", a description of each of which is incorporated herein by reference in full.

BACKGROUND

[0004] The present invention relates mainly to methods and systems for performing operations at a drilling site. More specifically, this invention is directed to methods and systems for performing fracturing operations, such as studying an underground formation and characterizing hydraulic fracturing networks in an underground formation.

[0005] In order to facilitate hydrocarbon recovery from oil and gas wells, subterranean formations surrounding such wells may be subjected to hydraulic fracturing. Hydraulic fracturing can be used to create cracks in subterranean formations to allow oil or gas to move toward the well. The formation is fractured by introducing a specially designed fluid (referred to herein as “fracturing fluid” or “frac drilling fluid”) at high pressure and high flow rates into the formation through one or more wellbores. Hydraulic fractures can move hundreds of feet from the well in two opposite directions in accordance with the natural stresses in the formation. In certain circumstances, they can form a complex network of cracks. Complex fracture networks may include artificially generated hydraulic fractures and natural fractures that may or may not intersect along multiple azimuths, in many planes and directions, and in many regions.

[0006] Hydraulic fracture patterns created by fracture intensification can be complex and can form a network of fractures, as shown by the distribution of related microseismic events. In order to represent the created hydraulic fractures, complex hydraulic fracture networks have been developed. Examples of methods for performing the gap are presented in US patents / applications No. 6101447, 7363162, 7788074, 20080133186, 20100138196, and 20100250215.

SUMMARY OF THE INVENTION

[0007] In at least one aspect, the present invention relates to methods for performing a fracturing operation at a drilling site. The drilling site is located near the underground formation, which has a well drilled in it and a network of fractures. The crack network has natural cracks. The drilling site can be intensified by pumping the injected fluid with proppant into the fracture network. The method includes obtaining wellsite data, including natural fracture parameters for natural fractures, and obtaining a mechanical model of the geological environment of the underground formation, and creating a hydraulic fracture growth pattern for the hydraulic fracturing network over time. The creation includes the propagation of hydraulic fractures from the well into a network of fractures of an underground formation to form a hydraulic fracture network including natural fractures and hydraulic fractures, determination of hydraulic fracture parameters for hydraulic fractures after propagation, determination of transfer parameters for proppant passing through the network fractures, and fracture sizing of hydraulic fractures by certain parameters of hydraulic fractures about the gap, determining the parameters of the transfer and the mechanical model of the geological environment. The method also includes performing stress shading on the fractures to determine stress interaction between the fractures and repeating the creation based on the determined stress interaction.

[0008] If the hydraulic fracture meets a natural fracture, the method may also include determining intersection behavior between the hydraulic fractures and the encountered fracture based on a certain stress interaction, and repetition may include creating a repetition based on a specific interaction of stresses and intersection behavior . The method may also include stimulation of the well site by pumping the injected fluid with proppant into the fracture network.

[0009] If the hydraulic fracture meets a natural fracture, the method may also include determining intersection behavior when a natural fracture is encountered, and the repetition includes repetition of the creation based on a certain interaction of stresses and intersection behavior. The crack growth pattern may or may not be changed in accordance with the intersection behavior. The fracture pressure of the hydraulic fracture network may be greater than the stress acting on the encountered crack, and the fracture growth pattern may propagate along the encountered crack. The fracture growth pattern can continue to propagate along the encountered crack, until the end of the natural crack is reached. The fracture growth pattern may change direction at the end of the natural crack, and the fracture growth pattern may extend in a direction perpendicular to the minimum stress at the end of the natural crack. The fracture growth pattern may extend perpendicular to the local main stress in accordance with the shading of the stress.

[0010] The voltage shading may include performing discontinuity displacements for each of the hydraulic discontinuities. Shading stresses may include performing shading stresses around a plurality of wells at a drilling site and repetition using stress shading performed on a plurality of wells. Shading stresses may include performing shading stresses at multiple stages of stimulation in the well.

[0011] The method may also include validating the crack growth pattern. Validation may include comparing a fracture growth pattern with at least one model of a fracture network stimulation model.

[0012] The propagation may include the propagation of hydraulic fractures along the fracture growth pattern based on the parameters of the natural fracture and the minimum stress and maximum stress in the subterranean formation. Determining the size of a crack can include one of the elements: estimated seismic measurements, ant tracking algorithm, acoustic measurements, geological measurements, and a combination thereof. Drilling site data may include at least one of geological, petrophysical, geomechanical, logging, completion, retrospective data, and a combination thereof. The parameters of a natural crack can be created using one of the observational studies with a downhole scanner, estimated crack sizes from downhole measurements, microseismic imaging, and combinations thereof.

[0013] In another aspect, the invention relates to a method for performing a fracturing operation at a drilling site located near an underground formation having a borehole therein and a network of fractures, with a network of fractures including natural fractures, and from a drilling site stimulated by pumping proppant fluid into a fracture network. The method includes obtaining wellsite data, including the parameters of a natural fracture for natural fractures and obtaining a mechanical model of the geological environment of an underground formation, creating a hydraulic fracture growth pattern for a fracture network over time, and interpreting microseismicity on hydraulic fractures to determine the interaction of stresses between hydraulic fractures breaks, and repetition of the creation based on a certain interaction of stresses. The creation includes the propagation of hydraulic fractures from the well into a network of fractures of an underground formation to form a hydraulic fracture network including natural fractures and hydraulic fractures, determination of hydraulic fracture parameters for hydraulic fractures after propagation, determination of transfer parameters for proppant passing through the network fractures, and fracture sizing of hydraulic fractures by certain hydraulic parameters discontinuities, determination of transport parameters and a mechanical model of the geological environment.

[0014] In another aspect, a method of performing a fracturing operation at a drilling site located near an underground formation having a well bore therein and a network of fractures is provided. The fracture network includes natural fractures, and the drilling site is intensified by pumping the injected fluid with proppant into the fracture network. The method includes generating wellsite data, including natural fracture parameters for natural fractures and obtaining measurements of microseismic events of the underground formation, modeling hydraulic fractures of the fracture network based on the drilling site data and determining hydraulic fracture geometry for hydraulic fractures, creating a hydraulic fracture stress field using a geomechanical model based on data from the well site, the determination of the parameters of fracture failure in shear, including guides a fracture curve and the state of stress cracks around the web, positioning shear failure of a network of cracks and fracture stress state curve and by hydraulic fracture geometry by comparing the simulated hydraulic fracturing and fracture locations in shear with the measured microseismic events. The method may also include measuring the well site data and microseismic events at the well site, the operation of adjusting the parameters of a natural fracture based on verification, performing an intensification operation, including intensifying the well site by pumping the injected fluid into the fracture network and / or adjusting the intensification operation to based verification.

[0015] This description section is provided to represent a selection of principles that are further disclosed in the following detailed description. This summary is not intended to identify the main or significant differences of the claimed invention, nor is it intended to be used as a means of limiting the scope of the claimed invention.

[0016] In at least one aspect, the invention relates to a method for performing a microseismic fracturing operation of a drilling site having an underground formation with a complex network of cracks in it. The fracture network includes natural fractures, and the drilling site is intensified by pumping the injected fluid with proppant into the fracture network. The method includes generating wellsite data, including measuring microseismic events of an underground formation, modeling a hydraulic fracture network and a discrete fracture network for a complex fracture network based on the wellsite data, and performing seismic moment operation. The implementation includes determining the actual density of the seismic moment based on the data of the drilling site and the predicted density of the seismic moment based on the shear and extension components of the simulated hydraulic fracturing network, and checking the discrete network of cracks based on the comparison of the predicted moment density and the actual moment density.

[0017] In another aspect, the invention relates to a method for performing a fracturing operation at a drilling site. The drilling site is located near the underground formation, which has a well drilled in it and a complex network of fractures. The fracture network includes natural fractures, and the drilling site is intensified by pumping the injected fluid with proppant into the fracture network. The method includes generating wellsite data, including measuring microseismic events of an underground formation, modeling a hydraulic fracture network and a discrete fracture network for a complex fracture network based on the wellsite data, and performing seismic moment operation. The implementation includes determining the actual density of the seismic moment based on the well site data, determining the predicted moment density by determining the shear and extension components of the simulated hydraulic fracture network and transforming the shear and extension components of the simulated hydraulic fracture network, and verifying the discrete fracture network based on the comparison of the predicted moment density and actual moment density.

[0018] Finally, in another aspect, the invention relates to a method for performing a fracturing operation at a drilling site. The drilling site is located near the underground formation, which has a well drilled in it and a network of cracks, and a network of cracks, including natural cracks. The method includes stimulation of the well site by pumping the injected fluid with proppant into the fracture network, creation of the well site data, including measurements of microseismic events of the underground formation, modeling of the fracture network and a discrete fracture network for a complex fracture network based on the wells site data, and performing seismic moment operation. The implementation includes determining the actual density of the seismic moment based on the data of the drilling site and the simulated density of the seismic moment based on the shear and extension components of the simulated hydraulic fracturing network, and checking the discrete network of cracks based on the comparison of the predicted moment density and the actual moment density. The method also includes adjusting the intensification operation based on verification.

[0019] In another aspect, the invention relates to a method for performing a microseismic fracture of a drilling site having an underground formation with a network of cracks in it, including a description of the relationship between microseismic events of a complex network of fractures of an underground formation, creating a discrete network of fractures, including discrete fractures from a complex network of cracks, determining the crack parameters of discrete cracks, and determining the approximate flow rate based on the crack parameters.

[0020] Finally, in another aspect, the invention relates to a system for performing a microseismic fracturing operation of a drilling site having an underground formation with a complex network of cracks in it.

BRIEF DESCRIPTION OF THE DRAWINGS

[0021] Embodiments of a system and method for characterizing well stresses and / or microseismic fracture methods are described with reference to the following drawings. The same reference numbers are used throughout the drawings to refer to like parts and components. The implementation of various methods will be described below with reference to the accompanying drawings. However, it should be understood that the accompanying drawings illustrate only the various embodiments described herein, and are not meant to limit the scope of the various methods described herein.

[0022] FIG. 1.1 is a schematic illustration of a hydraulic fracture site depicting a fracture operation;

[0023] FIG. 1.2 is a schematic illustration of a hydraulic fracture with microseismic events;

[0024] FIG. 2 is a schematic illustration of a two-dimensional crack;

[0025] FIG. 3 is a schematic illustration of the voltage shadowing effect;

[0026] FIG. Figure 4 is a schematic illustration of a comparison of the 2D Displacement Discontinuity Method (DDM) and the Flac3D method for two parallel straight fractures;

[0027] FIG. 5.1-5.3 are graphs illustrating 2D DDM and Flac3D methods of extended cracks for stresses in different positions;

[0028] In FIG. Figures 6.1-6.2 are graphs depicting propagation paths for two initially parallel cracks in isotropic and anisotropic stress fields, respectively;

[0029] FIG. Figures 7.1–7.2 show graphs depicting propagation paths for two initially displaced cracks in isotropic and anisotropic stress fields, respectively;

[0030] FIG. 8 is a schematic illustration of transversely parallel fractures along a horizontal well;

[0031] FIG. 9 is a graph depicting the lengths for five parallel cracks;

[0032] FIG. 10 is a schematic diagram. depicting the fracture geometry UFM and the width for parallel cracks of FIG. 9;

[0033] FIG. 11.1-11.2 are schematic diagrams depicting the geometry of the crack for the case of high friction perforation and the case of a wide arrangement of cracks, respectively;

[0034] FIG. 12 is a graph depicting a microseismic survey;

[0035] FIG. 13.1-13.4 are schematic diagrams illustrating a simulated crack network as compared to microseismic measurements for steps 1-4, respectively;

[0036] FIG. 14.1-14.4 are schematic diagrams depicting a distributed network of cracks at various stages;

[0037] FIG. 15 is a structural diagram depicting a method for performing a tear operation;

[0038] FIG. 16.1-16.4 are schematic illustrations depicting crack growth near the well during a fracturing operation;

[0039] FIG. 17 is a schematic diagram showing stresses applied to a hydraulic fracture;

[0040] FIG. 18 is a graph depicting the Mora-Coulomb limit line and the Mora circle for a rock;

[0041] FIG. 19.1 and 19.2 are schematic diagrams depicting views of a cross section and a map, respectively, of the stresses applied to a hydraulic fracture;

[0042] FIG. 20 is a schematic timeline illustrating the interaction of hydraulic fracture and natural fracture during seismic events;

[0043] FIG. 21 is a schematic diagram illustrating the development of the interaction of hydraulic fracture and natural fracture;

[0044] FIG. 22.1 and 22.2 are schematic diagrams depicting a discrete network of cracks and a network of cracks with simulated hydraulic fractures, respectively;

[0045] FIG. 23.1 and 23.2 are structural diagrams depicting methods for performing a burst operation;

[0046] FIG. 24 is a schematic diagram depicting a crack plane about an axis of coordinates;

[0047] FIG. 25.1-25.5 illustrate simplified, schematic views of an oil field having underground formations containing formations in accordance with embodiments of various technologies and methods described herein;

[0048] FIG. 26 is a schematic view, partially in cross-section, of an oil field having a plurality of data collection means located at various locations along the oil field to collect data from underground formations in accordance with embodiments of various technologies and methods described herein;

[0049] FIG. 27 illustrates a production system for performing one or more oilfield operations in accordance with embodiments of various technologies and methods described herein;

[0050] FIG. 28 is a schematic diagram illustrating shear and tensile stresses on a crack;

[0051] FIG. 29.1-35.1 are graphs depicting crack growth at various shear stresses applied to it, in FIG. 29.2-35.2 are graphs depicting crack growth at various tensile stresses applied to it;

[0052] FIG. 36 is a graph depicting microseismic surveys near a network of cracks;

[0053] FIG. 37 is a graph illustrating a simulated fracture network;

[0054] FIG. 38.1 and 38.2 are graphs illustrating stresses and strains, respectively, of the simulated hydraulic fracture network of FIG. 37;

[0055] In FIG. 39.1 and 39.2 are graphs illustrating the simulated strains of FIG. 38.1 and 38.2 respectively:

[0056] FIG. 40 is a graph illustrating the total density of the seismic moment;

[0057] FIG. 41.1 is a graph of the simulated hydraulic fracture portion 41.1 of FIG. 38.1 depicting shear stress, and in FIG. 41.2 is a graph of the simulated hydraulic fracture of FIG. 41.1, modified based on DFN;

[0058] FIG. 42 is a schematic diagram depicting the predicted placement of proppant;

[0059] FIG. 43 is a graph depicting the predicted total well production;

[0060] FIG. 44 is a graph depicting the predicted pressure of the wellbore;

[0061] FIG. 45.1-45.2 are structural diagrams depicting various methods for performing a fracture operation, including a seismic moment;

[0062] FIG. 46.1-46.4 are graphs depicting the various stages of testing a discrete network of cracks, and

[0063] FIG. 47 is a structural diagram depicting a method for testing a discrete network of cracks;

DETAILED DESCRIPTION OF THE INVENTION

[0064] The following description includes devices, methods, methods, and sequences of instructions that embody methods of performing an object of the invention. However, it should be clear that the described embodiments can be performed without these specific details.

1. MODELING CRACK

[0065] Models have been developed to study subsurface fracture networks. Models can take into account various factors and / or data, but cannot be limited by taking into account either the amount of injected fluid, or the mechanical interactions between cracks and injected fluids, and between cracks. Model constraints may be envisaged to provide an in-depth study of the mechanisms involved, and it may be difficult to accurately model the propagation of hydraulic fracturing when describing and / or attracting resources and computer processing time. A limited model can be configured to perform simulations to take into account factors, such as the interaction between cracks, over time and under desired conditions.

[0066] The original unconventional fracture model (UFM) (or complex model) can be used to model the propagation of a complex network of fractures in a formation with previously existing natural fractures. Many branches of the crack can propagate simultaneously and intersect with each other. Each open crack can exert additional pressure on the surrounding rock and adjacent cracks, which can be called the effect of "shadowing stress". Shading stresses can limit crack parameters (e.g., width), which can lead, for example, to increase the likelihood of proppant falling out. Stress shadowing can also alter the propagation path of a crack and affect the pattern of the crack network. Stress shadowing can influence the modeling of crack interactions in a complex crack model.

[0067] A method for calculating voltage shadowing in a complex hydraulic fracturing network is provided. The method can be performed based on the advanced two-dimensional displacement discontinuity method (2D DDM) with adjustment of the final crack height or the three-dimensional displacement discontinuity method (3D DDM). The predicted 2D DDM stress field can be compared with three-dimensional numerical simulation (3D numerical simulation, 3D DDM or flac3D) to determine the approximation for a three-dimensional crack problem. This calculation of voltage shading can be combined into a UFM. The results for simple cases of two cracks show cracks that can either attract or repel each other, depending, for example, on their initial relative positions, and can be compared with an independent two-dimensional non-planar hydraulic fracture model.

[0068] Additional examples of the propagation of both flat and complex cracks from a plurality of perforation clusters are presented, showing that crack interaction can control the size and pattern of crack propagation. In a formation with low stress anisotropy, the interaction of cracks can lead to a significant deviation of the cracks, since they can tend to repel each other. However, even when the stress anisotropy is large and the rotation of the crack due to the interaction of the crack is limited, stress shadowing can have a strong effect on the crack width, which can affect the flow distribution when pumping into many perforation clusters, and therefore the overall geometry of the crack network and the placement of proppant .

[0069] FIG. Figures 1.1 and 1.2 show the propagation of a fracture along the well 100. The well has a well 104 extending from the wellhead 108 at a surface location and down through the subterranean formation 102. A fracture network 106 extends close to the well 104. A pump system 129 is located near the wellhead 108 to allow fluid to flow through the string 142.

[0070] A pump system 129 is shown operated by a field operator 127 to store records and operating data and / or perform actions in accordance with a set injection schedule. The pump system 129 pumps fluid from the surface into the well 104 during a fracturing operation.

[0071] The pump system 129 may include a water source, such as a plurality of water tanks 131, which supply water to the gel hydration unit 133. To form a gel in the gel hydration unit 133, water from the tanks 131 is combined with a gelling agent. The gel is then sent to a blender 135, where it is mixed with proppant from the proppant vehicle 137 to form a fracturing fluid. A gelling agent can be used to increase the viscosity of the fracturing fluid, and to provide a suspended state of the proppant in the fracturing fluid. It can also act as a friction reducing agent to provide increased flow rate with less friction pressure.

[0072] The fracturing fluid is then pumped from blender 135 into preparation tanks 120 with plunger pumps, as shown by solid lines 143. Each preparation tank 120 receives fracturing fluid at low pressure and discharges it into a common manifold 139 (sometimes called a throwing trailer or projectile) at high pressure, as shown by dashed lines 141. Then, projectile 139 directs the fracturing fluid from the tankers 120 to prepare for the well 104, as shown by the solid line 115. To supply the fluid spine fracture with the necessary flow rate may be used one or more tankers 120 for training.

[0073] Each preparation tanker 120 can typically operate at a flow rate as well as at maximum operating capacity. The operation of tankers 120 for preparation at operating productivity can provide, if one of them fails, the others work at high speed to compensate for the absence of a failed pump. A computerized control system can be used to control the entire system 129 of pumps during a burst operation.

[0074] Various fluids can be used to create fractures, such as conventional proppant fluids. Other fluids, such as a “water based reagent” (which may contain a friction reducing agent (polymer) and water), can also be used to fracture shale gas wells. Such a “water-based reagent” can be in the form of an easily moving liquid (for example, with almost the same viscosity as water), and can be used to create more complex fractures, such as multiple microseismic fractures detected by monitoring.

[0075] Also, as shown in FIG. 1.1 and 1.2, the fracture network includes fractures located at different positions near the well 104. The various fractures may be natural fractures 144 that exist prior to fluid injection or hydraulic fractures 146 created near formation 102 during injection. In FIG. 1.2 shows an image of a network of 106 fractures based on microseismic events 148 collected using conventional means.

[0076] Multistage stimulation may be the norm for developing an unconventional reservoir. However, obstacles to optimizing completion in shale formations may include the lack of hydraulic fracturing models that can appropriately model the propagation of a complex fracture, often observed in such formations. A complex model of a fracture network (or UFM) has been developed (see, for example, Weng, X., Kresse, O., Wu, R., and Gu, H., Modeling of Hydraulic Fracture Propagation in a Naturally Fractured. Formation. Paper SPE 140253 presented at the SPE Hydraulic Fracturing Conference and Exhibition, Woodlands, Texas, USA, January 24-26 (2011) (hereinafter “Weng 2011”); Kresse, O., Cohen, C, Weng, X., Wu, R., and Gu, H. 2011 (hereinafter “Cresse 2011”). Numerical Modeling of Hydraulic Fracturing in Naturally Fractured Formations. 45th US Rock Mechanics / Geomechanics Symposium, San Francisco, CA, June 26-29, the contents of which are incorporated herein document in full by reference).

[0077] Existing models can be used to intensify fracture propagation, rock deformation, and fluid flow in a complex fracture network created during processing. The model can also be used to solve the completely related problem of fluid flow in a network of cracks and elastic deformation of cracks, which can have assumptions and basic equations similar to models of a pseudo-three-dimensional crack. The transport equation can be solved for each component of the injection of fluids and proppants.

[0078] Conventional flat crack models can model various aspects of a crack network. The presented UFM may also include the ability to simulate the interaction of hydraulic fractures with previously existing natural fractures, i.e. determine whether a hydraulic fracture will propagate through a natural fracture, or stop when it intersects, and subsequently propagate along a natural fracture. The branching of the hydraulic fracture at the intersection with a natural crack can lead to the development of a complex network of cracks.

[0079] The intersection model can be derived from a Renshaw and Pollard document (see, for example, Renshaw, CE and Pollard, DD 1995, An Experimentally Verified Criterion for Propagation across Unbounded Frictional Interfaces in Brittle, Linear Elastic Materials. Int.J. Rock Mech. Min. Sci. & Geomech. Abstr., 32: 237-249 (1995) the entire contents of which are incorporated herein by reference) regarding the criteria for intersecting a section surface, for application to any intersection angle, and can be developed ( see, for example, Gu, H. and Weng, X. Criterion for Fractures Crossing Frictional Interfaces at Non-orlhogonal Angles. 44th US Rock symposium, Salt Lake City, Utah, June 27-30, 2010 (hereinafter “Gu and 2010eng 2010 ’), the entire contents of which are hereby incorporated by reference) and confirmed by experimental data (see, for example, Gu, H., Weng, X., Lund, J., Mack, M., Ganguly, U . and Suarez-Rivera R. 2011. Hydraulic Fracture Crossing Natural Fracture at Non- Orthogonal Angles, A Criterion, Its Validation and Applications. Paper SPE 139984 presented at the SPE Hydraulic Fracturing Conference and Exhibition, Woodlands, Texas, January 24-26 (2011) (hereinafter “Gu et al. 2011”), the entire contents of which are incorporated herein by reference) and integrated in UFM.

[0080] To appropriately enhance the propagation of multiple complex fractures, the fracture model can take into account the interaction between adjacent branches of the hydraulic fracture, which is often called the "stress shadowing" effect. When a single flat hydraulic fracture opens under the influence of the final effective fluid pressure, it can apply a stress field to the surrounding rock that is proportional to the effective pressure.

[0081] In the extreme case of an infinitely long vertical crack of constant finite height, an analytical expression of the stress field applied by the open crack can be represented. See, for example, Warpinski, N.F. and Teufel, L.W., Influence of Geologic Discontinuities on Hydraulic Fracture Propagation, JPT, Feb., 209-220 (1987) (hereinafter “Warpinski and Toyuffel”) and Warpinski, N.R., and, Branagan, P.T., Altered-Stress Fracturing. SPE JPT, September, 1989, 990-997 (1989), the entire contents of which are incorporated herein by reference. The effective pressure (or more precisely, the pressure that this crack opens) can exert compressive stress in the direction perpendicular to the crack at the top of the minimum pressure in place, which can be equal to the effective pressure on the surface of the crack, but quickly drops with distance from the crack.

[0082] At a distance in excess of one crack height, artificially induced stress can be only a small fraction of the effective pressure. Thus, the term “stress shadowing” can be used to describe such an increase in stress in the region surrounding the crack.

If a second hydraulic fracture is created parallel to the existing open crack, and if it falls into the “stress shadowing” area (ie, the distance to the existing crack is less than the height of the crack), the second crack may actually experience a closing stress greater than initial voltage in place. As a result, more pressure can be used to propagate the crack, and / or the crack can have a smaller width than the corresponding single crack.

[0083] One application of stress shadowing studies may include creating and optimizing the location of cracks between cracks propagating simultaneously from a horizontal wellbore. In a shale formation with extremely low permeability, fractures can be closely spaced to effectively drain the formation. However, the stress shadowing effect can prevent crack propagation in close proximity to other cracks (see, for example, Fisher, MK, JR Heinze, CD Harris, BM Davidson, CA Wright, and KP Dunn, Optimizing horizontal completion techniques in the Barnett Shale using microseismic fracture mapping. SPE 90051 presented at the SPE Annual Technical Conference and Exhibition, Houston, 26-29 September 2004, the entire contents of which are incorporated herein by reference).

[0084] The interaction between parallel fractures has been studied in the past (see, for example, Warpinski and Teufel; Britt, LK and Smith, MB, Horizontal Well Completion, Stimulation Optimization, and Risk Mitigation. Paper SPE 125526 presented at the 2009 SPE Eastern Regional Meeting , Charleston, September 23-25, 2009; Cheng, Y. 2009. Boundary Element Analysis of the Stress Distribution around Multiple Fractures: Implications for the Spacing of Perforation Clusters of Hydraulically Fractured Horizontal Wells. Paper SPE 125769 presented at the 2009 SPE Eastern Regional Meeting, Charleston, September 23-25, 2009; Meyer, BR and Bazan, LW, A Discrete Fracture Network Model for Hydraulically Induced Fractures: Theory, Parametric and Case Studies. Paper SPE 140514 presented at the SPE Hydraulic Fracturing Conference and Exhibition, Woodlands , Texas, USA, January 24-26, 2011; Roussel, NP and Sharma, MM, Optimizing Fracture Spacing and Sequencing in Horizontal-Well Fracturing, SPEPE, May, 2011, pp. 173-184, the contents of which are incorporated herein in full by reference). The study may include parallel cracks in static conditions.

[0085] The stress shadowing effect may be such that cracks in the middle region of a plurality of parallel cracks may have a smaller width due to increased compressive stresses from adjacent cracks (see, for example, Germanovich, LN, and Astakhov D., Fracture Closure in Extension and Mechanical Interaction of Parallel Joints. J. Geophys. Res., 109, B02208, doi: 10.1029 / 2002 JB002131 (2004); Olson, JE, Multi-Eracture Propagation Modeling: Applications to Hydraulic Eracturing in Shales and Tight Sands. 42nd US Rock Mechanics Symposium and 2nd US-Canada Rock Mechanics Symposium, San Francisco, CA, June 29 July 2, 2008, the entire contents of which are incorporated herein by reference). When multiple cracks propagate simultaneously, the distribution of flow in the cracks can be a dynamic process and may depend on the effective pressure in the cracks. The effective pressure can be highly dependent on the width of the crack and, therefore, the effect of stress shadowing on the flow distribution and crack size requires further investigation.

[0086] The dynamics of the simultaneous propagation of multiple cracks may also depend on the relative positions of the original cracks. If the cracks are parallel, for example, in the case of a plurality of cracks that are perpendicular to the horizontal well, the cracks can repel each other, which causes the cracks to bend outward. However, if many cracks are staggered, for example, for cracks starting from a horizontal well that is not perpendicular to the plane of the crack, the interaction between adjacent cracks can be such that their vertices are attracted to each other and even join (see, for example, Olson, JE Fracture Mechanics Analysis of Joints and Veins. PhD dissertation, Stanford University, San Francisco, California (1990); Yew, CH, Mear, ME, Chang, CC, and Zhang, XC On Perforating and Fracturing of Deviated Cased Wellbores. Paper SPE 26514 presented at SPE 68lh Annual Technical Conference and Exhibition, Houston, TX, Oct. 3-6 (1993); Weng, X., Fracture Initiation and. Propagation from Deviated Wellbores. Pa per SPE 26597 presented at SPE 68th Annual Technical Conference and Exhibition, Houston, TX, Oct. 3-6 (1993), the entire contents of which are incorporated herein by reference).

[0087] When a hydraulic fracture crosses a second crack oriented in a different direction, it can apply an additional closing stress to the second crack that is proportional to the effective stress. This stress can be derived and taken into account when calculating the opening pressure of the gyrus in the analysis of leakage, which depends on pressure, during the formation of the gyrus (see, for example, Nolte, K., Fracturing Pressure Analysis for nonideal behavior. JPT, Feb. 1991, 210-218 (SPF 20704) (1991) (hereinafter “Knowlt 1991"), the entire contents of which are incorporated herein by reference.

[0088] For more complex cracks, there may be various types of crack interaction, as described above. In order to correctly take into account these interactions and to remain computationally efficient, so that it can be included in the complex model of a fracture network, the corresponding basic modeling structure can be constructed. The method based on the advanced 2D Displacement Discontinuity Method (2D DDM) can be used to calculate artificially induced stresses on a given crack and rock from the rest of a complex network of cracks (see, for example, Olson, JE, Predicting Fracture Swarms - The Influence of Sub critical Crack Growth and the Crack-Tip Process Zone on Joints Spacing in Rock. In The Initiation, Propagation and Arrest of Joints and Other Fractures, ed. JW Cosgrove and T. Engelder, Geological Soc. Special Publications, London, 231, 73-87 (2004) (hereinafter “Olson 2004”), the entire contents of which are incorporated herein by reference). A crack rotation can also be modeled based on a changed local stress direction in front of the propagating crack tip due to the stress shadowing effect. The results of modeling by the UFM model are presented, which include modeling the interaction of the crack.

UFM Model Description

[0089] To simulate the propagation of a complex network of cracks, which includes many intersecting cracks, the basic equations underlying the physics of the fracture process can be used. Basic equations may include, for example, equations determining the flow of a fluid in a network of cracks, an equation determining the deformation of a fracture, and criteria for propagation / intersection of a crack.

[0090] The continuity equation assumes that a fluid stream propagates along a network of cracks with the following mass conservation:

wherein q - local flow inside the hydraulic fracture along the length, w - average width or opening cross-sectional crack at position s = s (x, y) , H ƒl - the height of the fluid in the fracture, and qL, - volumetric leakage rate through the wall fracturing into the rock skeleton per unit height (the rate at which fracturing fluid penetrates the surrounding permeable medium), which is expressed using the Carter leakage model. The vertices of the crack propagate in the form of a sharp front, and the hydraulic fracture length at any given time t is defined as l (t).

[0091] The properties of the working fluid can be determined by a power exponent n '(an indicator of fluid behavior) and an indicator of consistency K'. The fluid flow may be laminar, turbulent, or Darcy flow through a proppant pack, and may be described accordingly using various laws. For the general case of 1D, the laminar flow of the internal size of the fluid, obeying the power law, in any given branch of the crack, the Poiseuille law can be used (see, for example, Knowlt, 1991):

Where

Here w (z) represents the crack width depending on the depth at the current position s, α is the coefficient, n '' is the exponent (the index of the consistency of the fluid), ϕ is the shape function and dz is the integration increment along the crack height in the formula.

[0092] The width of the crack may be related to the pressure of the fluid through an equation of elasticity. The elastic properties of the rock (which can be considered as mainly homogeneous, isotropic, linear, elastic material) can be determined using the elastic modulus E and Poisson's ratio v. For a vertical crack in a layered medium with an alternating minimum horizontal stress σ _h (x, y, z) and a fluid pressure p, the profile width (w) can be determined from the analytical solution in the form:

where W is the crack width at a point with spatial coordinates x, y, z (coordinates of the center of the element of the crack); p (x, y) is the fluid pressure, H is the height of the crack element, and z is the vertical coordinate along the crack element at the point (x, y).

[0093] Since the height of the cracks may vary, the system of basic equations may also include calculating the height growth, as described, for example, in Kresse 2011.

[0094] In addition to the above equations, the condition of the overall volume balance can be fulfilled:

where g _L is the fluid leakage rate, Q (t) is the time dependent on the injection rate, H (s, t) is the crack height at the spatial point s (x, y) and at t, ds is the length increment for integration along the crack length, dt is the time increment, dh _l is the increment of the leak height, H _L is the leak height and s ₀ is the coefficient of instantaneous water loss. Equation (5) provides that the total volume of fluid injected during time t is equal to the volume of fluid in the network of cracks and the amount of leakage from the crack until time t. Here L (t) represents the total length of HFN at time t and s ₀ is the coefficient of instantaneous water loss. Boundary conditions can use the flow rate, effective pressure, and crack width equal to zero at all crack tips.

, которое может быть решено, используя метод затухания Ньютона-Рафсона.[0095] The system of equations 1-5 together with the initial and boundary conditions can be used to represent a system of basic equations. The combination of these equations and the discretization of the network of cracks into small elements can lead to a nonlinear system of equations for the fluid pressure p in each element, simplified as

which can be solved using the Newton-Raphson attenuation method.

[0096] The interaction of the fracture can be taken into account to simulate the propagation of hydraulic fracturing in formations with natural fractures. This includes, for example, the interaction between hydraulic fractures and natural fractures, as well as the interaction between hydraulic fractures. Semi-analytical intersection criteria in UFM can be applied to the interaction between hydraulic fracture and natural fractures, using, for example, the approach described in Gu and Weng, 2010, and Gu et al., 2011.

Voltage shading simulation

[0097] For parallel discontinuities, stress shadowing can be represented by applying offsets from adjacent cracks. In FIG. 2 is a schematic representation of a two-dimensional crack 200 in a coordinate system having an x axis and a y axis. Various points along two-dimensional cracks, such as the first end at h / 2, the second end at -h / 2, and the middle end go to the observation point (x, y). Each line L passes at angles θ1, θ2 from points along a two-dimensional crack to the observation point.

[0098] The stress field around a two-dimensional crack with an internal pressure p can be calculated using, for example, the methods described in Warpinski and Toifel. The stress that affects the crack width is σ _x , and can be calculated from the equation:

Where

– координаты и расстояния на фиг. 2, приведенные по половине высоты h/2 трещины. Поскольку σ_x изменяется в направлении y, а также в направлении x, среднее напряжение на высоте трещины может быть использовано в вычислении затенения напряжения.and where σ _x is the stress in the x direction, p is the internal pressure, and

- coordinates and distances in FIG. 2 given at half height h / 2 of the crack. Since σ _x varies in the y direction, as well as in the x direction, the average stress at the crack height can be used in calculating the stress shadowing.

[0099] The analytical equation above can be used to calculate the average effective stress of a single crack on an adjacent parallel crack, and can be included in the effective closure stress on that crack.

[00100] For more complex fracture networks, the fractures can orient in different directions and cross each other. In FIG. 3 depicts a complex network of 300 cracks depicting the effects of voltage shadowing. The fracture network 300 includes a hydraulic fracture 303 extending from the well 304 and interacting with other fractures 305 in the fracture network 300.

[00101] A more general approach can be used to calculate the effective stress at any given crack branch from the rest of the crack network. In UFM, the mechanical interaction between cracks can be modeled on the basis of the advanced two-dimensional Displacement Discontinuity Method (DDM) (Olson 2004) for calculating artificially induced stresses (see, for example, Fig. 3).

влияния в сочетании с преобразованными уравнениями упругости 2D DDM следующим образом:[00102] In two-dimensional planar deformation, a solution to displacement discontinuity, (see, for example, Crouch, SL and Starfield, AM, Boundary Element Methods in Solid Mechanics, George Allen & Unwin Ltd, London. Fisher, MK (1983) (hereinafter Crouch and Starfield 1983), the entire contents of which are incorporated herein by reference) can be used to describe normal stresses and shear stresses (σ _n and σ _s ) acting on a crack element caused by opening and shear discontinuity displacements (Dn and Ds) from all elements of the crack. To take into account the three-dimensional effect due to the finite crack height, Olson 2004 can be used to create a three-dimensional correction factor for the coefficients

effects in conjunction with the transformed 2D DDM equations of elasticity as follows:

(8.1)

(8.1)

(8.2)

(8.2)

where A is the matrix of influence coefficients described in equation (9), N is the total number of elements in the network whose interaction is taken into account, i is the element in question and j = 1, N are other elements in the network whose influence on the voltage on element i is calculated ; and wherein C _ij - influence coefficients of two-dimensional planar elastic deformation. These expressions can be found in Crouch and Starfield 1983.

[00103] Elements i and j of FIG. 3 schematically depict the variables i and j in equations (8.1, 8.2). The discontinuities D _s and D _n applied to element j are also shown in FIG. 3. D _n may be the same as the crack width, and shear stress s may be 0, as shown. Gap displacement from element j creates stress on element i, as denoted by σ _s and σ _n .

[00104] The three-dimensional correction factor proposed in Olson 2004 can be represented by the following expression:

where h is the crack height, d _ij is the distance between the elements i and j, α and β are the fitting parameters. Equation 9 shows that a three-dimensional correction factor can lead to a weakening of the interaction between any two elements of the crack with increasing distance.

[00105] In the UFM model, additional artificially generated stresses can be calculated at each time step due to the effects of voltage shadowing. It can be assumed that at any time, the crack width is equal to the normal displacement discontinuities (D _n ), and the shear stress on the crack surface is zero, i.e. Dj By substituting these two conditions into equations 8.1 and 8.2, ruptures in shear displacements (D _s) and normal stresses artificially created on each element (σ _n) crack can be found.

[00106] The effects of stresses caused by voltage shading on a crack network propagation pattern can be described in two groups. Firstly, during the repetition of the pressure and the width, the initial stresses in place at each element of the crack can be changed by adding additional normal stress due to the effect of shading stress. This can directly affect the distribution of pressure and crack width, which can lead to a change in crack growth. Secondly, when artificially induced stresses (normal stresses and shear stresses) are turned on, the local stress fields in front of the propagating peaks can also be changed, which can cause the local direction of the main stress to deviate from the original stress direction in place. Such a changed local direction of the main stress can lead to the rotation of the crack from the original propagation plane, and can additionally affect the propagation pattern of the network of cracks.

Validation of the voltage shadowing model

[00107] Validation of the UFM model for cases of bilateral cracks can be performed using, for example, Weng 2011 or Kresse 2011. Validation can also be performed using the stress shadowing simulation approach. As an example, the results can be compared using a 2D DDM comparison with Flac 3D, as presented in Itasca Consulting Group Inc, 2002, FLAC3D (Fast Lagrangian Analysis of Continua in 3 Dimensions), Version 2.1, Minneapolis: ICG (2002) (hereinafter "Itasca, 2002").

Comparison of Advanced 2D DDM Methods with Flac3D

[00108] The three-dimensional correction factors proposed in Olson 2004 contain two empirical constants, α and β. The values of α and β can be checked by comparing the stresses obtained from numerical solutions (extended 2D DDM) with the analytical solution for a plane-deformed crack with infinite length and finite height. The model can be further verified for reliability by comparing 2D DDM results with complete three-dimensional numerical solutions using, for example, FLAC3D, for two parallel straight-line cracks with finite lengths and heights.

[00109] The validation problem is shown in FIG. 4. In FIG. 4 is a schematic diagram 400 comparing extended 2D DDM with Flac3D for two parallel straight fractures. As shown in FIG. 400, two parallel cracks 407.1, 407.2 are exposed to stresses σ _x , σ _y along the x, y coordinate axes. The cracks have a length of 2L _xf , and the crack pressure is p ₁ , p _2, respectively. Cracks are at a distance s from each other.

[00110] A crack in Flac3D can be modeled as two surfaces at the same location, but with loose mesh nodes. Constant internal fluid pressure can be applied as normal stress to the grids. Cracks can also be affected by stresses at infinity, σ _x and σ _y . Two cracks can have the same length and height with a ratio of height / half length = 0.3.

[00111] You can compare stresses along the x axis (y = 0) and the y axis (x = 0). Two closely spaced cracks (s / h = 0.5) can be modeled as shown by comparing FIG. 5.1-5.3. These drawings are a comparison of advanced 2D DDM with Flac3D: Voltages along the x axis (y = 0) and y axis (x = 0).

[00112] These drawings contain graphs 500.1, 500.2, 500.3, respectively, illustrating 2D DDM and Flac3D of extended cracks for σ _y along the y axis, σ _x along the y axis, and σ _y along the x axis, respectively. In FIG. Figure 5.1 shows the σ _y / p curves (y axis) versus the normalized distance from the crack (x axis) using 2D DDM and Flac3D. In FIG. Figure 5.2 shows the σ _x / p curves (y axis) versus the normalized distance from the crack (x axis) using 2D DDM and Flac3D. In FIG. Figure 5.3 shows the σ _y / p curves (y axis) versus the normalized distance from the crack (x axis) using 2D DDM and Flac3D. The location L _{f of} the crack tip is depicted along the x / h line.

[00113] As shown in FIG. 5.1-5.3, the stresses modeled from the advanced 2D DDM approach with a three-dimensional correction coefficient are in good agreement with the results of a full three-dimensional simulation model, and this shows that the correction coefficient allows one to capture the three-dimensional effect along the crack height on the stress field.

Comparison with CSIRO Model

[00114] A UFM model that combines the advanced 2DDM approach can be validated against the full 2D DDM simulation model using CSIRO (see, for example, Zhang, X., Jeffrey, RG, and Thiercelin, M. 2007, Deflection and Propagation of Fluid-Driven Fractures at Frictional Bedding Interfaces: A Numerical Investigation. Journal of Structural Geology, 29: 396-410, (hereinafter “Zhang 2007”), the entire contents of which are incorporated herein by reference). This approach can be used, for example, in the limited case of a very large crack height, where 2D DDM approaches do not take into account the three-dimensional effects of the crack height.

[00115] A comparison can be made of the influence of two closely propagating cracks in the propagation path of each other. The propagation of two hydraulic fractures starting parallel to each other (propagation along the local direction of maximum voltage) can be simulated for configurations, such as: 1) the starting points on top of each other and offset from each other for isotropic, and 2) anisotropic far-field stresses. The crack propagation path and pressure within each crack can be compared for the UFM and CSIRO code for the input data given in Table 1.

Table 1

Validation input versus CSIRO model

Upload speed 0.106 m ³ / s 40 barrels / min Stress anisotropy 0.9 MPa 130 psi inch Elastic modulus 3 × October ¹⁰ Pa 4.35e + 6 psi inch Poisson's ratio 0.35 0.35 Fluid viscosity 0.001 Pa⋅s 1 centipoise The specific gravity of the fluid 1,0 1,0 Min horizontal stress 46.7 MPa 6773 psi inch Max. horizontal stress 47.6 MPa 6903 psi inch Fracture toughness 1 MPa⋅m ^0.5 1000 psi inch / inch 0.5 Crack height 120 m 394 ft

 [00116] When two cracks start parallel to each other at the origin points divided by dx = 0, dy = 33 ft (10.1 m) (the maximum horizontal stress field is oriented in the x direction), they can rotate from each other due to the effect shading voltage.

[00117] The propagation paths for isotropic and anisotropic stress fields are shown in FIG. 6.1 and 6.2. The drawings show graphs 600.1, 600.2, depicting propagation paths for two initially parallel cracks 609.1, 609.2 in isotropic and anisotropic stress fields, respectively. Cracks 609.1 and 609.2 are initially parallel near injection points 615.1, 615.2, but deviate as they continue from them. Compared with the isotropic case, the curvature of the cracks in the case of stress anisotropy is depicted as being less. This can occur due to competition between the effect of shading stress, which tends to rotate cracks from each other, and far-field stresses, which cause cracks to propagate in the direction of maximum horizontal stress (x direction). The effect of far-field stress becomes predominant when the distance between the cracks increases, in this case, cracks can tend to propagate parallel to the direction of the maximum horizontal stress.

[00118] In FIG. Figures 7.1 and 7.2 show graphs 700.1, 700.2 showing a pair of cracks starting from two different points of injection 711.1, 711.2, respectively. These drawings show a comparison for the case when cracks start from points separated by a distance dx = dy = (10.1 m) for an isotropic and anisotropic stress field, respectively. In these drawings, cracks 709.1, 709.2 tend to propagate towards each other. Examples of a similar type of behavior were observed in laboratory experiments (see, for example, Zhang 2007).

[00119] As shown above, the advanced 2D DDM approach implemented in the UFM model may be able to capture the three-dimensional effects of a finite crack height on the interaction and propagation pattern of a crack, while being efficient in the calculation. A satisfactory estimate of the stress field for a network of vertical hydraulic fractures and the direction (pattern) of crack propagation can be presented.

Cases of Examples

Case No. 1 - Parallel Cracks in Horizontal Wells

[00120] In FIG. 8 is a schematic graph of 800 parallel transverse fractures 811.1, 811.2, 811.3, propagating simultaneously from a plurality of clusters 815.1, 815.2, 815.3 perforations respectively around a horizontal well 804. Each of the fractures 811.1, 811.2, 811.3 provides different costs q1, q2, q3, which are part of the total flow qt at pressure p0.

[00121] When the conditions of formation and perforation are the same for all cracks, the cracks can be approximately the same size if the friction pressure in the well between the clusters of perforations is proportionally small. This can be assumed when the cracks are separated by a sufficiently large distance, and the effects of stress shadowing are negligible. When the gaps between the cracks are in the area of influence of the shadowing of the stress, the cracks can be dependent not only on the width, but also on a different crack size. To illustrate this, a simple example of five parallel cracks can be considered.

[00122] In this example, it is assumed that the cracks have a constant height of 100 feet (30.5 m). The gap between the cracks is 65 feet (19.8 m). Other input parameters are given in table 2:

table 2

Input parameters for case No. 1

Elastic modulus 6.6 × l0 ⁶ psi inch = 4.55e + 10 Pa Poisson's ratio 0.35 Upload speed 12.2 barrel / min = 0.032 m ³ / s Viscosity 300 centipoise = 0.3 Pa⋅s Height 100 ft = 30.5 m Leak rate 3.9 × 10 ^-2 m / s ^1/2 Stress anisotropy 200 psi inch = 1.4 MPa Gap between cracks 65 ft = 19.8 m Number of perforations per crack one hundred

For this simple case, the traditional Perkins-Kern-Nordgren (Perkins-Kern-Nordgren, PKN) model (see, e.g., Mack, MG and Warpinski, NR, Mechanics of Hydraulic Fracturing. Chapter 6, Reservoir Stimulation, 3rd Ed., Eds. Economides, MJ and Nolte, KG John Wiley & Sons (2000)) for many cracks can be modified by combining the calculation of stress shadowing as given in Equation 6. The increase in closure stress can be approximated by averaging the calculated stress from Equation 6 over the entire crack. It should be noted that the simplified PKN model may not simulate crack rotation due to the effect of stress shadowing. The results of such a simple model can be compared with the results of the UFM model, which combines the calculation of stress shadowing along points along all crack paths, as well as crack rotation.

[00123] In FIG. Figure 9 shows the results of modeling crack lengths for five cracks calculated from both models. In FIG. 9 is a graph 900 depicting a length (y axis) versus time (t) of five parallel cracks during injection. Lines 917.1-917.5 are created according to the UFM model. Lines 919.1-919.5 are created using the simplified PKN model.

[00124] The fracture geometry and width profile of the UFM model for the five fractures of FIG. 9 are shown in FIG. 10. In FIG. 10 is a schematic diagram 1000 showing fractures 1021.1-1021.5 around well 1004.

[00125] Crack 1021.3 is the middle of five cracks, and cracks 1021.1 and 1021.5 are extreme cracks. Since the cracks 1021.2, 1021.3 and 1021.4 have a smaller width than the external cracks, due to the effect of shading stress, they can have greater hydraulic resistance, receive less flow and have a shorter length. Therefore, the effects of stress shadowing can affect not only the crack width, but also the crack length under dynamic conditions.

[00126] The effect of stress shadowing for fracture geometry may depend on many parameters. To illustrate the effect of some of these parameters, the calculated crack lengths for cases with varying gaps between cracks, perforation friction, and stress anisotropy are shown in Table 3.

[00127] In FIG. 11.1 and 11.2 show fracture geometry calculated using UFM for the case of large friction perforations and the case of a large gap between cracks (for example, about 120 feet (36.6 m)). In FIG. 11.1 and 11.2 are schematic diagrams 1100.1 and 1100.2 depicting five fractures 1123.1-1 123.5 around well 1104. When the perforation friction is high, a large deflection force can be created that evenly distributes the flow rate over all perforation clusters. Therefore, stress shadowing can be overcome, and the resulting crack lengths can become approximately equal, as shown in FIG. 11.1. When the gaps between the cracks are large, the stress shadowing effect can dissipate, and the cracks can be approximately the same size, as shown in FIG. 11.2.

Table 3

The influence of various parameters on the geometry of the crack

Crack Base case Gap 120 ft (36.6 m) Number of perforations = 2 Anisotropy = 50 psi inch (345,000 Pa) one 133 113 105 111 2 93 104 104 95 3 83 96 104 99 four 93 104 one hundred 95 5 123 113 109 102

Case No. 2 - Complex Cracks

[00128] In the example of FIG. 12, the UFM model can be used to model a 4-stage hydraulic fracturing in a horizontal well in a shale formation. See, for example, Cipolla, C., Weng, X., Mack, M., Ganguly, U., Kresse, O., Gu, H., Cohen, C. and Wu, R., Integrating Microseismic Mapping and Complex Fracture Modeling to Characterize Fracture Complexity. Paper SPE 140185 presented at the SPE Hydraulic Fracturing Conference and Exhibition, Woodlands, Texas, USA, January 24-26 (2011) (hereinafter “Zippola 2011”), the entire contents of which are incorporated herein by reference. The well can be cased and cemented, and each stage is pumped through three or four perforation clusters. Each of the four stages can include approximately 25,000 barrels (4000 m3) of fluid and 440,000 pounds (2e + 6 kg) of proppant. Spatial data may be available at the well, including advanced sonic logging, which provides an estimate of the minimum and maximum horizontal stresses. Microseismic survey data may be available at all stages. See, for example, Daniels, J., Waters, G., LeCalvez, J., Lassek, J., and Bentley, D., Contacting More of the Barnett Shale Through an Integration of Real-Time Microseismic Monitoring, Petrophysics, and Hydraulic Fracture Design. Paper SPE 110562 presented at the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, USA, October 12-14, 2007. This example is shown in FIG. 12. In FIG. 12 is a graph depicting microseismic imaging of microseismic events 1223 at various stages around well 1204.

[00129] Anisotropy of stress from enhanced sonic logging shows a higher stress anisotropy in the near-wellbore zone compared to the wellhead. An extended three-dimensional seismic interpretation may indicate that the predominant natural fracture tends to change from NE-SW (north-east to south-west direction) in the bottomhole zone to NW-SE (north-west to southeast direction) in the lateral mouth area parts. See, for example, Rich, J.P. and Ammerm-an, M., Unconventional Geophysics for Unconventional Plays. Paper SPE 131779 presented at the Unconventional Gas Conference, Pittsburgh, Pennsylvania, USA, February 23-25, 2010, the entire contents of which are incorporated herein by reference.

[00130] The simulation results can be based on the UFM model without including the full calculation of stress shadowing (see, for example, Zippola 2011), including shear stress and crack rotation (see, for example, Hungary 2011). Simulations can be updated using the full stress model proposed in this document. In FIG. 13.1-13.4, a plan view of the simulated network 1306 of fractures around the well 1304 is shown for four stages, respectively, and their comparison with microseismic measurements 1323.1-1323.4, respectively.

[00131] From the simulation results in FIG. 13.1-13.4, it can be seen that for steps 1 and 2 closely spaced cracks deviated slightly. This can occur due to high stress anisotropy in the bottom hole zone of the well. For steps 3 and 4, where the stress anisotropy is less, a larger crack deviation can be observed as a result of the stress shadowing effect.

Case No. 3 - An Example of Several Steps

[00132] Case No. 3 is an example showing how the shadowing of voltage from previous stages can affect the propagation of hydraulic fracture networks for the next processing steps, leading to a change in the overall picture of the created hydraulic fracture network for the case of four processing steps.

[00133] This case includes four stages of fracturing treatment. The well is cased and cemented. Steps 1 and 2 are pumped through three perforation clusters, and steps 3 and 4 are pumped through four perforation clusters. The rock is isotropic. The input parameters are shown in Table 4. A top view of the entire network of hydraulic fractures without and taking into account the voltage shadowing from the previous stages is shown in FIG. 13.1-13.4.

Table 4

Input parameters for case No. 3

Elastic modulus 4,5 × ¹⁰ June psi. inch = 3.1e + 10 Pa Poisson's ratio 0.35 Upload speed 30.9 bbl / min = 0,082 ^m3 / s Viscosity 0.5 centipoise = 0,0005 Pa⋅s Height 330 ft = 101 m Upload time 70 min

 [00134] In FIG. 14.1-14.4 are schematic diagrams 1400.1-1400-4 depicting a network of 1429 fractures at various stages during a fracturing operation. In FIG. 14.1 shows a discrete fracture network 1429 (DFN) before processing. In FIG. 14.2 shows the simulated DFN 1429 after the first processing step. DFN 1429 has widespread hydraulic fractures (HFN) 1431, passing through it due to the first stage of processing. In FIG. Figure 14.3 shows a DFN depicting simulated HFNs 1431.1-1431.4, common in four steps, respectively, but without taking into account the effects of the previous step. In FIG. 14.4 shows a DFN depicting HFN 1431.1, 1431.2'-1431.4 ', common during the four stages, respectively, but taking into account discontinuities, voltage shading and HFN from the previous stages.

[00135] When steps are created separately, they may not meet each other, as shown in FIG. 14.3. When voltage shading and HFNs from prior steps are taken into account, as shown in FIG. 14.4, the distribution pattern may change. Hydraulic fractures 1431.1 created during the first stage are the same for both scenarios, as shown in FIG. 14.3 and 14.4. The propagation pattern of the second stage 1431.2 may be influenced by the first stage due to voltage shadowing, as well as due to the new DFN (including HFN 1431.1 from stage 1), which leads to a change in the propagation pattern to HFN 1431.2 '. HFN 1431.1 'may begin to adhere to HFN 1431.1, created in step 1, when accounting for it. The third stage 1431.3 may adhere to the hydraulic fracture created during the second stage of processing 1431.2, 1431.2 ', and may not extend too far due to the effect of shading the voltage from stage 2, as shown 1431.3 in comparison with 1431.3'. Step 4 (1431.4) may tend to turn from step three whenever possible, but may adhere to HFN 1431.3 'from previous steps when encountered, and is depicted as HFN 1431.4' in FIG. 14.4.

[00136] A method for calculating voltage shading in a complex hydraulic fracturing network is provided. The method may include an extended two-dimensional or three-dimensional discontinuity fracture correction method for a finite crack height. The method can be used to approximate the interaction between different branches of a crack in a complex network of cracks for the fundamental problem of a three-dimensional crack. This calculation of stress shadowing can be integrated into UFM, a complex model of a fracture network. The results for simple cases of two cracks show cracks that can either attract or repel each other, depending on their initial relative positions, and are preferably compared with an independent two-dimensional non-planar hydraulic fracture model.

[00137] Modeling multiple parallel fractures from a horizontal well can be used to confirm the behavior of two extreme fractures, which may be more predominant, while internal fractures have a reduced crack length and width due to the stress shadowing effect. This behavior may also depend on other parameters, such as perforation friction and gaps between cracks. If the gaps between the cracks are greater than the height of the crack, the effect of shading stress can be reduced, and there may be slight differences between the plurality of cracks. If the perforation friction is large, a sufficient deviation can be made to distribute the flow evenly between the clusters of perforations, and the size of the crack can become approximately equal despite the effect of shading stress.

[00138] When complex cracks are created, if the formation has a low stress anisotropy, the interaction of the crack can lead to a significant deviation of the cracks when they tend to repel each other. On the other hand, for large stress anisotropy, there may be a limited deviation of the crack if the stress anisotropy biases the effect of rotation of the crack due to shadowing, and the crack may be forced to go in the direction of maximum stress. Regardless of the number of crack deviations, stress shadowing can affect the crack width, which can affect the distribution of the injection rate into many perforation clusters, and the overall imprint of the crack network, and the placement of the proppant.

[00139] In FIG. 15 is a flowchart depicting a method 1500 for performing a fracturing operation at a drilling site, such as the drilling site 100 of FIG. 1.1. The drilling site is located near the underground formation, which has a well drilled in it and a network of fractures. The crack network has natural cracks, as shown in FIG. 1.1 and 1.2. Method (1500) may include (1580) performing an intensification operation by intensifying a drilling site by pumping injected fluid with proppant into a network of fractures to form a network of hydraulic fractures. In some cases, intensification may be performed at the drilling site or by modeling.

[00140] The method includes (1582) obtaining data from a well site and a mechanical model of the geological environment of an underground formation. The rig data may include any data about the rig site that may be useful for modeling, such as natural fracture parameters for natural fractures, images of a fracture network, and the like. Natural crack parameters may include, for example, density orientation, distribution, and mechanical properties (e.g., friction coefficients, cohesion, fracture toughness, etc.). Fracture parameters can be obtained by direct observation of studies by a downhole scanner, evaluated by three-dimensional seismic measurements, ant tracking algorithm, anisotropy of acoustic waves, curvature of the geological layer, microseismic events or images, etc. Examples of methods for obtaining crack parameters are presented in document PCT / US2012 / 059774, the entire contents of which are incorporated herein by reference.

[00141] Images can be obtained, for example, by observational studies with a downhole scanner, estimated fracture sizes based on borehole measurements, microseismic imaging, and / or other fracture dimensions can be estimated by estimated seismic measurements, ant tracking algorithm, acoustic measurements, geological measurements and / or others. Other well site data can also be generated from various sources, such as well site measurements, historical data, assumptions, etc. Such data may include, for example, measurements of completion, geological structure, petrophysical, geomechanical, logging and other forms of data. A mechanical model of the geological environment can be obtained using conventional methods.

[00142] The method (1500) also includes creating (1584) a hydraulic fracture growth pattern over time, for example, during an intensification operation. In FIG. 16.1-16.4 shows an example of creating (1584) a hydraulic fracture growth scheme. As shown in FIG. 16.1, in the initial state, the network of cracks 1606.1 with natural cracks 1623 is located along the underground formation 1602 with a well 1604 in it. The proppant is pumped into the subterranean formation 1602 from the well 1604, the pressure from the proppant creates hydraulic fractures 1691 around the well 1604. Hydraulic fractures 1691 extend into the subterranean formation along L1 and L2 (Fig. 16.2), and eventually encounter other fractures in the network 1606.1 cracks as shown in FIG. 16.2-16.3. Contact points with other cracks are intersections 1625.

[00143] Creation (1584) may include (1586) extending hydraulic fractures from a well into a fracture network of an underground formation to form a fracture network including natural fractures and fractures, as shown in FIG. 16.2. The crack growth pattern is based on the parameters of the natural crack and the minimum stress and maximum stress on the underground formation. The creation may include determining (1588) hydraulic fracturing parameters (e.g., pressure p, width w, flow q, etc.) of hydraulic fractures, (1590) determining transfer parameters for the proppant passing through the hydraulic fracturing network, and determination (1592) of fracture dimensions (for example, height) of hydraulic fractures, for example, based on certain parameters of the hydraulic fracture, certain transfer parameters, and a mechanical model of the geological environment. The fracture parameters can be determined after passing. Definition (1592) can also be performed on the basis of proppant transfer parameters, parameters of the drilling site, and other elements.

[00144] Creation (1584) may include modeling rock properties based on a mechanical model of the geological environment, as described, for example, in Koutsabeloulis and Zhang, 3D Reservoir Geomechanics Modeling in Oil / Gas Field Production, SPE Paper 126095, 2009 SPE Saudi Arabia Section Technical Symposium and Exhibition held in Al Khobar, Saudi Arabia, May 9-11, 2009 (Coatesabeloulis, 2009), the entire contents of which are incorporated herein by reference. The creation may also include modeling a fracture operation by using well site data and / or images as modeling software such as UFM ™ and PETREL ™ available from SCHLUMBERGER TECHNOLOGY CORPORATION ™ (see: www.slb.com) for creating successful images of induced hydraulic fractures in a fracture network.

[00145] The method (1500) also includes performing (1594) shading stresses on hydraulic fractures to determine the interaction of stresses between hydraulic fractures (or with other cracks), and repeating (1598) creating (1584) based on stress shading and / or determining the interaction stresses between hydraulic fractures. Repetition can be performed to take into account the interaction of the crack, which can affect the growth of the crack. The stress shadowing may include, for example, 2D or 3D DDM for each of the fractures and updating the crack growth pattern over time. The crack growth pattern can propagate perpendicular to the local direction of the main stress in accordance with the shading of the stress. The crack growth pattern may include the effects of natural cracks and hydraulic fractures on the crack network (see FIG. 16.3).

[00146] Voltage shading can be performed for multiple wells of the wellsite. Shading stresses from different wells can be combined to determine the interaction of fractures, which is determined from each of the wells. Creation may be repeated for each of the stress shades for one or more of the plurality of wells. Creation can also be repeated to obscure the stress performed when performing stimulation from multiple wells. A number of simulations can also be performed on the same well with various combinations of data and compared, if necessary. Retrospective or other data can also be entered into the creation to present a variety of sources of information for consideration in the final results.

[00147] The method also includes determining (1596) the intersection behavior between hydraulic fractures and a encountered crack, if the hydraulic fracture meets another fracture, and repeating (1598) the creation (1598) based on the intersection behavior if the hydraulic fracture meets the crack ( see, for example, Fig. 16.3). Intersection behavior can be determined using, for example, the methods of document PCT / US2012 / 059774, the entire contents of which are incorporated herein by reference.

[00148] Determining intersection behavior may include performing voltage shading. Depending on the downhole conditions, the fracture growth pattern may be unchanged or variable when hydraulic fracture meets the fracture. When the crack pressure is greater than the stress acting on the encountered crack, the crack growth pattern may propagate along the encountered crack. The crack growth pattern may continue to propagate along the crack encountered until the end of the natural crack is reached. A crack growth pattern can change direction at the end of a natural crack, with a crack growth pattern extending in a direction perpendicular to the minimum stress at the end of a natural crack, as shown in FIG. 16.4. As shown in FIG. 16.4, hydraulic fracture passes along a new path 1627, in accordance with local stresses σ ₁ and σ ₂ .

[00149] If necessary, method (1500) may also include (1599) validating a fracture growth pattern. Validation can be performed by comparing the resulting growth pattern with other data, such as microseismic images, as shown, for example, in FIG. 7.1 and 7.2.

[00150] The method can be performed in any order and, if necessary, repeated. For example, creating (1584) - (1599) can be repeated over time, for example, by repeating breaks as the network changes. Creation (1584) can be performed to update the repeated modeling performed during the creation, to take into account the interactions and effects of multiple cracks when the network of cracks intensifies over time.

II. INTERPRETATION OF MICROSEISMICITY

[00151] In one aspect of the present invention, at least one embodiment relates to methods for performing oilfield operations, such as fracturing and / or intensification operations. More specifically, at least one embodiment of the present invention relates to a method for interpreting microseismic data using a geomechanical model to calculate the stress field surrounding a network of cracks and potential shear failure in natural cracks. This can lead to validation values and a more accurate determination of the geometry of the discontinuity network.

[00152] The invention also relates to the interpretation of hydraulic fracturing based on the analysis of microseismicity and stress. A method is presented for considering microseismicity initiated as a result of the interaction between hydraulic fractures and natural fractures. Geomechanical models can be used to determine the stress fields surrounding a network of cracks, and potential fracture damage in a shear network of cracks in natural cracks. The fracture geometry can be determined based on geomechanical models.

[00153] The interpretation of hydraulic fracturing can be performed using 2D and 3D DDM methods to describe the artificially generated stress on a given crack caused by other cracks, as described above. Interpretation of hydraulic fracturing can also be performed using 2D DDM and 3D DDM stress field methods to calculate the stress field for crack accumulations with known boundary displacements. In field stress methods, in calculating microseismicity, DDM is used to calculate stresses in the rock and / or on closed natural fractures located away from hydraulic fractures. DDM can be used to create artificially induced stresses on a crack by other cracks using 2D, 3D DDM, and / or to create stresses on distant cracks using advanced DDM.

[00154] In modern methods and systems for monitoring hydraulic fracturing, a map of places where gaps occur and the passage of gaps can be compiled. In some methods and systems for microseismic monitoring, the locations of seismic events can be processed by mapping information about the moments of arrival and polarization of the seismic wave in three-dimensional (3D) space using simulated moments of movement and / or beam paths. These methods and systems can be used to derive the propagation of hydraulic fracture over time.

[00155] A study of the nature and degree of complexity of hydraulic fracturing may be useful for the economic development of unconventional sources. Examples of hydraulic fracturing methods are described in the following documents: Mayerhofer et al., Integrating of Microseismic Fracture Mapping Results with Numerical Fracture Network Production Modeling in the Barnett Shale, Society of Petroleum Engineers (SPE) 102103. presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas. 24-24 September 2006; Mayerhofer et al., What is Stimulated Reservoir Volume (SRV) ?, SPE 119890 presented at the SPE Shale Gas Production Conference, Fort Worth, Texas, November 16-18, 2008; Warpinski et al., Stimulating Unconventional Reservoirs: Maximizing Network Growth while Optimizing Fracture Conductivity, SPE 114173 presented at the SPE Unconventional Reservoirs Conference, Keystone, Colorado, February 10-12, 2008; and Cipolla et al., The Relationship between Fracture Complexity, Reser \ 'oir Properties, and Fracture Treatment Design, SPE 115769 presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, September 21-24, 2008, the contents of which are included in this full document by reference.

[00156] The complex propagation of hydraulic fracturing can be interpreted based on microseismic measurements, for example, from unconventional formations and low permeability formations. Examples of complex fracturing methods are described in the following documents: Maxwell et al., Microseismic Imaging of Hydraulic Fracture Complexity in the Barnett Shale, SPE 77440 presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, September 29-0ctober 2, 2002 ; Fisher et al., Integrating Fracture Mapping Technologies to Optimize Stimulations in the Barnett Shale, 77411 presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, September 29-0ctober 2, 2002; Cipolla et al .. Effect of Well Placement on Production and Frac Design in a Mature Tight Gas Field, 95337 presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, October 9-12, 2005; and Warpinski et al., Stimulating Unconventional Reservoirs: Maximizing Network Growth while Optimizing Fracture Conductivity, SPE 114173 presented at the SPE Unconventional Reservoirs Conference, Keystone, Colorado, February 10-12, 2008, the entire contents of which are incorporated herein by reference.

[00157] Additional methods related to the gap are presented in documents Zhao, X.P. and Young, R.P. 2009, Numerical Simulation of Seismicity Induced by Hydraulic Fracturing in Naturally Fractured Reservoirs, Paper SPE 124690 presented at the Annual Technical Conference and Exhibition, New Orleans, LA, USA, October 4-7; Meyer, B.R. and Bazan, L.W. (2011) “A Discrete Fracture Network Model for Hydraulically-Induced Fractures: Theory, Parametric and Case Studies,” Paper SPE 140514 presented at the SPE Hydraulic Fracturing Conference and Exhibition, Woodlands, Texas, January 24-26; Jeffery, R.G .. Zhang. X .. and Thiercelin, M. 2009, Hydraulic Fracture Offsetting in Naturally Fractured Reservoirs: Quantifying a Pong-Recognized Process, Paper SPE 119351 presented at 2009 SPE Hydraulic Fracturing Technology Conference, Woodlands, TX, 19-21 January; and Wu, R., Kresse, O., Weng, X., Cohen, C., and Gu, H. 2012, Modeling of Interaction of Hydraulic Fractures in Complex Fracture Networks, Paper SPE 152052 presented at the SPE Hydraulic Fracturing Technology Conference and Exhibition held in The Woodlands, Texas, USA, February 6-8 (“Wu 2012”), the entire contents of which are incorporated herein by reference.

[00158] In FIG. 17-19.2 depict stresses applied to hydraulic fractures and natural rock fractures, such as a formation around a well, as shown, for example, in FIG. 1.1 and 1.2. As shown in these figures, microseismic events can be triggered due to the interaction between the geometry of the crack and the stress properties associated with the cracks. Microseismic events recorded during hydraulic fracturing operations can be used to interpret the geometry of an artificially generated fracture. Each microseismic event can be the result of a sudden release of local elastic energy stored in the rock associated with the propagation of a crack, for example, under the influence of shear strain.

[00159] Examples of microseismic event methods are provided in Warpinski, N.R., Branagan, P.T., Peterson, R.E., Wolhart, S.L., and Uhl, J.E. 1998, Mapping Hydraulic Fracture Growth and Geometry Using Microseismic Events Detected by a Wireline Retrievable Accelerometer Array, Paper SPE 40014 presented at the 1998 Gas Technology Symposium, Calgary, Alberta, Canada, March 15-18; Cipolla, CL, Peterman, F., Creegan, T., McCarley, D. and Nevels, H. 2005, Effect of Well Placement on Production and Frac Design in a Mature Tight Gas Field, Paper SPE 95337 presented at the 2005 SPE Annual Technical Conference and Exhibition, Dallas, Texas, October 9-12; Maxwell, SC, Urbancic, TI, Steinsberger, NP, and Zinno, R. 2002, Microseismic Imaging of Hydraulic Fracture Complexity in the Barnett Shale, Paper SPE 77440 presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, September 29 -October 2; and Fisher, M.K., Davidson, B.M., Goodwin, A.K., Fielder, E.O., Buckler, W.S., and Steinberger, N.P. 2002, Integrating Fracture Mapping Technologies to Optimiz.e Stimulations in the Barnett Shale, Paper SPE 77411 presented at the 2002 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, September 29-October 2, which are incorporated herein by reference in their entirety. volume by reference.

[00160] In FIG. 17 is a schematic diagram 1700 depicting a simple planar hydraulic fracture 1701 propagating in a rock 1704 containing previously existing natural fractures 1702. The hydraulic fracture 1701 depicted may be a fracture created, for example, in formation 102 of FIG. 1.1. Zone 1706 surrounding hydraulic fracture 1701 shows fluid penetration into rock skeleton 1704.

[00161] The homogeneous rock skeleton 1704 may initially be subject to in-situ stresses (eg, minimum horizontal stress σ _min , maximum horizontal stress σ _max ) in the geological environment. The surfaces of natural cracks 1702 may be in contact with each other since the rock 1704 is subject to compressive stresses in place of σ _min , σ _max , as shown by arrows. If natural cracks 1702 do not coincide with the directions of the main stresses σ _min , σ _max , the surfaces of natural cracks 1702 may be subjected to shear forces, in addition to compressive normal forces. If the shear stress at the interface exceeds a limit value that can be defined as the sum of the cohesion and normal stress multiplied by the Coulomb friction coefficient (COF), the rock interface can slip, initiating crack propagation and a microseismic event that can be detected using a geophone (not shown) at some distance.

[00162] Shear failure can be interpreted based on fracture parameters, such as a fracture curve (eg, Mohr-Coulomb fracture curve) and stress state (eg, Mohr circle). In FIG. Figure 18 is a plot of 1800 depicting the 1808 Mora Coulomb fracture curve and the 1810 Mora circle. The Mora-Coulomb fracture curve 1808 can be applied to the natural fracture interface for the rock 1704 of FIG. 17. The fracture curve 1808 can be used as a model describing the reaction of a rock to shear stresses. The Mohr-Coulomb fracture curve 1808 is a graph of rock shear resistance (y axis) versus applied normal stress (x axis). The y axis denotes σ _shear .

[00163] The horizontal axis (x axis) of plot 1800 shows the effective stress, defined as the total stress σ _total in the rock, minus the pore pressure Pp. The fracture curve 1808 extends from a point along the negative direction of the x axis to σ _normal in the positive direction of the x axis at a distance above it. A tensile line 1812 on a fracture curve 1808 extending from the x axis to the y axis represents tensile fracture of the rock. A shift line 1814 from the y axis along the upper side of the fracture curve 1808 may indicate shear fracture. A seal line 1816 extending from shear failure to the x axis may indicate a seal.

[00164] A Morae circle 1810 of a natural crack can be used to indicate the initial stress state in the rock 1704. A Morae circle 1810 extends between σ ′ _min and σ ′ _max at a distance above the x axis. The Mora circle 1810 represents the normal stresses and shear stresses on the surface of the rock for any orientation θ. Mora circle 1810 can be used to graphically determine the component of stress acting on a rotating coordinate system. In other words, the Moore circle 1810 can be used to determine stress components acting on a differently oriented plane passing through a specific material point. When the pore pressure increases, the Mohr circle 1810 may shift to the left, and may cause the natural crack 1701 to slip, when the total stress remains constant.

[00165] The fracture curve 1808 may differ from the fracture curve for rock skeleton 1704, which may have a different cohesion 1811 (cohesion is the intersection of the fracture curve in shear with the y axis) and another curve. If the initial stress state in the rock 1704 is such that the corresponding Mora circle 1810 touches the shear fracture curve 1808, the natural crack is oriented at an angle θ, which corresponds to the point of contact at which the fracture curve may fall off during shear. Although the Mohr-Coulomb fracture curve and the Mohr circle are shown, other fracture curves or stress states can be used to analyze the fracture.

[00166] As shown in FIG. 17 and 18, during hydraulic fracturing treatment (for example, as shown in FIG. 1.1), fluid can penetrate the rock skeleton surrounding the hydraulic fracture 1701. As a result, pore pressure in the rock skeleton can increase and force the Moore circle 1810 to move to the left , as mentioned above. Such displacement may be the primary mechanism of seismicity during hydraulic fracturing in permeable rock. Another mechanism, which may be the predominant mechanism for extremely low permeability rock skeletons, may be a stress disorder surrounding hydraulic fracture 1701, as shown schematically in FIG. 19.

[00167] In FIG. 19.1 and 19.2 schematically illustrate a failure of 1900 stresses for the stresses σ _min , σ _vertical applied to the hydraulic fracture 1701. These stress disturbances can initiate sliding of an existing natural crack 1702 if its properties and initial stress state are such that the natural crack 1702 is close to the fracture conditions when shifting. A small stress disorder, such as that artificially formed in the rock surrounding hydraulic fracture 1701, can propel Moore's circle 1810 to achieve shear failure, and creates a microseismic event.

[00168] As shown in cross-sectional view in FIG. 19.1, a distributed stress zone 1918 can be created proportional to the crack height for crack 1701. A shear strain 1920 can be created near the distributed stress zone, as shown by double arrows. As shown in the map view of FIG. 19.1, a tensile strain T can be applied to the hydraulic fracture, as shown by the opposite arrows.

[00169] Like natural cracks 1702, if the stress state is such that a skeleton shift curve 1808 is reached, a shear crack can be created in the rock skeleton, which can also trigger a microseismic event. It may be easier to achieve a fracture state for at least some of the existing natural fractures 1702 than for a rock skeleton.

[00170] Hydraulic fracturing can be used to recover hydrocarbons, for example, in unconventional formations with ultra-low permeability, such as shale gas. As in traditional formations, microseismic monitoring can be used additionally to determine the created fracture geometry. Microseismic monitoring can show a widespread cloud of events, which can indicate complex fracture patterns or networks created during hydraulic fracturing. When a complex fracture pattern is created, the possibility of using a microseismic cloud to outline the detailed structure of the fracture network can be difficult, for example, because microseismic events may not be located in the fracture planes and / or may be located on natural fractures surrounding the fractures , and / or due to the uncertainty associated with the locations of microseismic events.

[00171] Examples of microseismic position uncertainty are presented in Maxwell, S.C. 2009, Microseismic Location Uncertainty, CSEG RECORDER, April 2009, pp. 41-46; and Maxwell, S.C., Underhill, B., Bennett, L., Woerpel, C. and Martinez, A. 2010, Key Criteria for a Successful Microseismic Project, Paper SPE 134695 presented at the SPE Annual Technical Conference and Exhibition. Florence, Italy, September 19-22, 2010, the entire contents of which are incorporated herein by reference.

[00172] In FIG. 20 is a schematic diagram 2000 illustrating how microseismicity can be triggered by the interaction between hydraulic fracture 2001 and natural fracture 2002. A timeline 2022 is shown depicting microseismic events 2028 occurring along hydraulic fracture 2001 and natural fracture 2002. Examples of microseismicity are presented in the document. Maxwell, SC and Cipolla, C. 2011. What Does Microseismicity Tell Us About Hydraulic fracturing. Paper SPE 146932 presented at the 2011 SPE Annual Technical Conference and Exhibition, Denver, CO, October 30 - November 2, the entire contents of which are incorporated herein by reference.

[00173] At time t _{1, the} hydraulic fracture 2001 is far enough from the natural fracture 2002, so that the stress disturbances surrounding the hydraulic fracture 2001 are insufficient to initiate sliding of the interfaces of the natural fracture 2002. In this case, microseismicity cannot be released from the natural fracture. At time t _{2, the} hydraulic fracture 2001 is close enough to the natural fracture 2002, so that stress disruption causes a slip slip in the natural fracture 2002, leading to microseismic event 2028.

[00174] At time t _{3, the} hydraulic fracture 2001 crosses the natural fracture 2002 and may propagate along the natural fracture 2002 or branches from the natural fracture 2002. In some cases, the natural fracture 2002, which is already connected with the hydraulic fracture 2001, may still have interfaces “Stuck together” again as a result of rock deformation or pressure fluctuations. At the last moment of time t4, the interface can again stick together and highlight a new microseismic event 2028.

[00175] Fracturing planes / surfaces can be directly extracted from microseismic data. Examples of microseismic data extraction methods are presented in Fisher et al., Integrating Fracture Mapping Technologies to Optimiz.e Stimulations in the Barnett Shale, Paper SPE 77411 presented at the 2002 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, September 29 -October 2, 2002; Craig, D.P. and Burkhart, R., Using Maps of Microseismic Events to Define Reservoir Discontinuities, Paper SPE 135290 presented at SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September, 2010; Williams et al .. Quantitative Interpretation of Major Planes from Microseismic Event locations With Application in Production Prediction, submitted to SEG Annual Meeting (2010), and US Patent Application No. 2011/0029291, the contents of which are incorporated herein in full by reference.

[00176] In at least some cases, fracture surfaces extracted directly from the microseismic cloud of events using certain methods may have great uncertainty, for example, as events may not be on actual fracture surfaces, as described above. These methods may not use other information, such as formation properties and the volume of fluid pumped. Interpretation of microseismic sound signals can provide information such as the moment tensor of the microseismic source, voltage reduction, and slip effective zone. Such information cannot be fully used to correlate with hydraulic fracture geometry.

[00177] In order to incorporate formation characteristics and injection information, hydraulic fracturing models have been developed to simulate the propagation of a complex fracture in natural fractured formations. Examples of fracture models are provided in Weng et al., Modeling of Hydraulic Fracture Network Propagation in a Naturally Fractured Formation. Paper SPE 140253 presented at the SPE Hydraulic Fracturing Technology Conference and Exhibition held in The Woodlands, Texas, USA, 24-26 January 2011 (“Weng 2011”); Cipolla et al., Integrating Microseismic Mapping and Complex Fracture Modeling to Characterize Hydraulic Fracture Complexity, Paper SPE 140185 presented at the SPE Hydraulic Fracturing Conference and Exhibition, Woodlands, Texas, USA, January 24-26, 2011; and Gu et al., “Hydraulic Fracture Crossing Natural Fracture at Non-Orthogonal Angles, A Criterion, Its Validation and Applications,” Paper SPE 139984 presented at the SPE Hydraulic Fracturing Conference and Exhibition, Woodlands, Texas, January 24-26, 2011 , the contents of which are incorporated herein in full by reference.

[00178] Models can consider the interaction of hydraulic fracturing with natural fractures and / or convolutions, and calculate the detailed structure of the created fracture networks. Models can use a simulation model, such as UFM ™, which can include, a priori, a predetermined set of natural fractures in the formation. Natural cracks can be created based on information obtained from three-dimensional seismic data, studies by a downhole scanner, and / or core characteristics. Natural cracks created can have large uncertainties, which can lead to inaccurate calculations for complex simulation models of cracks. Microseismic data can represent values to confirm and / or verify simulation results.

[00179] Since the microseismic data may not represent the exact plane of the crack, as described above, the predicted “fingerprint” of the model of the crack of a common crack network can be compared with a common microseismic cloud. Model parameters can be adjusted as long as the model results are approximately consistent with the observed microseismic cloud. This verification approach may have some inherent uncertainty, for example, when the imprint of the network of cracks may not be the same as the area indicated by the microseismic cloud. This can occur, for example, when shear failure events can be initiated at some distance from the actual cracks.

[00180] In FIG. 21 is a schematic diagram 2100 showing an example of the progressive propagation of hydraulic fractures 2101 a-f and natural fractures 2102a-f. Detailed models of complex hydraulic fracturing can be used to calculate the translational propagation of many branches of cracks in a complex network of cracks. The formation may initially include many natural fissures 2102a-f.

[00181] As shown in FIG. 21, various relationships 2130a-f may occur between hydraulic fractures 2101 a-f and natural fractures 2102a-f. Relationship 2130a does not show intersections between hydraulic fracture 2101a and natural fracture 2102a. The relationship 2130b shows the suspension and / or sliding between the hydraulic fracture 2101a and the natural fracture 2102a. The relationship 2130c shows a hydraulic fracture 2101c propagating along the natural fracture 2102c and the extension of the natural fracture 2102c. Relation 2130d shows a hydraulic fracture 2101d intersecting a natural fracture 2102c. Relation 2130e shows the intersection between hydraulic fracture 2101e and natural fracture 2102e, with natural fracture 2102e remaining closed. The relationship 2130f shows the intersection between the hydraulic fracture 2101f and the natural fracture 2102f, with a natural crack 2102e having a gyrus hole 2103 that develops after the intersection between the hydraulic fracture 2101f and the natural fracture 2102f.

[00182] In some cases, such as relationship 2130b-2130f, hydraulic fractures 2101 a-f and natural fractures 2102a-f may intersect. The relationship of the hydraulic fractures 2101 a-f and the natural fracture 2102a-f can lead to branching of the crack where the hydraulic fractures 2101a-f and the natural fracture 2102a-f intersect. Intersections 2130a-f may cause hydraulic fractures 2101a-f to open and propagate along natural fractures 2102a-f, and will result in branching and complexity of the fracture.

[00183] In some cases, characterization of natural fissures underground may be difficult, if not impossible. The original set of natural fractures of a discrete fracture network (DFN) can be created stochastically. The stochastic set of DFN can be limited by information obtained from seismic data and studies by a downhole scanner, and / or using geological and geostatistical models.

[00184] In FIG. 22.1 is a schematic diagram 2200.1 depicting DFN 2232 around well 2236. Traces of a statistically generated DFN are shown near well 2236, with statistically generated DFN traces evenly distributed in formation 2234. The traces depict natural fractures 2202 located along formation 2234.

[00185] In FIG. 22.2 is a schematic diagram 2200.2 showing a predicted hydraulic fracture network (HFN) 2236 modeled from a uniformly distributed DFN 2232. Hydraulic fractures 2201 are created from a complex fracture model for the corresponding DFN 2232. FIG. 22.2 also shows microseismic events 2238 (shown as balls on graph 2200.2) collected during fracture processing.

[00186] In the case of FIG. 22.2, the predicted fingerprint of HFN 2236 does not correspond to the microseismic cloud 2240 of microseismic events 2238. Attempts to ensure coincidence can be made by changing the properties of the rock and / or the initial distribution of natural cracks in order to try to reconcile microseismic events 2238. There is no certainty that microseismic events 2238 are actual fracture planes, as they may be shear caused by the sliding of natural fractures 2202 from hydraulic fracture in 2203, as already indicated above.

[00187] Forcing a complex fracture model together with a microseismic cloud 2240 may result in an error. Another approach may be to calculate the artificially created stress field surrounding the created HFN 2236, and to determine the conditions of shear failure in natural cracks and the skeleton of the rock, so that the “imprint” of stress approximately corresponds to microseismic conditions. In addition, from the calculated stress field can be determined natural cracks that are subjected to sliding, and their orientation, which can be compared with the sliding orientation determined from the microseismic moment tensor to obtain a more reliable interpretation.

[00188] In FIG. 23.1 and 23.2 illustrate methods 2300.1, 2300.2 of performing a fracturing operation at a drilling site. In at least one embodiment of the present invention, methods 2300.1, 2300.2 are provided for interpreting microseismicity and using it to verify modeling of a complex fracture by combining stress analysis and rock failure. Each of the methods 2300.1, 2300.2 may include performing a well site stimulation operation 2350, which consists in stimulating the well site by pumping the injected fluid with proppant into the fracture network and / or creating 2352 well site data (e.g., natural crack parameters for natural fractures, injection data and microseismic measurements). Methods 2300.1, 2300.2 can be performed using all or part of the method 1500 of FIG. fifteen.

[00189] Method 2300.1 includes predicting fracture geometry 2354, determining 2356 three-dimensional (3D) stress fields and performing 2358 fracture assessment and verification as compared to microseismic events.

Crack Geometry Prediction

[00190] Prediction of 2354 fracture geometry can be performed, for example, by modeling 2360 fractures, such as natural, hydraulic, and / or complex fractures, based on well site data, and creating a 2362 discrete fracture network from the well site data. The fracture geometry can initially be calculated using a fracture model based on knowledge of geological, geomechanical and fracture processing data. In the case of complex fractures in a formation with natural fractures, the model can be used to predict the planes of a complex fracture, as well as the crack width, fluid pressure, and other parameters associated with the fracture system. Examples of modeling are presented in application for US patent No. 2008/0183451. Prediction can be accomplished using simulations, such as UFM, as described above.

Calculation of a three-dimensional (3D) voltage field

[00191] Three-dimensional (3D) voltage field can be determined 2356 using simulation. For any given hydraulic fracture geometry calculated using a fracture model, a three-dimensional stress field (or region) surrounding hydraulic fractures (see, for example, FIG. 19) can be calculated using simulation 2364, for example, a numerical geomechanical model. For example, a finite element numerical geomechanical code and / or a finite difference code can be used. Such numerical modeling can be time-consuming, because it involves the construction of complex three-dimensional small predicted grids surrounding each of the cracks, and can be with a large amount of computation. Simulation examples are provided in Coatesabeloulis 2009 and Zhang 2007, and may use Itasca 2002 and / or FLAC3D ™ manufactured by ITASCA ™ (see: http://vvwvv.itascacg.com/).

[00192] A three-dimensional stress field can also be determined 2356 using methods with an effective amount of computation based on the Displacement Discontinuity Method (DDM). DDM can be performed using, for example, advanced two-dimensional (2D) DDM and / or 3D DDM. Examples

1. Advanced 2D DDM

[00193] The method may be based on an enhanced 2D DDM 2366, such as described herein. The 2D DDM method was used in complex fracture modeling to calculate the interaction between complex hydraulic fractures (also called the “stress shadowing” effect), and is described in this document and in PCT / US2012 / 063340. Examples of 2D DDM are given in Olson, 2004, and complex fracture models are presented in Weng, 2011 and Wu, 2012.

[00194] In FIG. 3 is a schematic diagram 300 showing a plan view of a complex network of 300 fractures. The crack network 300 is sampled into a plurality of related small elements ELEM i, j. In each ELEM i, j, fluid pressure and width can be determined by solving a system of coupled equations of elasticity and fluid flow. Examples of fluid flow in cracks are given in Hung, 2011. 2D DDM can be used to account for the interaction between adjacent cracks. Examples of 2D methods are given in Crouch and Starfield, 1983.

[00195] The 2D DDM equations relate the normal stresses and shear stresses (σ _n and σ _s ) acting on the element of the crack Elem i with the contributions of the opening and shear discontinuity displacements (Dn and Ds) from all elements of the crack Elem i, j, as shown in equations below. In order to take into account the three-dimensional effect due to the finite crack height, a three-dimensional correction coefficient 2368 is introduced to the influence coefficients Cij and the transformed elastic equations (8.1) and (8.2) 2D DDM, as indicated here. Methods involving three-dimensional effects are described in Olson, 2004.

[00196] A three-dimensional correction factor can be represented as set in equation (12). The introduced three-dimensional correction coefficient can lead to weakening of the interaction between the two elements of the crack with increasing distance, correctly displaying the three-dimensional effect of the final crack height. The advanced 2D DDM method can be tested 2370 in comparison with three-dimensional solutions of finite difference in simple cases to confirm a good approximation. Correction methods are described in Wu, 2012.

[00197] In the method for calculating voltage shadowing, stresses can be calculated 2372 in the center of each element of the hydraulic fracturing network. Similar equations can be applied to calculate the stress field in a rock from hydraulic fracturing elements. By calculating the normal stresses and shear stresses acting on part of a discrete network of cracks, such as previously existing natural cracks and / or points in the rock skeleton, shear failure conditions can be estimated.

2. 3D DDM

[00198] In some cases, the 2D DDM method may be limited to estimate average stresses in the horizontal plane (assuming the cracks are vertical). The method may also be based on 3D DDM 2374.

[00199] For a given hydraulic fracturing network, the network can be discretized into related small rectangular (or polygonal) elements. For any given rectangular element subjected to displacement displacements between its two surfaces represented by D _x , D _y , and D _z induced by stresses in the rock at any point (x, y, z), can be calculated using the 3D DDM solution.

[00200] FIG. 24 is a diagram 2400 of a local coordinate system x, y, z for one of the rectangular elements 2470 located along the x-y plane. An artificially created field of displacements and stresses can be expressed as:

where a and b are half the lengths of the edges of the rectangle, and

For any given observation point P (x, y, z) in three-dimensional space, 2376 artificially induced stresses at point P can be calculated by applying stresses from all elements of the crack and by applying the corresponding coordinate transformation. Methods involving 3D DDM are presented in Crouch, S.L. and Starfield, A.M. (1990), Boundary Element Methods in Solid Mechanics, Unwin Hyman, London, the entire contents of which are incorporated herein by reference.

Assessment and verification of fracture in comparison with microseismic events

[00201] Assessment and verification of fracture can be performed 2358 in comparison with microseismic events. Stresses can be calculated at various locations in three-dimensional space for various analysis purposes. Stresses can be created by applying stress to fixed points in three-dimensional space to plot 2378 stress components and / or to create stresses 2380 along observed microseismic locations. The following are lists of such applications, but the method is not limited to these applications.

1. Three-dimensional voltage circuit

[00202] The calculation of stress can be applied to fixed points in three-dimensional space to create graphs of 2378 contours of various stress components or graphs of derivatives of stress fracture parameters. Three-dimensional contour plots give an indication of where stress concentrations exist or where the rock most likely causes shear failure, which can be correlated with the locations of the microseismic event or the density of the event.

2. Stresses in these natural cracks

[00203] Stresses can be calculated 2380 on natural cracks or along natural cracks. Shear stress or other relevant indicators related to fracture conditions can be calculated. In addition, they can be compared 2382 with microseismic locations and attributes of the moment tensor to determine whether the expected parameters of the natural crack are consistent with microseismic observations, and whether any adjustment of the parameters of the crack is performed.

3. Stresses at the locations of the microseismic event

[00204] Voltages can be calculated 2384 at the observed locations of the microseismic event. Based on the calculated stresses, the probability of shear slip or the state of the boundary can be estimated. Since slip slip occurs at the location of the microseismic event, matching or mismatching the forecast model with reality can provide a measure of the correctness of the model results.

[00205] No matter where the stresses are calculated in space, a comparison of a predicted predisposition to slip during shear or fracture can be made with observations of microseismicity. If the predicted model does not agree well with microseismic observations, modifications in the system of natural cracks or other rock parameters can be used and return to modeling until adequate agreement is obtained. After adjusting 2388, the wellsite data can be modified in 2352, and the method is repeated. After checking, the crack parameters can be corrected 2388 based on a comparison. Intensification operation 2390 can also be adjusted based on crack parameters.

[00206] The method provides a direct relationship between the observed microseismicity and the stress field expected from artificially generated hydraulic fractures. When doing this, the initial homogeneous stress distribution in the rock formation, changes in natural fractures and their attributes, and their distribution in the formation, main shifts with different properties, etc. can be taken into account. This can reduce uncertainties in the analysis and interpretation of microseismic events, and can provide more deterministic confirmation / verification of fracture geometry from a fracture model.

[00207] The verification process may also provide a better study of the mechanisms and parameters of the microseismic source, which provides the basis for improved consideration of the installation or microseismic measurement scheme in subsequent treatments of the same well, or in future treatments of neighboring wells.

[00208] In FIG. 23.2, another method 2300.2 for performing a tear operation is presented. In this embodiment, the method includes performing 2350 stimulation operations, including stimulating the well section by pumping injected fluid with proppant into the fracture network and creating 2352 well site data (for example, natural crack parameters for natural fractures, injection data and microseismic measurements) as in FIG. 23.1. Method 2300.2 also includes modeling 2375 hydraulic fractures based on well site data and determining hydraulic fracture geometry for hydraulic fractures, creating 2377 hydraulic fracture stress fields using a geomechanical model (e.g., 2D or 3D DDM), determining 2379 shear fracture parameters containing a curve fracture and stress state near the fracture network (for example, along natural fractures, hydraulic fractures, and / or rocks), determining 2381 fracture locations at shifting the fracture network from the fracture curve and the stress state, checking 2383 hydraulic fracture geometry by comparing microseismic measurements with a simulated fracture network and / or an activated discrete fracture network, adjusting the 2385 discrete fracture network based on comparison, and correcting 2387 intensification operations based on comparison.

[00209] The method, in whole or in part, can be performed in any order and, if necessary, repeated.

III. INTERPRETATION OF MICROSEISMICITY WITH THE SEISMIC MOMENT

[00210] The present invention also relates to methods for performing fracture operations, including modeling hydraulic fractures and discrete fracture networks, determining shear and tensile components of a hydraulic fracture network, and determining a simulated moment density from shear and tensile components. A discrete network of cracks can be verified by comparing the simulated moment density with the actual moment density determined from the wellsite data. This information can be used to predict proppant placement, production and formation pressure.

[00211] The methods described herein can be used, for example, to extract and evaluate attributes or properties of a network of hydraulic (artificially formed) fractures from microseismic activity created during stimulation treatments in unconventional formations. The methods may not be limited to a particular formation, type of well and / or type of group used to collect microseismic signals.

[00212] The evidence of microseismicity of fracture complexity has led to the recent development of modeling tools to simulate the growth of a fracture network. Such complex fracture models may rely on verifying microseismic location information, although the mechanics of the microseismic source can also provide additional model validation. The simulated geomechanical deformation associated with the intensification of hydraulic fracturing for complex hydraulic fracturing contains information that can be compared with the observed microseismic deformation. The division of the simulated stresses into the components of shear and longitudinal strain can provide a relative comparison of the corresponding displacement mode with the observed total microseismic moments.

[00213] A number of fractures with simple geometry were investigated to illustrate the deformation modes of simulated fracture displacements. A sequence of actions is also described where the input modeling parameters are changed to match both the fingerprint and the microseismic deformation, which then leads to an assessment of the entire volume of the network of cracks and the placement of the proppant. Thus, an effectively stimulated volume can be estimated and used as input to simulate a formation for studying well productivity and draining a formation. Embodiments of the present invention may include one or more methods, computing devices, non-volatile computer readable media, and systems for modeling a microseismic fracture network (MFN).

[00214] A study of the nature and degree of complexity of hydraulic fracturing may be useful for the economic development of unconventional sources. During fracture treatments, the geomechanical interaction between fractures and natural fractures can affect the complexity of the resulting fracture network. Examples of hydraulic fracturing methods are described in the following documents: Mayerhofer et al., Integrating of Microseismic Fracture Mapping Results with Numerical Fracture Network Production Modeling in the Barnett Shale, Society of Petroleum Engineers (SPE) 102103, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24-24 September 2006; Mayerhofer et al., What is Stimulated Reservoir Volume (SRV) ?, SPE 119890 presented at the SPE Shale Gas Production Conference, Fort Worth, Texas, November 16-18, 2008; Warpinski et al .. Stimulating Unconventional Reservoirs: Maximizing Network Growth while Optimizing Fracture Conductivity. SPE 114173 presented at the SPE Unconventional Reservoirs Conference, Keystone, Colorado, February 10-12, 2008; and Cipolla et al .. The Relationship between Fracture Complexity, Reservoir Properties, and Fracture Treatment Design, SPE 115769 presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, 21-24 September 2008.

[00215] The complex propagation of hydraulic fracturing can be interpreted based on microseismic measurements, for example, from unconventional formations and low permeability formations. Examples of complex fracturing methods are described in the following documents: Maxwell et al., Microseismic Imaging of Hydraulic Fracture Complexity in the Barnett Shale, SPE 77440 presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, September 29-0ctober 2, 2002 ; Fisher et al., Integrating Fracture Mapping Technologies to Optimize Stimulations in the Barnett Shale, 77411 presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, September 29-0ctober 2, 2002; Cipolla et al., Effect of Well Placement on Production and Frac Design in a Mature Tight Gas Field, 95337 presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, October 9-12, 2005; and Warpinski et al., Stimulating Unconventional Reservoirs: Maximizing Network Growth while Optimizing Fracture Conductivity, SPE 114173 presented at the SPE Unconventional Reservoirs Conference, Keystone, Colorado, February 10-12, 2008.

[00216] Design decisions for stimulation and completion may be performed based on the expected fracture complexity, which may be an indicator for the ultimate well productivity. Geomechanical analysis tools can be used to model the fracture network obtained from the intensification of hydraulic fracturing of a previously existing discrete fracture network (DFN). In some cases, there may be problems in the differences between a small degree of crack complexity and a simple planar crack growth. An indicator that can influence the creation of complex fracture systems is the presence and distribution of natural fractures. An example of complex fractures is shown in Cipolla et al., Integrating Microseismic Mapping and Complex Fracture Modeling to Characterize Fracture Complexity, SPE 140185 presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, February 24-26, 2011. DFN models were used for modeling production in naturally fractured formations, as shown, for example, in the following documents: Dershowitz et al., A Workflow for Integrated Barnett Shale Reservoir Modeling and Simulation, SPE 122934 presented at the SPE Latin American and Caribbean Petroleum Engineering Conference. Cartagena, Columbia. May 31-June 3, 2009; Quiet al., Applying Curvature and Fracture Analysis to the Placement of Horizontal Wells: Example from the Mabee (San Adres) Reservoir, Texas, SPE 70010 presented at the SPE Permian Basin Oil and Gas Recovery Conference, Midland, Texas 15-17 May, 2001; and Will et al., Integration of Seismic Anisotropy and Reservoir-Performance Data for Characterization of Naturally Fractured Reservoirs Using Discrete-Feature-Network Models, SPE 84412 presented at the SPE Annual Technical Conference and Exhibition, Denver, Colorado, 5-8 October 2003 These methods, together with logging approaches (see, for example, Bratton et al., Rock Strength Parameters from Annular Pressure While Drilling and Dipole Sonic Dispersion Analysis, Presented at the SPWLA 45th Annual Logging Symposium, Noordwijk, The Netherlands, 6 -9 June 2004) may be descriptive. Some of these methods can be used to characterize the structure of a natural network of fractures in order to continue observations in the well along the formation.

[00217] Some models have also been developed to quantify the propagation of a complex network of hydraulic fractures, for example, in a formation with previously defined, deterministic or stochastic natural fractures in it. Examples of complex fracture models are described in the following documents: Sahimi, M., New Models For Natural And Hydraulic Fracturing On Heterogeneous Rock, SPE 29648 presented at the SPE Western Regional Meeting, Bakersfield, California (1995); Fomin et al., Advances In Mathematical Modeling Of Hydraulic Stimulation Of A Subterranean Fractured Reservoir, Proc. SPIE 5831: 148-154 (2005); Napier et al., Comparison Of Numerical And Physical Models For Understanding Shear Fracture Process, Pure Appl. Geophys, 163; 1153-1174 (2006); Tezuka et al., Fractured Reservoir Characterization Incorporating Microseismic Monitoring And Pressure Analysis During Massive Hydraulic Injection, IPTC. 12,391 presented at the International Petroleum Technology Conference, Kuala Lumpur-, Malaysia (2008); Olsen et al., Modeling Simultaneous Growth Of Multiple Hydraulic Fractures And Their Interaction With Natural Fractures, SPE 119739 presented at the Hydraulic Fracturing Technology Conference, The Woodlands, Texas (2009); and Xu et al .. Characterization of Hydraulically Induced Shale Fracture Network Using an Analytical / Semi- Analytical Model, SPE 124697 presented at the SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October 2009; and Weng et al., Modeling of Hydraulic Fracture Propagation in a Naturally Fractured Formation, SPE 140253 presented at the SPE Hydraulic Fracturing Technology Conference, Woodlands, Texas, USA, January 24-26, 2011. In some models, microseismic activity can be used for containing cracking process.

Introduction

[00218] In FIG. 25.1-25.4 illustrate simplified, schematic views of an oil field 2500 having subterranean formations 2502 containing a formation 2504 in accordance with embodiments of various technologies and methods described herein. In FIG. 25.1 illustrates an exploration operation performed using a borehole measuring instrument, such as seismic station 2506.1, to measure the properties of an underground formation. An exploration operation is a seismic exploration operation for performing sound vibrations. In FIG. 25.1, some such sound vibrations, sound vibrations 2512 created by source 2510, are reflected by horizons 2514 in the bulk of rock 2516. A number of sound vibrations are received by sensors, such as geophonic receiver 2518 located on the earth's surface. The obtained data 2520 is presented as input to the computer 2522.1 of the seismic station 2506.1, and, in response to the input, the computer 2522.1 creates the output seismic data 2524. The output seismic data can be stored, transmitted or further processed, if necessary, for example, by preliminary processing data. A surface mount 2534 is also depicted as having a microseismic fracture operation system 2550, as will be described later.

[00219] In FIG. 25.2 illustrates a drilling operation performed using a drilling tool 2506.2 suspended from a rig 2528 and pushed into an underground formation 2502 to form a well 2536. A mud reservoir 2530 is used to move the drilling fluid to the drilling tool along a pressure line 2532 to circulate the mud through drilling tool, and then uphole 2536 and back to the surface. The drilling fluid may then be filtered and returned to the drilling fluid reservoir. The circulation system can be used to store, control, or filter leaking drilling fluid. A drilling tool advances into subterranean formation 2502 to reach formation 2504. Each well may be targeted to one or more layers. The boring tool is configured to measure properties in a borehole environment using logging along with a boring tool. Logging along with the drilling tool can also be performed with the possibility of sampling 2533 core, as shown.

[00220] Computer equipment may be located at various locations in the oil field 2500 (eg, mounting 2534 on the surface) and / or remote locations. The surface mount 2534 can be used to communicate with a drilling tool and / or off-site operations, as well as with other sensors on the surface or in the well. The surface mount 2534 has the ability to communicate with the boring tool to send commands to the boring tool and to receive data from it. A surface mount 2534 can also collect data generated during a drilling operation, and generates output 2535 that can then be stored or transmitted.

[00221] Sensors (S), such as measuring instruments, may be placed around the oil field 2500 to collect data regarding various operations mentioned in the above description. As shown, the sensor (S) is installed at one or more locations in the drilling tool and / or installation 2528 for measuring drilling parameters, such as weight on the bit, torque on the bit, pressure, temperature, flow rates, compositions, rotation speed and / or other parameters of fishing operations. Sensors (S) can also be installed at one or more locations in the circulation system.

[00222] Drill tool 2506.2 may include bottom hole assembly (BHA) equipment (not shown) near the drill bit (for example, several drill pipe lengths from the drill bit). The equipment of the bottom of the drill string includes the ability to measure, process and store information, as well as communication with the installation of 2534 on the surface. The bottom hole equipment further includes drill pipes to perform various other measurement functions.

[00223] The equipment of the bottom of the drill string may contain a communication unit that communicates with the installation 2534 on the surface. The communication unit is configured to send and receive signals from the surface using a communication channel, such as mud pulsation telemetry, electromagnetic telemetry, or drill string wire communication. The communication unit may include, for example, a transmitter that generates a signal, such as an audio or electromagnetic signal, that represents drilling parameters. One skilled in the art will appreciate that a variety of telemetry systems, such as a wireline drill string system, electromagnetic, or other known telemetry systems, can be used.

[00224] A well may be drilled in accordance with a drilling plan that is approved prior to drilling. In terms of drilling, equipment, pressures, trajectories and / or other parameters that determine the drilling process for the drilling site can be installed. A drilling operation may then be performed in accordance with the drilling plan. However, as information is collected, the drilling operation may deviate from the drilling plan. In addition, when a drilling operation or other operation is performed, surface conditions may vary. The geological environment model can also provide adjustments as new information is collected.

[00225] Data collected by sensors (S) can be collected using a surface mount 2534 and / or other data collection sources for analysis or other processing. Data collected by sensors (S) can be used individually or in combination with other data. Data may be collected in one or more databases and / or transmitted to or from the site. The data may be retrospective data, real-time data, or a combination thereof. Real-time data can be used in real time or saved for later use. Data can also be combined with historical data or other input data for further analysis. Data can be stored in separate databases, or combined in one database.

[00226] The surface mount 2534 may include a transceiver 2537 to provide communication between the surface mount 2534 and various portions of the oilfield 2500 or other locations. A surface mount 2534 can also be provided or functionally coupled to one or more control devices (not shown) for actuating mechanisms in an oil field 2500. A surface mount 2534 can then send control signals to an oil field 2500 in response to the received data. A surface mount 2534 may receive commands through a transceiver 2537 or may itself execute commands to a control device. A processor may be provided for analyzing data (locally or remotely), executing a solution, and / or actuating a control device. Thus, the 2500 oil field can be selectively adjusted based on the collected data. This method can be used to optimize part of field operations, such as drilling control, bit weight, pumping speeds or other parameters. These adjustments can be made automatically based on a computer protocol, and / or manually, by an operator. In some cases, well plans may be adjusted to select optimal operating conditions, or to avoid problems. A surface mount 2534 is also depicted as having a microseismic fracture operation system 2550, as will be described later.

[00227] In FIG. 25.3 shows the wireline work in the well performed using a tool 2506.3, lowered into the well on a cable suspended on the installation 2528, and in the wellbore 2536 of FIG. 25.2. Tool 2506.3, lowered into the well on a cable, is configured to be put into operation in wellbore 2536 to create well logs, perform downhole tests and / or sample collection. Tool 2506.3, lowered into the well on a cable, can be used to create another method and apparatus for performing a seismic survey. An instrument 2506.3, lowered into a well on a cable, may, for example, have a source 2544 of radioactive, electrical, or sound energy that sends and / or receives electrical signals to the surrounding rock strata 2502 and fluids therein.

[00228] A tool 2506.3, lowered into a well on a cable, may be operatively connected, for example, to geophones 2518 and computer 2522.1 of the seismic station 2506.1 of FIG. 25.1. Tool 2506.3, lowered into the well on a cable, can also provide data to the installation 2534 on the surface. The surface mount 2534 may also collect data generated during wireline drilling in the well, and may generate output data 2535, which may then be stored or transmitted. Tool 2506.3, lowered into the well on a cable, can be installed at various depths in well bore 2536 to provide the surveyor with other information related to the subterranean formation 2502.

[00229] Sensors (S), such as measuring instruments, may be placed around the oil field 2500 to collect data regarding various field operations mentioned in the above description. As shown, the sensor S is installed in the tool 2506.3, lowered into the well on a cable, for measuring downhole parameters, which are associated, for example, with porosity, permeability, composition of the fluid and / or other parameters of field operations.

[00230] In FIG. 25.4 shows the production operation performed using tooling 2506.3, driven from an industrial installation or fountain 2529 and in the completed well 2536 to extract fluid from the wellbore into equipment 2542 on the surface. Fluid flows from reservoir 2504 through perforations in the casing (not shown) and into tooling 2506.4 into well 2536 and into equipment 2542 at the surface through a collection network 2546.

[00231] Sensors (S), such as gauges, may be placed around the oil field 2500 to collect data regarding various field operations mentioned in the above description. As shown, the sensor (S) can be installed in tooling 2506.4 or related equipment such as fountain fittings 2529, collection network 2546, surface equipment 2542, and / or production equipment to measure fluid parameters, such as fluid composition , costs, pressures, temperatures and / or other parameters of fishing operations.

[00232] Production may also include injection wells for additional recovery. One or more acquisition systems may be operatively coupled to one or more drilling sites for selectively collecting downhole fluid from the drilling site (s).

[00233] Although in FIG. 25.2-25.4 shows the means used to measure the properties of an oil field, it should be clear that the means can be used in connection with operations not in the oil field, for example, gas fields, mines, aquifers, storage or other underground equipment. In addition, although certain means of data collection are depicted, it should be understood that a variety of measuring tools capable of sensing parameters, such as seismic total travel time, density, resistivity, flow rate, etc., of an underground formation and / or its geological formations. A variety of sensors (S) may be located at various positions along the wellbore and / or monitoring means to collect and / or monitor the necessary data. Other data sources from off-site locations may also be provided.

[00234] The field configurations of FIG. 25.1-25.4 are intended to provide a brief description of an example field used with oilfield application frameworks. Part or all of the 2500 oil field may be located on land, water, and / or the sea. In addition, although a single field is depicted, measured at one location, oilfield applications can be used with any combination of one or more oil fields, one or more processing facilities, and one or more drilling sites.

[00235] In FIG. 25.5 shows a microseismic fracture operation system 2550. As shown, a microseismic crack operation system 2550 includes a microseismic tool 2552, a fracture tool 2554, a downhole tool 2556, an optimizer 2558, and an oilfield tool 2560. A microseismic tool 2552 can be used to perform Ant-tracking. Burst tool 2554 may be used to perform burst extraction. Downhole tool 2556 can be used to create fracture attributes, such as permeability. Optimizer 2558 can be used to perform dynamic modeling and adjust gap attributes based on dynamic modeling. An oilfield tool 2560 may be used to obtain well site data, for example, from sensor S of FIG. 25.1-25.4 and data manipulation for use by other tools of the 2550 microseismic fracture operation system. Each of these functions is described below.

[00236] In FIG. 26 is a schematic view, partially in cross-section, of oil fields 2600 having data collection means 2602.1, 2602.2, 2602.3 and 2602.4 located at various locations along the 2600 oil field for collecting data from the underground formation 2604 in accordance with embodiments of various technologies and methods described in this document. The data collection tools 2602.1-2602.4 may be the same as the data collection tools 2506.1-2506.4 of FIG. 25.1-25.4, respectively, or others not shown. As shown, data collection means 2602.1-2602.4 create graphs of data or measurements 2608.1-2608.4, respectively. Data graphs are shown along the 2600 oil field to show data created through various operations.

[00237] Data graphs 2608.1-2608.3 are examples of static data graphs that can be created using data collection means 2602.1-2602.3 respectively, however, it should be understood that data graphs 2608.1-2608.3 can also be real-time data graphs . These measurements can be analyzed to better determine the properties of the formation (s) and / or to determine the accuracy of the measurements and / or to check for errors. Graphs of each of the corresponding measurements can be arranged and scaled for comparison and confirmation of properties.

[00238] The static data graph 2608.1 is a seismic two-way response over a period of time. Static graph 2608.2 represents core sample data measured from a core sample of formation 2604. A core sample can be used to obtain data, such as a graph of density, porosity, permeability, or some other physical property of the core sample along the length of the core. Density and viscosity tests can be performed on core fluids at various pressures and temperatures. Static data graph 2608.3 is a log curve that can represent resistivity or other formation measurements at various depths.

[00239] A performance curve or graph 2608.4 is a graph of dynamic fluid flow rate data over time. The performance drop curve can represent flow rates as a function of time. When the fluid flows through the wellbore, measurements are made of the properties of the fluid, such as flow rates, pressures, composition, and the like.

[00240] Other data, such as historical data, user inputs, economic information, and / or other measurement data or other parameters of interest, may also be collected. As indicated above, static and dynamic measurements can be analyzed and used to create models of the underground formation to determine its characteristics. Similar measurements can also be used to measure changes in aspects of the formation over time.

[00241] The underground structure 2604 has many geological formations 2606.1-2606.4. As shown, this structure has several formations or formations, including shale stratum 2606.1, carbonate stratum 2606.2, shale stratum 2606.3 and sand stratum 2606.4. Dislocation 2607 passes through a shale formation 2606.1 and a carbonate formation 2606.2. Means of collecting static data are configured to measure and detect formation characteristics.

[00242] Although a particular subterranean formation with specific geological structures is depicted, it should be understood that the oil field 2600 may contain a variety of geological structures and / or formations, sometimes of extreme complexity. In some locations, for example, below the aquifer, the fluid may occupy the pore spaces of the formation. Each of the measuring instruments can be used to measure formation properties and / or geological features. Although each data acquisition tool is shown to be located at a specific location in an oil field 2600, it should be understood that one or more types of measurements can be performed at one or more locations in one or more deposits or other locations for comparison and / or analysis.

[00243] Data collected from various sources, such as the data collection means of FIG. 26 can then be processed and / or evaluated. The seismic data displayed in the static data graph 2608.1 from the data collection means 2602.1 are used by the geophysicist to determine the characteristics of the underground formation and features. The core data shown on the static curve 2608.2 and / or the log data from the log 2608.3 can be used by a geologist to determine various characteristics of the underground formation. Production data from schedule 2608.4 can be used by a field engineer to determine fluid flow characteristics in a formation. Data analyzed by a geologist, geophysicist, and field engineer can be analyzed using a modeling method.

[00244] In FIG. 27 illustrates an oil field 2700 of oilfield operations in accordance with the embodiments of various technologies and methods described herein. As shown, the oil field has a number of drilling sites 2702 functionally coupled to the central processing unit 2754. The oil field configuration of FIG. 27 does not limit the scope of the oil field application system. Part or all of the oil field may be on land and / or sea. In addition, although one oil field is depicted with one processing device and multiple drilling sites, any combination of one or more oil fields, one or more processing devices and one or more drilling sites may exist.

[00245] Each well 2702 has equipment that forms a wellbore 2736 in a geological environment. Wellbores pass through subterranean formations 2706 containing formations 2704. These formations 2704 contain fluids such as hydrocarbons. Drilling rigs extract fluid from the formations and pass it to processing devices via surface networks 2744. The surface networks 2744 have pipelines and control mechanisms for controlling the flow of fluids from the wellsite to processing devices 2754.

Characterization of a microseismic source

[00246] Outside of the hypocentric location and temporal connection with the injection program, there are two aspects of microseismic source deformation that may be relevant to understanding the geomechanical deformation of the fracture network. The first is a scalar seismic moment (Mo), which connects the power of a microseismic source with a measure of coseismic voltage through the product of slip zone (A) and displacement (d):

where μ is the shear modulus.

[00247] A measure of the power value of a microseismic source can be estimated using a moment value (Mw) (see, for example, Hanks and Kanamori, A Moment Magnitude Scale, Journal of Geophysical Research, Vol. 84. Issue B5, pp. 2348-50 1979 (here referred to as “Hanks and Kanamori”)):

Displacement or slip stress is an attribute that can be directly estimated using numerical geomechanical modeling, so that equivalent moments or moment magnitude can be estimated from the simulation.

[00248] A second aspect of the microseismic source is the source focal mechanism. The focal mechanism refers to the orientation of the dislocation plane, which slides, and can be inferred from the solution of the moment tensor, which can be estimated by analyzing the observed forms of the seismic signal. Focal mechanisms can be used to assess the orientation of a microseismic source crack using a variety of methods. In particular, moment tensor inversion methods can also be used to evaluate the slip mode of a microseismic source and whether shear, opening occurs under tension or a combination of them (see, for example, Hanks and Kanamori, 1979). For a given fracture segment orientation in DFN, a geomechanical simulation can also calculate a comparable slip mode.

[00249] The characterization of a microseismic source can thus represent strain characteristics compatible with aspects of geomechanical modeling of the stress of a fracture network. The recorded microseismicity is a component of the complete deformation of the fracture network, although aseismic deformation can also occur, and may represent a component of the fracture stresses. After the microseismicity mode is determined, the corresponding geomechanical fracture mode can be quantitatively compared with numerical simulation.

Grid network deformation modes

[00250] In FIG. 28 and 29.1-35.2 show various cases of fracture geometry depicting shear and tensile strain of a hydraulic fracture. In each drawing, the gap 2923, 2923 ’is shown in light gray, and the shear and tensile stresses applied to it are depicted in a darker tone. To illustrate the relative deformation modes that occur due to hydraulic fracturing processing, a series of fractures with simple geometry can be modeled. For each of the geometries, subsequent fracture stresses can be estimated and designed for shear and tensile components. Stresses can be estimated from a fracture mechanics model that maintains an injection mass balance to create a sufficient volume of fracture to contain the volume of fluid injected by creating hydraulic fractures that interact with pre-existing fractures.

[00251] During the extension of the crack, the associated geomechanical stresses are calculated, which may include displacements both in tension and in shear, depending on the tensile characteristics of the network of cracks. Throughout the rest of the description, deformation may focus on the hydraulic fracture network itself. Elastic changes in the rock around the expanding fracture network and any artificially associated displacements of previously existing fractures that can be separated from the hydraulic fracture can be taken into account or not taken into account.

[00252] In FIG. 28 depicts a conceptualized increase in hydraulic fracture 2823 over time. Stage 1) depicts the earliest growth period of hydraulic fracture 2823 outward from injection point 2817 toward the previously existing fracture 2819. Stage 2) depicts hydraulic fracture 2823 ’as it grows in the previously existing fracture 2819, filled with fluid and starting to stretch. Step 3) shows a 2823 ”hydraulic fracture as it continues to grow, creating a new 2823.1 fracture at the end of the 2823” existing hydraulic fracture.

[00253] The mode of opening gaps 2823, 2823 ’, 2823”, 2823.1 at different stages leads to tensile opening 2825, and also causes localized shear 2827. These segments of the gap have a potential combination of tensile and shear displacements, as shown in table 5:

Table 5

Tensile and hydraulic fracture displacement with time

Stage σ τ one) X - 2) X X 3) X X

[00254] In FIG. 29.1-35.2 depict various examples of the creation of hydraulic fracturing for the cases described in table 6:

Table 6

Shear and tensile deformation for various cases

Case No. Full shift
(m) Full Stretch (m) Percent Shift Max. shift
(m) Max. stretching
(m) Percentage Max shear 1 - There are no gaps 0 0.5483 0,0% 0 3.11E-03 0,0% 2-One asymmetric 0,078 0.5342 14.6% 2,13E-03 3.39E-03 62.9% 3-one symmetrical 0,1051 0.4469 23.5% 1,52E-03 3.77E-03 40.4% 4 multiple symmetrical 0.1152 0.4643 24.8% 2,09E-03 3.82E-03 54.7% 5 - Long symmetrical 0.1286 0.573 22.4% 1,35E-03 3.98E-03 33.9% 6 - Long asymmetric 0.1119 0.5412 20.7% 1,61E-03 3.64E-03 44.3% 7 - Short symmetrical 0,0806 0.5411 14.9% 1,19E-03 3,52E-03 33.8%

Table 6 summarizes the types of total deformation, as well as the localized maximum deformation (which can be considered as a localized shift).

[00255] Each case 1-7 in table 6 is depicted in a pair of drawings including both a shear drawing τ and a tensile drawing σ. In FIG. 29.1-35.1 depict the complete shift τ for the discontinuity 2923, constructed along X (m) (x axis) depending on Y (m) (y axis). In FIG. Figures 29.2-35.2 show the total tensile stress σ for a 2923 ’discontinuity constructed along X (m) (x axis) as a function of total Y (m) (y axis). Each of cases 1-7 is depicted in more detail below:

Case 1: No Previous Gaps

[00256] In this simplest scenario, a flat hydraulic fracture 2923 was created (Fig. 29.1), which deforms to a hydraulic fracture 2923 ’due to tensile opening in the absence of associated shear deformation (Fig. 29.2). In each of these scenarios, at x = 0, there is an injection point, from which the hydraulic fracture 2923 increases from east to west under tension. Although tensile rupture creates fractions of shear stress in the rock near the top of the rupture rupture, the opposite sides of the rupture experience relative displacement when opening, if the rupture does not meet a previously existing crack in the desired direction of sliding. In this example, in the absence of previously existing cracks, a hydraulic fracture of 2923 ’in tension is created with opening exclusively in tension and without shear deformations.

[00257] In the following cases, 2-4, the previously existing hydraulic fractures 2923, 2923 ’from east to west are used in addition to the previously existing fractures 2919.1-.4, 2919.1-.4’ from north to south to create a specific geometry. In this case, shear deformations are created along the hydraulic fracture branch 2923, and are more localized along the short part of the “fracture” of the previously existing fracture 2919.1-.4, 2919. 1-.4 ’. A small amount of shear is caused along the initial hydraulic fracture 2923 due to the asymmetry of the intersecting previously existing fracture 2919 and the associated elongation of the segment, leading to a branching in the form of a fracture. As shown in Table 6 above, the shear strain along the kink can be the largest localized shear found for the scenario, and the total shear can be relatively small.

Case 2: Single asymmetric pre-existing crack

[00258] In FIG. 30.1 shows a simulated fracture shear 2923. In FIG. 30.2 shows a simulated tensile strain associated with hydraulic fracture 2923 ’tensile. The horizontal portion formed by the original hydraulic fracture 2923 represents a simulated fracture network. Parts 2919.1 extending beyond hydraulic fracture 2923 are presented as shear displacements in FIG. 30.1, and the parts 2919.1 ’extending beyond the hydraulic fracture 2923’ are the tensile displacements of FIG. 30.2.

[00259] In this scenario, a single, flat tensile fracture 2923 in accordance with FIG. 29.1, which ultimately grows into the previously existing fracture 2919.1 from north to south in FIG. 30.1. Here, the pre-existing fracture is asymmetric with respect to the injection point and hydraulic fracture, leading to one branched fracture network (Figs. 30.1 and 30.2).

[00260] In FIG. 30.1 shows shear displacement, and FIG. 30.2 shows the tensile displacement associated with the asymmetric intersecting fracture 2919.1, 2919.1 ’around the hydraulic fracture 2923, 2923’. It should be noted that the previously existing hydraulic fractures 2923, 2923 ’are deliberately positioned to create a symmetrical fracture 2923.2 around the injection point x = 0.

Case 3: Single Symmetric Pre-existing Fracture

[00261] In FIG. 31.1 shows shear offsets, and in FIG. 31.2 shows tensile displacements associated with a symmetrical intersecting discontinuity. Here, a single flat hydraulic fracture 2923 intersects the symmetrical fracture 2919.2, creating a hydraulic fracture with two branches (Fig. 31.1). The shift develops along the intersecting gap 2923 ’and along each of the branching gaps 2919.2’.

[00262] In contrast to the asymmetric case of FIG. 30.1, the shear develops along the entire length, leading to a more extended shear structure (see Table 6). Another difference from the asymmetric case is the absence of shear along the initial hydraulic fracture of 2923 ’.

Case 4: Multiple Symmetrical Pre-existing Cracks

[00263] In FIG. 32.1 shows shear offsets, and in FIG. 32.2 shows the tensile displacements associated with multiple symmetrical intersecting discontinuities 2923, 2923 ’. Changing a single symmetrical gap 2919.2, 2919.2 ’with two branches (case 3) includes an additional previously existing gap 2919.2.1, 2919.2.1’ parallel to the first one, which creates additional branching (Figs. 32.1 and 32.2). A deformation scheme similar to case 2 was discovered with an additional shift along the fracture structure. The enlarged branches of the discontinuity network rupture lead to an additional increase in total shifts (table 5).

[00264] For the following cases 5-7, additional east-west gaps are not included in addition to north-south gaps. Shear deformation occurs at a previously existing gap from north to south.

Case 5: Long Symmetrical Gap

[00265] In FIG. 33.1 shows displacements 2919.3 in shear, and in FIG. 33.2 shows displacements 2919.3 ’in tension associated with a long symmetrical intersecting gap 2923, 2923’. In this scenario, a relatively long, intersecting gap is intensified (Figs. 33.1 and 33.2).

Case 6: Long asymmetric gap

[00266] In FIG. 34.1 shows displacements 2919.4 in shear, and in FIG. 34.2 shows the displacements 2919.4 ’in tension associated with the long asymmetric intersecting fracture 2923. With the previously existing fracture 2923 asymmetric with respect to the initial hydraulic fracture, the additional fracture branch 2937 grows from the proximal end of the fracture (Fig. 34.1).

[00267] The shift is created at both intersecting 2923 and branching break 2919.4. A small amount of shear was created at the 2923 ’central hydraulic fracture, similar to case 2. It should be noted that the 2919.4’, 2937 ’branch fracture around the 2923’ hydraulic fracture is at an angle due to the shadowing of the stress associated with the shift along the intersecting fracture.

Case 7: Short Symmetrical Gap

[00268] In FIG. 35.1 shows the displacements 2919.5, 2937.1 in shear, and in FIG. 35.2 shows displacements 2919.5 ’, 2937.1’ in tension associated with a short symmetrical intersecting gap 2923, 2923 ’. In this scenario, a short symmetrical gap 2923 is intensified (Figs. 35.1 and 35.2). Again, two branching breaks 2923.5, 2937.1 are created from the orthogonal intersecting break 2923, and two branching breaks 2923.5 ’, 2937.1’ are created from the orthogonal intersecting break 2923 ’, with shift components along both. As shown in table 6, a smaller total shift is created compared to the scenario (No. 5) of a longer gap, similar to the comparison between cases 2 and 3.

[00269] Based on these cases, it can be established that: (1) the more complex the fracture network and the increased density of previously existing fractures, the greater the shear strain; (2) longer intersecting breaks can give a greater shift; (3) asymmetric discontinuities can give less total shear, and more localized shear; (4) asymmetric fractures can produce a small amount of shear at the initial hydraulic fracture in tension; and (5) shear strain itself may not be a satisfactory substitute for tensile strain. In view of these and other considerations, methods for performing fracture operations that take into account the geometry of the fracture and the shear and tensile strain of the fracture network can be created.

Microseismic confirmation

[00270] The simulated geomechanical deformation associated with the intensification of the hydraulic fracture of a complex hydraulic fracture creates a context for the interpretation of microseismic deformation. The division of the simulated stresses into the components of shear and tension (longitudinal) provides a relative comparison of the corresponding displacement mode with the observed total microseismic moments. The input modeling parameters can be changed to match both the fingerprint and microseismic deformation, which then leads to an assessment of the total volume of the network of cracks and the location of the proppant. Thus, an effectively stimulated volume can be estimated and used as input to simulate a formation for studying well productivity and draining a formation.

[00271] Microseismic monitoring can be used to image intensification of hydraulic fracturing of unconventional formations. The timing and location of microseismicity can be used to interpret geometry and hydraulic fracture growth. The microseismic waveform also contains information on inelastic deformation, which can also be used to obtain hydraulic fracture characteristics. The detected microseismic activity is part of the geomechanical strain associated with hydraulic fracturing. See, for example, Maxwell, S.C., “What Does Microseismic Tell Us About Hydraulic Fracture Deformation,’ ’” Recorder, 29-43, October, 2011 (here called “Maxwell 2011”). Detected movements can be limited to time scales corresponding to the bandwidth of the monitoring equipment. In at least some scenarios, microseismicity corresponds to shear deformation, and hydraulic fracturing can be considered as an interlayer of rock tension. Thus, aseismic deformation can include the aspect of displacement of the rupture beyond the limits that were observed due to microseismicity (see, for example, Maxwell, 2011). Deformation data can be taken into account when analyzing a network of fractures.

[00272] Microseismic locations can be used to limit the network of gaps. For a particular stress state, complex fracture networks can be modeled for a given discrete fracture network (DFN) of previously existing fractures. DFN can be adjusted to match the observed extent of microseismicity. DFN can be constructed using seismic origin formation and fracture logs. In some cases, there may be uncertainty in various aspects of the DFN, some of which may be limited using microseismic data.

[00273] There are various methods for using microseismic locations relative to discrete fractures of a direct image, especially if locations with high resolution (eg, doubled difference, relative separation) have been calculated. In another example, location uncertainty can be minimized using clustering or compression algorithms. Microseismic directions can also be determined from a series of locations using various methods. The microseismic method can also be used to statistically determine various DFN attributes. For example, microseismic source mechanisms can be used to determine the orientation of gaps. The radius of a microseismic slip source (derived from the frequency spectrum) can help delimit length distributions.

[00274] One aspect is the burst density, which can potentially be determined from microseismic density. Although the microseismic event density can potentially be used, the shear displacement distribution is also related to the density of discontinuities. Indeed, simulated displacement discontinuities can be directly calculated as the seismic moment density and compared with the observed seismic moment density. The density of the seismic moment can be expressed as:

– разрыв смещения в зоне дислокации, v_j – нормальное направление дислокации, c_ijpq – тензор упругости области источника и поддерживается для произвольной анизотропии. Другие сравнивали наблюдаемую микросейсмическую деформацию в контексте всей деформации, которая происходит во время гидравлического разрыва, на основе соображений баланса либо массы, либо энергии.Where

Is the displacement gap in the dislocation zone, v _j is the normal direction of the dislocation, c _ijpq is the elastic tensor of the source region and is maintained for arbitrary anisotropy. Others compared the observed microseismic deformation in the context of the entire deformation that occurs during hydraulic fracturing, based on considerations of either mass or energy balance.

[00275] It has been found that at least a portion of the deformation occurs aseismically, either of amplitude too small to be measured, or with temporal-scale characteristics beyond those that can be detected using conventional seismic equipment. In particular, it can be expected that part of the tensile strain associated with crack opening is aseismic. Thus, accounting for aseismic deformation can be used in comparison between the simulated and observed density of the seismic moment. A relative comparison can be made between simulated and observed seismic moments, which can potentially contribute to limiting the relative spatial heterogeneity of the density of discontinuities. In the study of the following case, an example of comparing microseismic deformation with a simulated deformation of a network of discontinuities will be given.

[00276] The ability to simulate hydraulic fracture growth can be used in fracture engineering. Hydraulic fracture intensification can be modeled using mechanical fracture models that simulate fracture elongation / deformation, leakage, hydraulic conductivity, and associated pressure profile for a given injection volume. There is a model for simple scenarios of relatively flat two-dimensional discontinuities. In cases of complex fracture networks, modeling capabilities can be used to solve the creation of new hydraulic fractures and / or the activation of previously existing natural fractures, which leads to the combination of geomechanical and hydraulic interactions between the individual components of the fracture network. See Weng, X., Kresse, O., Cohen, C., Wu, R. and Gu, H., “Modeling of Hydraulic Fracture Network Propagation in a Naturally Fractured Formation,” SPE140253, (2011).

[00277] The complexity of the hydraulic fracture network may depend in part on the differential voltage and the strength of the various fractures in the DFN: for flat fractures predominant in scenarios of large differential stress and strong fractures, and networks of fractures in scenarios of low differential stress and weak fractures. The complexity of the fracture can be difficult to calculate a priori, due to heterogeneity of the formation and the interaction of processing and completion schemes. Before fracturing is handled, geomechanical modeling can provide a deterministic prediction of fracture networks for specific scenarios. After processing, the geomechanical forecast can be checked using appropriate measurements, including microseismic ones.

[00278] Microseismicity provides observations to confirm such geomechanically calculated networks, either simply by comparison with the passage of the observed microseismically active region, or by quantifying the observed deformation using the obtained characteristics of the microseismic source. The observed microseismic deformation can only represent part of the total deformation, such as the relatively fast displacement of the fracture and / or shear components. Thus, confirmation or verification of the geomechanical model may include the separation of the voltage of the fracture network into components that are consistent with both microseismic and aseismic elements.

[00279] In one aspect presented herein, a comparison of microseismic deformation and simulated geomechanical stresses and a sequence of steps for testing a fracture network model is discussed. Aspects of characterization of the microseismic source and how it can be used to supplement the DFN and the mechanical model of the geological environment will be presented, quantifying the crack deformation.

The interaction of hydraulic fractures and simplified fracture geometries is shown here partially to illustrate certain indicators that control deformation modes. Non-limiting examples are presented here to describe the separation of simulated stresses into shear and elongation components, followed by a comparison of the corresponding displacement mode with the observed total microseismic moments.

[00280] Based on the example (s) disclosed herein, a sequence of actions is presented where the input modeling parameters can be changed to match both the fingerprint and microseismic deformation, which then leads to an estimate of the total volume of the fracture network and the placement of the proppant. Thus, an effectively intensified volume can be estimated and used as input to simulate a formation for studying well productivity and reservoir drainage.

Example - Four stages of fracturing simulation

1. Geomechanical modeling of a network of gaps

[00281] In the example shown in FIG. 36, a four-stage hydraulic fracturing intensification of the well 1204 of FIG. 12. FIG. 36 is the same as FIG. 12, except that the fracture network 3645 is shown near the production well 1204 and the control well 1205. As shown in FIG. 36, microseismic events 1223 are mapped in steps 1-4 and depicted as microseismic clusters 1223.1-1223.4 respectively around well 1204.

[00282] It is assumed that a change in stress in the formation leads to a change in the fracture geometry from relatively narrow, flat fractures for the first two steps of the bottomhole zone to a wider, more complex network of fractures for the final steps in the wellhead zone. Gap network modeling can be created and verified to approximate the spatial extent of microseismicity, as demonstrated by microseismic events 1223 shown in FIG. 36. Clusters of microseismic events 1223.1-.4 at each of stages 1-4 depict segments of a network of discontinuities close to the extent of microseismicity.

[00283] A simulation of the discontinuity network was created and tested to approximate the spatial extent of microseismicity, as shown in FIG. 37. FIG. 37 is a graph 3700 illustrating a simulated fracture network 3723 corresponding to the microseismic events 1223 of FIG. 36. Graph 3700 is shown along the direction Y (north) (m) (y axis) relative to X (east) (m) (x axis). Simulation can be performed using the same method as that set in FIG. 14.1-14.4 above. In this case, the simulated fracture network 3723 includes four segments (or parts) 3723.1-.4 of the fracture network corresponding to the microseismic event clusters 1223.1-.4 of FIG. 36. These segments 3723.1-.4 of the discontinuity network approximate the microseismic extent of FIG. 36. A closer match can be created by modifying the geometry of the input data of pre-existing gaps for the network 3645 gaps of FIG. 36.

2. Shear and tensile strains

[00284] In FIG. 38.1-39.2 depict simulated and observed deformations of the network 3723 discontinuities in FIG. 37. The simulated and observed strains can be compared, and the simulated strains converted to an effective seismic moment. The hidden assumption of the model of the network of discontinuities can be used to create a sufficient volume of the discontinuity to accommodate the full injected volume, by extending the discontinuity. Elongation in the network of discontinuities can also cause shear displacements at other discontinuities, so the resulting tensile stresses can be a combination of elongation in shear and tension. For a fracture model, displacements can be designed either as normal (i.e., opening under tension or elongation) or parallel (i.e., shear) components with respect to the orientation of the fracture.

[00285] In FIG. 38.1 and 38.2 illustrate simulated modes of shear and tensile deformation in the discontinuity network shown in FIG. 37. In FIG. 39.1 and 39.2 show the corresponding density profiles of the total stresses of the hydraulic fracturing network 3723 of FIG. 37, broken down into shear and tensile components, respectively.

[00286] In FIGS. 38.1 and 38.2, each graph 3800.1 and 3800.2 is shown along the Y (north) (m) (y axis) relative to X (east) (m) (x axis) directions. In FIG. 38.1 shows simulated shear strains proportional to shear displacement with arrows showing areas with additional shear τ. In FIG. 38.2 shows a simulated tensile strain with arrows showing areas with a significant elongation of σ tensile. Deformation in some places has predominantly stretch segments 3723.1, and other shear segments 3723.2 (mainly shear).

[00287] The tension and shear segments 3723.1, 3723.2 can be created by breaking the rock fracture strain of the hydraulic fracture network 3723. The simulated shear deformations shown are proportional to shear displacement (for example, a maximum of about 0.02 m) and a simulated tensile strain (for example, a maximum of about 0.03 m). The arrows in FIG. 38.1 show two areas with a significant shift. The arrows in FIG. 38.2 show two areas with significant elongation.

[00288] As shown in FIG. 38.2, shear segments 3723.2, 3723.3 (single flat fractures in the middle of the hydraulic fracture network 3723) are elongated, as mainly the tensile strain mode. It was found that the maximum tensile strain in the 3723 network is about 3 cm, while the maximum shear strain is about 2 cm.

[00289] Equations (20) and (21) can be used to transform the shear and tension components of the simulated hydraulic fracturing network of FIG. 38.1 and 38.2 into the simulated moment density of FIG. 39.1 and 39.2. In FIG. 39.1 and 39.2 show the corresponding contours of the density diagram of the total simulated total shear and tensile strains. In FIG. 39.1 is a graph 3900.1 showing the contours of a shear simulated full strain diagram of FIG. 38.1. In FIG. 39.2 is a graph 3900.2 showing the contours of a diagram of the total simulated tensile strain in FIG. 38.2. In Figs. 39.1 and 39.2, each graph 3900.1 and 3900.2 is shown along the Y direction (north) (m) (y axis) relative to X (east) (m) (x axis).

[00290] FIG. 39.1 and 39.2 may represent another view of graphs 3800.1 and 3800.2 of FIG. 38.1 and 38.2 modeled using a shear simulated full strain diagram. Shear and tensile stresses are shown in FIG. 39.1 and 39.2 with arrows τ of stress and arrows σ of tension, respectively. Arrow M indicates a high-shear area.

[00291] For comparison with the observed microseismicity, a 25 m sequential grating was used to calculate the seismic moment density of both total simulated and observed strains. A grid pitch has been selected to match the average uncertainty of location. In this example, the observed values of microseismicity are consistent with the directional pattern of the shift of displacements from northeast to southwest (NE-SW) or from northwest to southeast (NW-SE) with displacement along strike. In general, the inversion of the seismic moment tensor can also be used to estimate the microseismic deformation mode.

[00292] Based on the assumption of microseismic slip during shear, the contours of the total microseismic moments can be compared with the corresponding simulated shear deformations. Outside the observed microseismic strains, aseismic strains are also expected to contribute to the total expected strain. Seismic efficiency, defined as the ratio of radiated seismic energy to total energy released, is also an indicator leading to the expectation that microseismicity represents only a fraction of the total stresses. Assuming that these indicators are constant in the network of gaps, a relative comparison with microseismicity can be performed.

[00293] In FIG. 40 is a graph 4000 illustrating the total seismic moment from the observed microseismicity. Graph 4000 shows another view of the microseismic events 1223 depicted in FIG. 36 calculated based on the magnitude of the measured microseismic events of FIG. 36. Chart 4000 also shows the contours of the area of the large shift M ’in the segment 3723.1. These contours can be roughly matched with the simulated shear strain (FIG. 38.1).

[00294] FIG. 40 can be used to create the actual moment density taken from the microseismic events of FIG. 36. The contours of FIG. 40 is approximately consistent with the simulated shear strain of FIG. 39.1. The simulated strain shown in graph 4000 may be more constant in the fracture network than shown in FIG. 38.1, where the observed microseismic moment Mo is greatest near the working well (for example, near the working well 1204 of Fig. 12), namely, with a relatively flat break in the middle of the graph 4000 (shown by arrows in Figs. 39.1 and 40). The model shown in FIG. 40, shows this rupture segment 3723.1 next to arrow M, is predominantly a shear strain, and segment 3723.2 refers to tensile opening, which would then mean a more effective rupture in segment 3723.1 despite relatively weak microseismicity.

3. Seismic moment

[00295] The simulated strains can also be converted to a simulated (or effective) seismic moment (Mo ’) by multiplying the displacements by the shear modulus and the area of each fracture segment (see, for example, equation (20)). Table 7 compares the total simulated moments (Mo) for the tensile (σ) and shear (τ) components and the observed microseismicity for each step of the four steps of FIG. 36. As shown below, the modeled tensile component σ is larger than the modeled shear component τ (for example, about 50 times) from the model, and the microseismicity Mo is about 0.1% of the modeled shear component τ.

TABLE 7
OBSERVED TOTAL SEISMIC MOMENTS AND ACTING SIMULATED RESULTS Stage 1 Stage 2 Stage 3 Stage 4 Observed moment (Mw) (GNm) 1.29 0.24 0.16 0.62 Simulated Shift (τ) (GNM) 19300 21800 12400 19200 Simulated tensile stress (σ) (GNm) 36400 35,000 34400 33800

The observed moment (Mw) can be determined from the simulated shift (τ) of FIG. 38.1 and simulated tensile (σ) of FIG. 38.2, calculating it using equation (21).

[00296] In this example, the simulated stresses are predominantly tensile consistent with simple geometry scenarios. The simulated deformation is also larger than the observed one, which again indicates aseismic deformation. The observed deformation of Mo is relatively large at stage 1 and low at stage 2, compared, for example, with stage 4. The simulated shift is greatest for stage 2, suggesting that the simulated fracture network is too complex for this stage. It was found that the modeling of stage 1 is more consistent in deformation with other stages, in contrast to the large observed deformation for this particular stage. An additional study of the observed distribution of values shows a localized region in the north-eastern part of the segment 3723.1 rupture, comprising almost half of the seismic moment (along the arrows M, M ’in Fig. 39.1 and 40).

3. Verification

[00297] A second model was performed for step 1, including the adjusted DFN to simulate a given area of localized shift in the observational data. In FIG. 41.1 and 41.2 show graphs 4100.1 and 4100.1 ’, respectively, comparisons of shear displacements in the original stage 1 model and the updated model, where the DFN is manually adjusted to match the localized shear strain (arrows). In FIG. 41.1 shows part 41.1 of FIG. 38.1 and presents a more detailed view of the gap part 3723.1 of step 1 with a shift τ applied to it, as shown by the arrow. In FIG. Figure 41.1 shows the simulated shear stress τ associated with stage 1 for the original model.

[00298] In FIG. 41.2 shows a modified segment 3723.1 ’gap, adjusted for DFN. The adjusted model of the modified segment 3723.1 ’gap arises from the adjusted DFN. The modified gap segment 3723.1 ’as the effective shear moment increases by 46% over the initial gap segment 3723.1, with a localized shear similar to the observed microseismic (for example, the microseismic events of FIG. 37). A modified gap segment 3723.1 ’can be created using the process depicted in FIG. 46.1-46.4, as described in more detail here.

4. Forecasts

[00299] The modifications depicted in FIG. 41.2 can be used to create a microseismically verified fracture model, as shown on map 4200 of FIG. 42. The 4200 card is rotated and viewed from various angles to depict hydraulic fractures in more detail. A microseismically verified fracture model can be used to predict proppant distribution in a 3645 fracture network.

[00300] FIG. 42 shows a proppant gap / distribution width map 4200 for step 1 of the case studied. Map 4200 shows the proppant filling region 4255 and the proppant region 4253 not filled in the fracturing network 3739, shown based on the updated model of the fracture segment 3723.1 ’in FIG. 41.2.

[00301] This map 4200 also shows that the proppant is predicted to be concentrated near well 1204, with a relatively small total volume filled with proppant. The hydraulic conductivity can then be set based on the increase in permeability associated with shear displacements, in addition to the proppant distribution. In this particular example, although the fracture network 3739 may not be heavily filled with proppant, conductivity can still be increased by shearing and elongating from the non-conjugated surface topography.

[00302] The proppant map 4200 and the corresponding comparative conductivity can then be embedded in the reservoir simulator to predict well productivity and associated formation drainage. The fitting of the model based on the available data to a decrease in pressure can be used to assess the hydraulic conductivity of the areas 4255, 4253 filled and unfilled with proppant. The reservoir simulator can then be used to predict well productivity (e.g., production) and evaluate reservoir drainage over time, as shown in FIG. 43.

[00303] In FIG. 43 is a graph 4300 showing the predicted total well production for a proven conductivity of 0.03 millidar-foot (0.91 millidar-cm), as well as sensitivity tests for larger and lower conductivity scenarios. The graph 4400 shows the volume (V) of gas production (million standard cubic feet) (y axis) versus time (t) (year) (x axis) at conductivity levels 4359, 4361, 4363 without proppant about 0, 0003 millidar-feet (0.0091 millidar-cm), 0.03 millidar-foot (0.91 millidar-cm) and 1.0 millidar-foot (30.33 millidar-cm), respectively. Changing the conductivity level without proppant leads to an increase of 90% from line 4361 to 4359, and an increase of 40% from line 4361 to 4363. Predicted formation drainage can be used to study the need for well placement.

[00304] Pressure (P) can also be calculated for the burst network 3723 of FIG. 38.1 based on the placement of the proppant of FIG. 42. In FIG. 44 is a 4400 graph depicting a form of a pressure (P) map of a formation near a network of 3723 fractures, modeled after 20 years of production from well 1204.

[00305] The elongation of a fracture is one of the indicators of the effectiveness of a fracture, providing a sufficient fracture volume to accommodate a proppant, thereby ensuring long-term fracture permeability after intensification. The model described here can be used to maintain the mass balance of the injected fluid, and thus can be used to predict the placement of proppant in the fracture network, as shown in FIG. 42. The resulting proppant map can then be used to saturate permeability in the fracture network to simulate the formation by well productivity and formation drainage, as shown in FIG. 43 and 44, which leads to optimization of the assessment of the effective intensified volume and return of the reservoir.

Tear operation

[00306] In one aspect, the present invention describes methodologies for performing a microseismic fracture operation. These methods may include the use of complex fracture models that can be used to study the extent and magnitude of the deformation for comparison with the observed microseismicity (for example, the microseismic events of FIG. 36). Improving alignment in an appropriate microseismic fracture simulation mode can provide confidence in the overall simulation result. In the example (s) presented here, confirming the validity of shear strain using microseismicity suggests that the elongation strain is reliable, regardless of whether the directly observed microseismicity represents tensile opening conditions. Geomechanical modeling of hydraulic fracturing can be used to distinguish the estimated strain between the regimes of stresses in shear and tension.

[00307] In FIG. 45.1 illustrates a method 4500.1 for performing a discontinuity operation that can use either shear or moment densities to determine the discontinuity network. Method 4500.1 includes performing 2350 stimulation operations, including stimulation of a drilling site by pumping injected fluid with proppant into a fracture network, generating 2352 drilling site data (e.g., natural crack parameters for natural fractures, injection data, and microseismic measurements) and modeling 2375 fractures of the fracture network based on data from the drilling site, and determination of fracture geometry for fractures, as described in with respect to FIG. 23.1.

[00308] In this embodiment, after modeling 2375, a decision 4551 may continue to continue the shear fracture operation 4553.1 and / or to perform the seismic moment operation 4553.2. At step 4551, method 4500.1 can continue by performing shear fracture analysis operation 4553.1. Shear fracture analysis operation 4553.1 includes creating 2377 hydraulic fracture stress fields using a geomechanical model (e.g., 2D or 3D DDM), determining 2379 shear fracture parameters, including the fracture curve and stress state around the fracture network (e.g., along natural fractures, hydraulic fractures and / or rocks), determining 2381 fracture locations when the fracture network is shifted by the fracture curve and stress state, and 2383 checking the fracture geometry va by comparing microseismic measurements with a simulated fracture network and / or an activated discrete fracture network, as was done in method 2300.2 of FIG. 23.2.

[00309] Method 4500.1 may also include performing seismic moment operation 4553.2. Performing aseismic operation 4553.2 may include 4559 — determining the actual and simulated seismic moment densities and 4561 — checking the DFN of the fracture network by adjusting the DFN based on a comparison of the simulated and real seismic moment densities.

[00310] A seismic moment operation 4553.2 can be performed to take into account the effects of deformation on a network of discontinuities, as shown, for example, in FIG. 28-35.2. Seismic moment portion 4553.2 may be performed in addition to or in place of fracture portion 4553.1. In cases where both shear failure part 2351.1 and seismic moment part 2351.2 are performed, the results of each part can be compared and / or analyzed. Parts 4553.1, 4553.2 of shear failure and / or seismic moment can be repeated and / or compared.

[00311] The shear fracture operation 4553.1 and the seismic moment operation 4553.2 can be performed simultaneously or sequentially. The results of shear failure operation 4553.1 and seismic moment operation 4553.2 can be compared, analyzed and / or combined. After performing seismic operation 4553.1 and / or operation 4553.2. seismic moment correction 2385 and 2387 can be performed as previously described with respect to method 2300.2 of FIG. 23.2. Correction 2385 and / or 2387 can be performed based on a separate operation 4553.2 destruction, a separate operation 4553.2 seismic moment, and / or a combination of operation 4553.2 destruction and operation 4553.2 seismic moment.

[00312] In FIG. 46.2 shows a method 4500.2 for performing seismic moment operation, which can be used as performing 4553.2 of FIG. 45.1. Method 4500.2 includes 4555 — modeling a hydraulic fracturing network (see, for example, FIG. 37) based on well site data (for example, logging data 2352), 4559 — determining the actual and simulated seismic moment density, and 4561 — checking DFN 2375 based on a comparison of the predicted moment density (Fig. 39.1) and the actual moment density (Fig. 40). 4559 — determination of the actual and simulated seismic moment density can include 4557 — determination of the shear and extension components of a simulated hydraulic fracture network (see, for example, FIGS. 38.1, 38.2 and equations (20), (21)), 4558 — assembly of components shear and tension of a simulated hydraulic fracture with a simulated moment density, 4560 - creation of the actual moment density (see, for example, Fig. 40) based on data from the well site (for example, microseismic events, Fig. 37).

[00313] The simulation 4555 may be the same as the simulation 2375 and / or, as shown in FIG. 37. Definition 4557, transformation 4558, creation 4560, and verification 4561 can be repeated to further refine the DFN. Method 4500.2 may also include 4567 — proppant placement forecast (FIG. 42), 4568 — production forecast (FIG. 43) and / or 4569 — reservoir pressure forecast for fracture network (FIG. 44).

[00314] Part or all of the described methods can be combined, performed in any order and / or, if necessary, repeated.

Check

[00315] In another aspect, the present invention relates to a method for using microseismic data to verify an initial discrete natural fracture network (DFN). The proven DFN model can be used as input to the model of a complex hydraulic fracture network (HFN) to model crack propagation during fracture processing. The proven DFN provides an accurate description of the formation and, therefore, more accurate prediction of the generated fracture geometry using the HFN simulator.

[00316] Detailed models of complex hydraulic fracturing predict the progressive propagation of multiple fracture branches in the fracture network. The formation may initially include many natural fractures. The interaction of hydraulic fracture and natural fracture can lead to branching of the fracture where they intersect.

[00317] As shown in FIG. 21, various scenarios of when hydraulic fracture crosses a natural fracture are depicted. Scenarios that lead to hydraulic fracturing and propagation along a natural fracture lead to branching and fracture complexity. In FIG. 21 schematically depicts some of the possible outcomes of when a hydraulic fracture crosses a natural fracture. Since it is not possible to perfectly characterize a natural fracture underground, the initial set of natural fractures is stochastically generated, limited information obtained from seismic data and surveys by a downhole scanner using geological and geostatistical models.

[00318] In FIG. 46.1-46.4 depict graphs 4600.1-4600.4 stages of modeling a network of 4647 fractures around well 1204. FIG. 46.1 shows a top view of a statistically generated DFN 4647 having tracks evenly distributed in the formation. In FIG. 46.2 shows the predicted HFN 4661 created from a complex fracture model for the corresponding DFN, along with micro-seismic events 4663 collected during fracture processing. In FIG. 46.1 shows traces of a statistically generated DFN near horizontal well 1204. FIG. 46.2 shows a simulated fracture network 4661 created from a uniformly distributed DFN 4647. In this case, the microseismic data show the different formation of clusters of microseismic events. Compared to the simulation results, there is a large area between the clusters of events, where numerous areas of the fracture surface are created in accordance with the model, and with small microseismic activity.

[00319] Since microseismic events correlate with slip during shear of natural fractures in the formation caused by rock deformation and fluid flow in the formation surrounding hydraulic fractures, the formation of microseismic event clusters can be an indicator of the strong formation of natural fracture clusters. In this case, the region between the clusters may be absent in many natural cracks, and the model predicts an incorrect fracture geometry due to an incorrect assumption of the initial distribution of natural cracks.

[00320] In one aspect of the present invention, it is contemplated that a more representative DFN can be created by adjusting the original DFN model using microseismic measurements. This test can be performed by redistributing natural cracks in proportion to the spatial distribution of the density of microseismic events, or by using the method of moment density described in FIG. 45.2.

[00321] In FIG. 46.3 shows graph 4600.3, showing the tested DFN 4647 ’and the heterogeneous distribution of natural cracks based on microseismic measurements. A corresponding hydraulic fracture geometry simulation 4661 ’is shown in graph 4600.4 in FIG. 46.4. In FIG. 46.4 shows the simulated 4661 ’hydraulic fractures for the tested DFN. The results of the verified DFN should provide a description of the hydraulic fracturing geometry with increased accuracy, and the final dynamics of the production well 1204.

[00322] In FIG. 47 shows a method 4700 for checking DFN. Method 4700 can be used, for example, to optimize a complex fracture pattern using microseismic measurements to verify the distribution of natural cracks. Method 4500 includes creating (4571) an initial distribution of natural fractures (DFN model) with characteristics derived from well site data, such as seismic measurements, geological structure, wellbore scanner studies, and core studies based on characteristics and measurements; creation (4573) of the initial hydraulic fracturing scheme and simulation using a complex fracture model that combines the interaction of hydraulic fractures and natural fractures; an injection operation (4575) for hydraulic fracturing and the collection of microseismic data in real time; verification (4577) of the initial DFN and redistribution of natural cracks in accordance with the observed distribution of microseismic events; (4579) checking additional parameters of natural fractures and formations using the verified DFN distribution to match the predicted hydraulic fracture coverage with the full microseismic region and the simulated treatment pressure with the measured pressure; and revising (4581) the fracture pattern based on the proven model to optimize the next treatment step in the same well or the next well in the same area.

[00323] The method of FIG. 47 may be used as check 4561 of FIG. 45.2 by replacing the observed distribution of microseismic events 4577 with the observed density of the seismic moment.

[00324] Although the present invention has been described with reference to examples of embodiments and their embodiments, the present invention is not limited to such embodiments and their embodiments. On the contrary, the system and method proposed in the present invention allow various modifications, changes and / or improvements without departing from the essence or scope of the present invention. Accordingly, the present invention clearly covers all such modifications, changes, and improvements within its scope.

[00325] It should be noted that when improving any such actual embodiment, numerous decisions of a particular embodiment must be made to achieve the specific goals of the developers, such as compatibility with systemic and economic constraints that vary from one application to another. In addition, it is clear that attempts to such an improvement can be complex and time-consuming, but, nevertheless, the present description can be a guide for specialists who are obvious advantages of the present invention. In addition, the embodiments used / disclosed herein may also contain some components other than those set forth.

[00326] In the description, each numerical value should be considered only as adjusted by the term “about” (if it has not already been clearly adjusted), and then considered again as not so adjusted, unless otherwise indicated in the context. In addition, in the description it should be understood that any range given or described as useful, suitable, etc., assumes that without exception all values in the range, including end points, should be considered declared. For example, “a range of 1 to 10” should be considered as showing all possible numbers along a continuum between about 1 and about 10. Without this, even if specific reference points in the range, or even no reference points in the range are clearly identified, or referring to several specific points, it should be clear that the applicants acknowledge and understand that all reference points in the range should be considered as indicated, and that the applicants have knowledge for the entire range and all points in dia Azon.

[00327] The statements provided herein merely provide information related to the present invention and may not establish the prior art, and may describe some embodiments illustrating the invention. All references cited herein are hereby incorporated by reference in their entirety.

[00328] The description herein is directed to certain specific embodiments. It should be understood that the description below serves to enable a person skilled in the art to carry out and use any object defined now or later by the claims found in any patent granted.

[00329] It should be understood that the various methods described herein can be implemented in connection with hardware, software, or a combination thereof. Thus, various methods or certain aspects or parts thereof may take the form of a control program (i.e., instructions) implemented on a tangible medium such as floppy disks, CDs, hard disks, or any other computer-readable storage media in which when the control program is downloaded and executed on a machine, such as a computer, the machine becomes a device for implementing various methods. In the case of executing a control program on programmable computers, the computing device may include a processor, a memory device read by the processor (including volatile and non-volatile memory and / or memory elements), at least one input device and at least one output device. One or more programs that can implement or use the various methods described here can use an application programming interface (API), reusable controls, and the like. Such programs can be implemented at a high level procedurally or object-oriented programming language for communication with a computer system. However, the program (s) may be implemented in assembly language or machine language, as necessary. In any case, the language can be a compiled or interpreted language, and combined with hardware implementations.

[00330] Although the foregoing is directed to embodiments of the various methods described herein, other and further embodiments may be devised without departing from the main scope of the invention, which may be defined in the following claims. Although the subject matter of the invention has been described in a language characteristic of structural features and / or methodological actions, it should be understood that the subject matter defined in the appended claims cannot be limited to the specific features or actions set forth above. On the contrary, the specific features and actions set forth above are disclosed as exemplary forms of embodiments of the claims.

[00331] Although only a few exemplary embodiments are described in detail above, one skilled in the art will appreciate that many modifications are possible in exemplary embodiments without significantly deviating from systems and methods for performing well stimulation operations. Accordingly, all such modifications are intended to be included within the scope of the present invention, as indicated in the following claims. In the claims, the means-plus-function clauses are intended to encompass the structures disclosed herein as performing the specified function, and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw cannot be equivalent to a structure in that the nail uses a cylindrical surface to fasten the wooden parts together, while the screw uses a screw surface in the fastening environment of the wooden parts, the nail and the screw can be equivalent structures. It is not the applicant’s explicit intention to apply Section 35 of the U.S. Code, § 112, paragraph 6, for any restrictions on any claims in this document except those that specifically use the words "intended for" in conjunction with a related function.

Claims (28)

1. A method of performing a fracturing operation at a drilling site located near an underground formation having a borehole passing through it (1204) and a complex network of fractures, a network of fractures containing natural fractures, the drilling site being intensified by pumping the injected fluid with proppant into the fracture network, including: creation of data (2352) of the well site containing measurements of microseismic events of the underground formation; modeling (2375) of the hydraulic fracture network and the discrete fracture network of a complex fracture network based on data from the drilling site; characterized in that the method further comprises: execution (4553.2) of seismic moment operation, including: determination (4559) of the actual density of the seismic moment based on the data of the drilling site and the predicted density of the seismic moment based on the shear and extension components of the simulated hydraulic fracturing network and checking (4561) a discrete network of cracks based on a comparison of the predicted moment density and the actual moment density; and adjustment (2387) of the download based on the verification. 2. The method according to claim 1, in which the determination of the predicted density of the seismic moment includes: determination (4557) of shear and tension components of a simulated hydraulic fracture network and transforming (4558) the shear and tension components of a simulated hydraulic fracture network into a simulated moment density. 3. The method according to claim 1, further comprising predicting (4567) proppant placement based on a simulated discrete network of cracks. 4. The method according to claim 3, further comprising predicting (4568) production based on the predicted placement of proppant. 5. The method according to claim 4, further comprising predicting (4569) formation pressure based on the predicted proppant placement. 6. The method according to claim 1, in which the modeling of a discrete network of fractures includes the creation of an initial discrete network of fractures from at least one of the data of the well site, including seismic measurements, geological structure, studies by a downhole scanner and core studies and their combination based on measurements of characteristics. 7. The method according to claim 1, in which modeling the hydraulic fracturing network includes creating an initial hydraulic fracturing scheme and performing modeling using a complex model of a fracture that combines the interaction of hydraulic fractures and natural fractures. 8. The method according to claim 1, in which the creation of data from the well site includes an injection operation for hydraulic fracturing into the well of the well site and the collection of microseismic data in real time. 9. The method according to claim 1, in which the verification includes: verification (4777) of a discrete network of cracks and redistribution of natural cracks in accordance with the observed distribution of microseismic events in the event area; checking (4779) additional parameters of natural fractures and formations using a proven discrete fracture network to match the coverage area of the simulated hydraulic fracture network with the event area and simulated treatment pressure with the measured pressure, and optimization (4781) of injection at the drilling site by revising the simulated hydraulic fracture based on a proven discrete fracture network. 10. The method according to claim 1, further comprising performing a fracture shear operation, including: determination (2377) of the stress field of hydraulic fractures using a geomechanical model; determination (2379) of shear fracture parameters, including the fracture curve and stress state around the network of cracks; determination (2381) of the fracture location when the network of cracks is shifted from the fracture curve and the stress state and comparison (2383) of simulated hydraulic fractures and shear fracture locations with measured microseismic events. 11. The method according to claim 1, further comprising intensifying (2350) the drilling site by pumping the injected fluid with proppant into the fracture network. 12. The method according to claim 11, in which the adjustment includes the adjustment (2387) of the intensification operation based on verification.

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