RU2591857C1 - System and method for performing operations for stimulation of resources - Google Patents

Abstract

FIELD: mining.

SUBSTANCE: system and method for performing operations on hydraulic fracturing of formation in well shaft, boring underground formation. Method involves receiving integrated data of drilling platform, creation of a model of mechanical properties of geologic environment using integrated data of drilling platform, simulation of intersection of natural fracture artificially created hydraulic break, using model of mechanical properties of geologic environment, determining properties of intersections encountered natural fractures. Method may also generate a stimulation plan, using model of mechanical properties of geologic environment and properties of intersections. Stimulation plan may include viscosity or consumption of fracture medium.

EFFECT: technical result is improved efficiency of subsurface stimulation.

23 cl, 22 dwg

Description

BACKGROUND

[0001] This section is intended to provide reference information to better understand the various technologies described below. As is clear from the title, a description is given of the technical field to which the invention relates. The fact that this technical field is related to the invention does not in any way mean that it is a prior art. This technical field may or may not be the state of the art. Therefore, it should be understood that the provisions of this section should be considered in this light, and the Applicant in no way acknowledges such a provision, nor does it agree with such a provision in which any reference cited is prior art or similar prior art.

[0002] To facilitate the recovery of hydrocarbons from oil and gas wells, subterranean formations surrounding these wells may be subjected to hydraulic fracturing. Hydraulic fracturing has become a valuable method for creating fractures in subterranean formations that allow hydrocarbons to move toward the well. Hydraulic fractures can extend from the well tens of meters in two opposite directions, in accordance with the natural stresses of the formation. In some cases, they can form a complex network of cracks. Complex fracture networks may contain artificially created hydraulic fractures and natural fractures that may or may not intersect in a variety of azimuths, in a variety of horizons and directions, and in a variety of areas.

[0003] The formation is fractured by introducing into the formation a specially designed fluid (called a “fracturing fluid” or “fracturing pulp”) under high pressure and at a high flow rate of fluid through one or more of the wellbores. Oil companies have developed a wide variety of oil and water based fluids and impregnations to more effectively create and maintain permeable and productive fractures. The composition of these fluids is very different - from plain water with sand to complex polymeric substances with many additives. Each type of fracturing fluid has unique characteristics, and each has its own positive and negative sides. To achieve the required complexity of the fracture network, it is necessary to selectively change certain qualities of the fracturing fluid, as well as its injection characteristics.

[0004] For example, highly complex fracture network geometry can create a larger surface area compared to relatively simple and straight fractures. Large fracture surface areas can increase production in very low permeability formations. On the other hand, a complex network of cracks can contain tortuous cracks that twist many times and change in the direction of the gap, which can make the cracks placed too closely or create compression points that impede the movement of hydrocarbons or particle transport. In order to achieve greater high performance of cracked formations, an optimal geometry may be needed to maximize both the surface area of the cracks and the transport characteristics.

[0005] In some cases, to evaluate the development of hydraulic fracturing over time, the occurrence of cracks and their propagation in the formation can be numerically modeled. Traditional fracturing models usually involve a two-way type of artificially created fractures. Such double-sided fractures can provide an incomplete picture of the complex nature of artificially created fractures in some atypical formations with already existing heterogeneities, such as natural fractures (PT). Moreover, although some of the fracture models available on the market allow for taking into account the already existing natural fractures of the formation, many of the published models are too simplified and overlook the need for a rigorous and flexible solution to the problem of the interaction between artificially created and natural fractures. In addition, the vast majority of published models do not explicitly take into account the injection properties of the fluid, which may include the discharge flow rate, the viscosity properties of the fluid, and the concentration of additives.

SUMMARY OF THE INVENTION

[0006] This document describes options for implementing all kinds of technologies for a method of performing fracturing operations near a wellbore penetrating an underground formation. The method may include collecting integrated well area data. Integrated data about a well’s area may include geomechanical, geological and (or) geophysical properties of an underground formation, as well as mechanical, geomechanical and (or) geometric properties of natural fractures in this underground formation. The method may include modeling the mechanical properties of the geological environment using integrated drilling data. The method may include simulation of the intersection of artificial fracturing with a natural fracture using the simulation of the mechanical properties of the geological environment. The method may include determining the properties of a natural fracture intersected in this case. The method may also include the development of a simulation plan using modeling the mechanical properties of the geological environment and the properties of the corresponding intersections of the gaps. This simulation plan may include indicators of fluid viscosity or flow rate of the fracturing fluid used.

[0007] This document describes options for implementing all kinds of technologies for a method of performing hydraulic fracturing operations near a wellbore penetrating an underground formation. The method may include collecting integrated well area data. Integrated drilling data may include the geomechanical, geological and (or) geophysical properties of the underground formation, as well as the mechanical, geomechanical and (or) geometric properties of natural fractures in this underground formation. The method may include modeling the mechanical properties of the geological environment using integrated drilling data. The method may include simulation of the intersection of artificial fracturing with a natural fracture using the simulation of the mechanical properties of the geological environment. The method may include determining the properties of a natural fracture intersected in this case. The method may also include predicting the hydrocarbon productivity of the subterranean formation using fracture intersection properties.

[0008] This document describes options for implementing all kinds of technologies for a method of performing fracturing operations near a wellbore penetrating an underground formation. The method may include collecting integrated well area data. Integrated data about a well’s area may include geomechanical, geological and (or) geophysical properties of an underground formation, as well as mechanical, geomechanical and (or) geometric properties of natural fractures in this underground formation. The method may include modeling the mechanical properties of the geological environment using integrated drilling data. The method may include simulation of the intersection of artificial fracturing with a natural fracture using the simulation of the mechanical properties of the geological environment. The method may include determining the properties of a natural fracture intersected in this case. The method can compare the properties of intersections of gaps with microseisms in the observed data obtained as a result of simulation based on the model of the mechanical properties of the geological environment.

[0009] This document describes options for implementing all kinds of technologies for a method of performing fracturing operations near a wellbore penetrating an underground formation. The method may include collecting integrated well area data. Integrated data about the well area may include geomechanical, geological and (or) geophysical properties of the underground formation, as well as mechanical, geomechanical and (or) geometric properties of natural fractures of the underground formation. The method may include performing modeling of the mechanical properties of the geological environment using integrated drilling data. The method may include simulating the leakage of a fracture fluid from a generated fracture into a natural fracture using simulations of the mechanical properties of the geological environment. The method may also include the development of a simulation plan using modeling the mechanical properties of the geological environment. The simulation plan may include indicators of fluid viscosity or injection flow rate of the fracturing fluid used. The method may also include adjusting the operating parameters of the simulation plan, based on simulation modeling of the outflow of fluid into the reservoir in order to optimize the outflow from artificially induced hydraulic fracturing into a natural fracture.

[0010] The foregoing section of the invention is presented to represent a number of concepts, which are described below in the section of a detailed description of the invention. The present description of the invention is intended neither to indicate the claims of the subject invention, nor to be used to limit the scope of the claimed subject matter. Moreover, the claims of the object of the invention are not limited to implementations that correct any or most of the disadvantages described in any part of this disclosure. In fact, the systems, methods, work procedures, techniques and work processes disclosed herein may supplement or replace traditional methods for designating, separating and / or processing various aspects of well data or other data collected in the subsoil area or another multidimensional space.

BRIEF DESCRIPTION OF THE DRAWINGS

[0011] Implementations of various technologies will be described below with reference to the relevant drawings. It should be understood, however, that the respective drawings illustrate various embodiments of the invention described herein and are not intended to limit the scope of the various technologies described herein.

[0012] Figures 1A-1D illustrate schematic views of oilfield work in a well region in accordance with various embodiments of the invention described herein.

[0013] Figures 2A-2D illustrate schematic views of data collections in accordance with various embodiments of the invention described herein.

[0014] Figure 3A illustrates a schematic view of a well area with various downhole stimulation activities in accordance with the various embodiments of the invention described herein.

[0015] Figures 3B-3D illustrate a variety of fractures in a well region in accordance with the various embodiments described herein.

[0016] Figure 4A is a flowchart of a workflow in accordance with various embodiments of the invention described herein.

[0017] Figure 4B illustrates a schematic view of a borehole stimulation of a subsoil in accordance with various embodiments of the invention described herein.

[0018] Figures 5.1-5.4 illustrate an increase in fracture near a wellbore during hydraulic fracturing in accordance with various embodiments of the invention described herein.

[0019] Figure 6 illustrates a fracturing network in accordance with various embodiments of the invention described herein.

[0020] Figure 7 illustrates the intersection between artificially generated fractures and natural fractures in accordance with various embodiments of the invention described herein.

[0021] Figure 8 is a flowchart of simulation and fracturing in accordance with various embodiments of the invention described herein.

[0022] Figure 9 illustrates a computer system in which the various technologies and techniques described herein can be implemented.

DETAILED DESCRIPTION OF THE INVENTION

[0023] The following describes specific implementations of the invention. It should be understood that the following is intended to enable a person skilled in the art to create and use any aspect of the invention defined here or below by the “claims” found in any patent granted.

[0024] Detailed descriptions of various embodiments of the invention will be given below, examples of which are illustrated by the respective drawings and figures. In the following detailed description of the invention, numerous specific details are set forth in order to provide a thorough understanding of the claimed invention. However, it will be apparent to one of ordinary skill in the art that the claimed invention can be practiced without these specific details. In other cases, well-known methods, procedures, components, circuits and networks are not described in detail, so as not to unnecessarily clutter up the main aspects of the claimed invention.

[0025] It is also apparent that although the terms first, second, etc. may be used herein. to describe different elements, these elements should not be limited to these terms. Such terms are used to distinguish one element from another. For example, a first object or block may be defined as a second object or block, and, likewise, a second object or block may be defined as a first object or block, without departing from the scope of various embodiments of the invention described herein. Both the first object or block, and the second object or block are, respectively, objects or blocks, but they should not be considered as the same object or block.

[0026] The terminology used in the designation herein is provided for the purpose of describing specific embodiments of the invention, and is not intended to limit the claimed invention. The singular word forms used herein are intended to include the plural forms as well, unless the context clearly indicates otherwise. It should also be understood that the terms “and / (or)” are used herein to refer to any combinations and include them with one or more related elements. In addition, it should be understood that the terms "includes", "including", "contains" and / (or) "containing" when used in this description determine the presence of the claimed parts, parts, blocks, actions, elements and / (or) components but do not impede the presence of one or more or complement due to one or more other parts, parts, blocks, actions, elements, components and / (or) their groups.

[0027] As used herein, the term “if” should be construed as meaning “when” or “during” or “in response to a determination” or “in response to a discovery”, as the context requires. Likewise, the phrase “if defined” or “if [a specific condition or event] is detected” should be interpreted as meaning “at the time of determination” or “in response to a determination” or “at the time of detection of [a specific condition or event]” or “in response to the detection of a [specific state or event], ”depending on context.

[0028] Various embodiments of the invention described herein relate to systems and methods for performing and simulating fracturing of an underground formation. Such embodiments of the invention will be described in more detail with reference to Figures 1-9.

PETROLEUM WORKS

[0029] Figures 1A-1D illustrate various oilfield operations that may be performed at a drilling site, and Figures 2A-2D illustrate various information that may be collected at a drilling site. Figures 1A-1D illustrate a simplified, schematic view representing an oilfield or drilling site 100 containing an underground formation 102 containing, for example, a reservoir 104, and illustrate a variety of oilfield operations performed at a drilling site 100. Figure 1A illustrates exploration work performed by a reconnaissance tool, such as seismic station 106.1, to measure the properties of an underground formation. Exploration work can be seismic operations to create acoustic vibrations. In Figure 1A, such acoustic vibrations 112 generated by source 110 are reflected from a plurality of heterogeneities 114 in subterranean formation 116. These acoustic vibrations 112 can be received by sensors, such as geophones-receivers 118, placed on the earth's surface, and generating electrical outgoing signals, denoted as received data 120 in Figure 1A.

[0030] In response to the received acoustic vibrations 112 represented by different parameters (such as the amplitude and / (or) frequency) of these acoustic vibrations 112, the geophones 118 can generate electrical output signals containing data about the underground formation. The obtained data 120 can be fed as incoming data to the computer 112.1 of the seismic station 106.1 and, responding to the input data, the computer 122.1 can create an output 124 of seismic and microseismic data. The output 124 of seismic data can be recorded, transmitted or, if necessary, sent for further processing, for example, for data preprocessing.

[0031] Figure 1B illustrates drilling operations performed by a drilling tool 106.2 suspended on a derrick 128 and moving into an underground formation 102 to create a borehole 136 or other channel. A mud reservoir 130 may be used to supply drilling fluid to the drilling tools through a pipe 132 for circulating the drilling fluid through the drilling tools up the barrel 136 and back to the surface to the surface. The drilling fluid can be filtered and returned to the reservoir mud. A circulating system can be used to store, control, or filter leaking drilling fluid. In this illustration, a drilling tool has been pushed into an underground formation to reach reservoir 104. Each well may target one or more reservoirs. The drilling tool can be adapted to measure the properties of the well using logging while drilling. The logging while drilling can also be adapted to obtain a core sample 133, as shown in Figures 1B and 2B, or be removed so that the core 133 could be obtained using another tool.

[0032] For communication between the drilling tool 106.2 and the ground station, a surface unit 134 may be used. The surface unit 134 may communicate with the drilling tool 106.2 to send instructions to and receive data from the drilling tool 106.2. The surface unit 134 may be made with computer equipment for receiving, storing, processing and (or) analyzing data on work. The surface unit 134 may collect data generated during drilling operations and create a data output 135 that may be stored or transmitted. Computer equipment, such as surface unit 134, may be located at various locations near the well site and / or remote location.

[0033] Sensors (S) may be located near the field to collect data related to the various activities described above. As shown, the sensor (S) can be placed in one or more places in the drilling tool 106.2, and / or on the cable to measure drilling parameters, such as bit weight, bit torque, pressure, temperature, flow rates, compositions, speed rotation and / or other operating parameters. Sensors (S) can also be located in one or more places in the circulation system.

[0034] Data collected by sensors can be collected using surface unit 134 and / or other sources of data collection for analysis or other processing. Data collected using sensors can be used alone or in combination with other data. Data may be collected in one or more databases and / or transmitted remotely. All or some parts of the data can be selectively used for analysis and (or) work on predicting the current and (or) other boreholes. The data may be archived 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 archival data or other inputs for further analysis. Data can be stored in separate databases or combined into a single database.

[0035] The collected data can be used for research, such as modeling. For example, the output of seismic data can be used to perform geological, geophysical surveys and (or) engineering analysis of the formation. Data on the reservoir, borehole, surface and (or) processed data can be used to perform reservoir-reservoir, borehole, geological and geophysical or other types of simulation. The output of work data can be created by sensors directly or after some preliminary processing or modeling. Such output can be used as input for further research.

[0036] Data may be collected and stored in the surface unit 134. One or more surface units 134 may be located at or connected to the drilling site remotely. Surface block 134 may be a single block or a complex network of blocks used to perform the necessary data management functions during oilfield operations. Surface unit 134 may be a manual or automatic system. The surface unit 134 may be controlled and / or configured by the user.

[0037] The surface block 134 may be configured with a transmitter 137 to enable communication between the surface block 134 and different parts of the area of the current field or other location. The surface unit 134 may also be configured with or operably connected to one or more controllers to drive mechanisms at the drilling station 100. The surface unit 134 may then send control signals to the field area in response to the received data. Surface unit 134 may receive commands through a transceiver or send commands to a controller on its own. A processor may be provided for analyzing data (locally or remotely), making decisions and actuating the controller. Thus, the work can be selectively adjusted based on the data collected. Based on this information, part of the work can be optimized, such as drilling control, bit loading, discharge rate or other parameters. Such adjustments can be performed automatically based on a computer protocol and / or manually by the operator. In some cases, drilling plans can be adjusted to select the optimal working conditions, or to avoid problems.

[0038] Figure 1C illustrates the cable work performed using a cable tool 106.3 suspended from a rig 128 and immersed in a trunk 136 in Figure 1B. Rope tool 106.3 may be arranged to be placed in barrel 136 to perform logging operations performed in the well of tests and (or) sampling. Rope tool 106.3 can be used to implement another method and equipment for performing seismic surveys. The cable tool 106.3 of Figure 1C may, for example, have an explosive, radioactive, electrical or acoustic source of energy 144 that sends and / or receives electrical signals in the surrounding formation 102 and the fluid contained therein.

[0039] The cable tool 106.3 can be operatively connected to, for example, geophones 118 and computer 122.1 of the seismic station 106.1 of Figure 1A. The cable tool 106.3 may also send data to the surface unit 134. The surface unit 134 may collect data generated during the cable work and generate data output 135 that may be stored or transmitted. Rope tool 106.3 can be placed at different depths in the trunk 136 for exploration or other information related to the underground formation.

[0040] Sensors (S) may be located close to field 100 to collect data related to various activities described above. As shown, the sensor (S) is located in the cable tool 106.3 for measuring downhole parameters, which include, for example, porosity, permeability, fluid composition and (or) other operating parameters.

[0041] Figure 1D illustrates field exploration performed using production tool 106.4, placed from a production unit or wellhead 129 in a completed wellbore 136 of Figure 1C to extract fluid from downhole reservoirs to surface equipment 142. Fluid flows from the reservoir 104 through the perforation in the casing (not shown) into the production tool 106.4 in the bore 136, and then into the surface equipment 142 through the collecting network 146.

[0042] Sensors (S) may be located near the field to collect data related to the various activities described above. As shown, the sensor (S) can be located in an operational tool 106.4 or in related equipment, such as wellhead 129, a collection network, surface equipment and / or production equipment for measuring fluid parameters, such as fluid composition, flow rate, pressure , temperature and (or) other operating parameters.

[0043] Although only simplified configurations of the well site are shown, it is obvious that the field or well 100 may occupy part of the land, sea, and / or water sections containing one or more well sites. Production may also include injection wells (not shown) for additional recovery or for storage, for example, of hydrocarbons, carbon dioxide or water. One or more pieces of collection equipment can be operatively connected to one or more drilling sites for selectively collecting downhole fluids from the drilling site (s).

[0044] It is obvious that Figures 1B-1D illustrate instruments that can be used to measure the properties of not only the field, but also non-oilfield objects, such as mines, margins, storage facilities, and other underground equipment. In addition, although specific tools for data collection are illustrated, it is obvious that various measuring tools (e.g. wireline, drilling measurements (IPB), logging while drilling (CPB), coring, etc.) can be used that can lead registration of parameters, such as seismic total double run time, density, resistivity, productivity, etc., of the underground formation and (or) geological formations. Various sensors (S) can be placed along the barrel and (or) the monitoring tool to collect and (or) monitor the necessary data. Other data sources from remote locations may also be used.

[0045] The field configuration of Figures 1A-1D illustrates examples of a drilling site 100 and various works used with the techniques described herein. The field may be located partly or entirely on land, water and (or) the sea. Also, although a single field is illustrated, measured in a single place, field development can be used in any combination of one or more fields, one or more processing equipment, and one or more drilling sites.

[0046] Figures 2A-2D are graphical illustrations of data collected using the tools of Figures 1A-1D, respectively. Figure 2A illustrates the seismic trace 202 of the underground formation of Figure 1A obtained by seismic station 106.1. Seismic trace 202 can be used to provide data, such as a time period of the reflected signal. Figure 2B illustrates a core sample 133 obtained using drilling tools 106.2. A core sample can be used to provide data, such as a graph of the density, porosity, permeability, or other physical properties of a core sample along the length of the core. Density and viscosity tests can be performed on a core fluid at different pressures and temperatures. Figure 2A illustrates the logging diagram 204 of the subterranean formation of Figure 1C obtained using wireline tool 106.3. A log 204 may provide measurements of resistivity or other formation parameters at different depths. Figure 2D illustrates a curve or graph 206 of the performance drop of a fluid flowing through an underground formation from Figure 1D measured on surface equipment 142. A performance decline curve may reflect the current flow rate Q as a function of time t.

[0047] The corresponding graphs of Figures 2A, 2C and 2D illustrate examples of static measurements that can reflect or provide information about the physical characteristics of the formation and the reservoir therein. These measurements can be analyzed to determine the properties of the formation (s), to determine the accuracy of measurements and (or) check for errors. The diagrams of each of the corresponding measurements can be aligned and scaled for comparison and verification of properties.

[0048] Figure 2D illustrates an example of dynamic measurements of fluid properties along a bore. As the fluid flows through the barrel, measurements are made of the properties of the fluid, such as its flow rate, pressure, composition, etc. As described below, 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 in a formation over time.

STIMULATION WORKS

[0049] Figure 3A illustrates the stimulation work performed at well site 300.1 and 300.2. The drilling platform 300.1 comprises a drilling rig 308.1 containing a vertical shaft 336.1 extending through the formation 302.1. The drilling platform 300.2 contains a drilling rig 308.2 containing a vertical trunk 336.2 and a drilling rig 308.3 containing a trunk 336.3 extending beneath it into the underground formation 302.2. Although the drilling site 300.1 and 300.2 are illustrated as having specific configurations of drilling rigs with trunks, it is obvious that one or more rigs with one or more trunks can be located on one or more drilling sites.

[0050] The trunk 336.1 exits drilling rig 308.1, passing through atypical reservoir reservoirs 304.1-304.3. Trunks 336.2 and 336.3 exit drilling rig 308.2 and 308.3, respectively, into an atypical reservoir reservoir 304.4. As illustrated, atypical reservoirs 304.1-304.3 are gas saturated reservoirs and atypical reservoirs 304.4 are shale reservoirs. One or more atypical reservoir reservoirs (for example, gas saturated, shale, carbonate, coal, heavy oil, etc.) and (or) typical reservoir reservoirs can be represented in this formation.

[0051] The stimulation work in Figure 3A can be performed individually or in combination with other oilfield work, such as the oilfield work in Figures 1A and 1D. For example, wells 336.1-336.3 can be measured, drilled, tested, and performed as illustrated in Figures 1A-1D. Stimulation work carried out at drilling sites 300.1 and 300.2 may involve, for example, perforation, rupture, injection, etc. Stimulation work can be performed in combination with other oilfield work, such as completion and production work (see, for example, Figure 1D). As illustrated in Figure 3A, the shafts 336.1 and 336.2 are completed and constructed with perforations 338.1-338.5 to facilitate operation.

[0052] The downhole tool 306.1 is placed in a vertical wellbore 336.1 in the vicinity of the gas-saturated sand reservoir 304.1 to perform downhole measurements. Packers 307 are placed in the barrel 336.1 to isolate part of it that is directly close to the perforation 338.2. As soon as perforations are created near the well, the fluid can be pumped through the perforation in the formation to create and (or) expand gaps in it to stimulate the productivity of the reservoir.

[0053] The reservoir 304.4 of formation 302.2 was perforated, and the packers 307 were positioned so as to isolate the barrel 336.2 near the perforation 338.3-338.5. As shown in horizontal trunk 336.2, packers 307 were placed in steps St ₁ and St ₂ in the trunk. As also illustrated, wellbore 304.3 may be a peripheral (test) well passing through formation 302.2 to reach reservoir 304.4. One or more shafts can be placed on one or more drilling sites. If necessary, many trunks can be placed.

[0054] The fractures may be extended to various reservoir reservoirs 304.1-304.4 to facilitate the production of fluids from them. Examples of fractures that can be formed are schematically illustrated in Figures 3B-3D near the barrel 304. As illustrated in Figures 3B-3C, mechanical inhomogeneities 340, such as natural cracks, bedding surfaces, faults, and weakening planes, propagate further into the formation layers. Natural cracks, as described herein, refer to planar heterogeneities of a formation having properties different from those surrounding the formation. Aperture (or perforation clusters) 342 can be formed around the barrel 304, and fluids 344 and / or fluids mixed with proppant 346 can be pumped through this perforation 342. As shown in Figures 3B-3C, fracturing can be performed by injection through perforation 342, thereby creating cracks along the plane of greatest stress σ _hmax and opening and continuing natural cracks.

[0055] On the surface of the working platform illustrated in Figure 3B, near the wellhead 308.4, an injection system 329 is placed to pass fluids 344 and / or fluids mixed with propant 346 through conduit 315 into the interior.

[0056] The injection system 329 is illustrated as being managed by an operator 327 for recording system and operational data and / or performing maintenance in accordance with a prescribed maintenance plan. Injection system 329 pumps fluid 344 from the surface into wellbore 304 during oilfield operations.

[0057] One embodiment: injection system 329 may comprise several water tanks 331 supplying water to a gel hydration unit 333. A gel hydration unit 333 mixes water from tanks 331 with a gel agent to create a gel. The gel is then fed into a mixer 335, where it is mixed with the proppant from the proppant transfer unit 337 to create a hydraulic fracturing fluid 344. A gel agent can be used to increase the viscosity of the hydraulic fracturing fluid and to allow suspension of the proppant in the hydraulic fracturing fluid. It can also work as a friction reducing agent to create the possibility of high discharge costs with less friction losses. The gel hydration unit 333 may mix additional liquid additives with water to create a fracture fluid 344 with specific properties.

[0058] Then, the fracture fluid 344 is pumped from the mixer 135 to the treatment station 320 using reciprocating pumps, as shown by solid lines 343. Each processing station 320 receives the fracture fluid at low pressure and discharges it into a common manifold 339 (sometimes called a projectile trailer or projectile) at high pressure, as shown by dashed lines 341. Projectile 339 then directs fracture fluid from processing stations 320 to well 304, as shown by solid line 315. To support the flow of fracture fluid, it is necessary At a flow rate, one or more processing stations 320 may be used.

[0059] Each processing station 320 may operate normally at any flow rate, such as maximum downhole flow rate. The management of processing stations 320 at their operational capacity may allow one of them to fail and continue to operate at a higher speed for operation in the absence of a failed pump. As shown, a computerized control system 345 can be used to direct the entire injection system 329 during fracturing.

[0060] Figure 3D illustrates another type of fracturing activity near well 304. Here you can see the created fractures 348 radially diverging from the well 304. The created fractures can be used to achieve a group of 351 microseismic events (shown schematically as points) near the well 304. Fracturing operations can be used as part of stimulation activities to provide the ability to facilitate the movement of hydrocarbons in well 304 for its operation.

[0061] Returning to Figure 3A, sensors (S) can be placed near the field to collect data related to various activities, as described above. Some sensors, such as geophones, can be placed near the formation during fracturing to measure microseismic waves and perform microseismic mapping. Data collected by sensors can be collected using surface unit 334 and / or other sources of collected data for analysis and other processing as described above (see, for example, surface unit 134). As shown, the surface unit 334 is connected to a network 352 and other computers 354.

[0062] The stimulation tool 350 may be performed as part of a surface unit 334 or other part of the well site to perform stimulation work. For example, information generated during one or more stimulation activities can be used in drilling planning for one or more wells, one or more drilling sites and / or for one or more fields. The stimulation tool 350 may be operatively connected to one or more drilling rigs and / or drilling sites, and used to receive data, process data, send control signals, etc., as will be described below. The stimulation tool 350 may include a reservoir description block 363 for creating a model of the mechanical properties of the geological environment (MMSS), stimulation planning block 365 for creating stimulation plans, an optimizer 367 for optimizing stimulation plans, a real-time block 369 for real-time optimization of the optimized stimulation plan , control unit 368 for selectively adjusting stimulation activities based on a real-time optimized stimulation plan, updater 370 for updating the geo model th-physical characteristics of the reservoir, based on optimized in terms of real-time stimulation and retrospective evaluation of data, and a calibrator 372 for calibrating an optimized stimulation plan, as will be described below. Stimulation planning unit 365 may include a stage change tool 381 for performing stage changes, a stimulation procedure change tool 383 to make changes to the stimulation, a performance prediction tool 385 for predicting performance, and a drilling planning tool 387 for creating drilling plans.

[0063] The data of the well site used in stimulation works can vary: from, for example, core samples for a petrophysical interpretation based on logs to three-dimensional seismic data (see, for example, Figures 2A-2D). Changes in the stimulation procedure may require the involvement, for example, of petroleum petro-technical specialists to combine manual processes for comparing different pieces of information. Integration of information may involve manual manipulation of disconnected work processes and outputs, such as determining the boundaries of reservoir zones, identifying the required completion zones, assessing the expected fracture growth for a given configuration of completion equipment, deciding where and when to place the next well or multiple wells for better stimulation of the formation, and others. These changes to the stimulation procedure may also include semi-automatic or automatic integration, feedback, and control to facilitate stimulation work.

[0064] Stimulation work for traditional and unconventional reservoirs may be performed based on knowledge of the reservoir. Determining the characteristics of the reservoir can be used, for example, in drilling planning, determining the optimal target zones for perforation and stratigraphy, changing many wells (for example, the interval between them and orientation) and geomechanical models. Changes in the stimulation procedure can be optimized based on the final prediction of productivity. These changes in the stimulation procedure may involve the use of an integrated reservoir-centric workflow, including the change, in real time (RV) and after processing, of the evaluation components. Well completions and changes in stimulation procedures can be performed using a multidisciplinary well and reservoir data.

[0065] Figure 4A is a schematic flowchart 400 illustrating stimulation operations, such as those illustrated in Figure 3A. Flowchart 400 is an iterative process that uses integrated information and analysis to modify, apply, and update stimulation work procedures. The method utilizes pre-processing / pre-stimulation assessment 445, stimulation planning 447, real-time processing optimization 451, and updating execution / model 453. Part or all of the flowchart 400 may be iterated to fine-tune stimulation operations and / or perform additional stimulation operations in existing or additional wells.

[0066] Evaluation 445 of preliminary stimulation includes determining 460 characteristics of the reservoir and creating 462 three-dimensional models of the mechanical properties of the geological environment (MMSS). The determination of 460 reservoir characteristics can be created by integrating information, such as the information collected in Figures 1A-1D, to create a model using a combined combination of archive-independent technological regimes or work directions (e.g., petrophysics, geology, geomechanics and geophysics, as well as the results of the previous hydraulic fracturing treatment of the formation). Such a determination of reservoir reservoir characteristics 460 can be created using integrated static modeling techniques to create the IMSS 462, as described, for example, in patent applications US 2009/0187391 and 2011/060572, which are incorporated herein by reference in their entirety. As an example, software such as the commercially available PETREL ™, VISAGE ™, TECHLOG ™, and GEOFRAME ™ packages from SCHLUMBERGER ™ can be used to perform 445 preprocessing evaluations.

[0067] In describing the 460 characteristics of the reservoir, various types of information can be used, such as data associated with the underground formation, as well as the development of one or more reservoir models. The information collected may contain, for example, a reservoir zone (productive), geomechanical (stresses, elasticities and the like) zones, geometric (orientation of faults and their size) distribution of mechanical heterogeneities (natural faults) in the formation, and mechanical proper (permeability, cohesion , tension, crack density, tensile strength and the like) heterogeneity. A description of the 460 characteristics of the reservoir can be made so that information regarding stimulation activities is included in the preliminary stimulation assessment. Creation of a 462 MSMSS can stimulate an underground formation under development (for example, creating a digital representation of the state of stresses and mechanical properties of a formation for a given stratigraphic section of a field or reservoir).

[0068] To create 462 MSMSS can be applied to the traditional geomechanical modeling. Examples of MSMSS techniques are described in US Patent Application No. 2009/0187391, which is incorporated herein in full by reference. MMSS 462 can be created using information collected using, for example, oilfield work in Figures 1A-1D, 2A-2D and 3A-3D. For example, a three-dimensional MSGS may take into account a variety of reservoir data collected previously, including seismic data collected during early formation exploration, and logging data collected when one or more exploration wells were drilled before production (see, for example, Figure 1A- 1D). MMSS 462 can be used to provide, for example, geomechanical information for a variety of oilfield operations, such as selecting a casing point, optimizing the number of casing strings, drilling stable shafts, changing completion, performing fracturing stimulation, etc.

[0069] Created by the IMSHS 462 can be used as input when performing stimulation planning 447. To identify areas potentially beneficial for drilling, a three-dimensional MSMS can be constructed. In one embodiment of the invention, if the formation is practically homogeneous and practically does not contain large natural faults and (or) high-stress screens, it can be assumed that a given volume of fracture fluid pumped at a given flow rate for a given period of time will create almost the same network cracks in the formation. In another embodiment of the invention, if the formation contains a complex network of mechanical heterogeneities and (or) highly stressed screens, the necessary stimulated region, volume and (or) volume form can be achieved by setting at least one of such parameters as fluid viscosity media, discharge flow rate and additives to reduce water loss in order to optimize the behavior of the transition between the created gaps and heterogeneities already existing in the formation. Seismic data 202, such as those shown in Figures 1A and 2A, can provide useful information when analyzing formation fracture properties.

[0070] Planning 447 stimulation jobs may use drilling planning 465, changing stages 466, changes to stimulation procedure 468, and predicting 470 performance. In particular, the IMSHS 462 may be an input for planning 465 drilling and / or changing 466 stages and changing the stimulation procedure 468. Some embodiments of the invention may include semi-automatic methods for recognizing, for example, the intervals between the wells and their orientation, changing the multi-stage perforation and changing the fracturing procedure. With regard to the wide variation in the characteristics of hydrocarbon reservoirs, some embodiments of the invention may use methods for target reservoir environments, such as, but not limited to, gas saturated reservoirs, sandstone reservoirs, naturally cracked shale reservoirs, or other atypical reservoirs.

[0071] Planning 447 stimulation activities can use the semi-automatic method used to identify areas potentially beneficial for drilling out by dividing the underground formation into multiple discrete intervals, describing the characteristics of each interval based on information such as the geophysical properties of the formation and its proximity to natural fractures, then rearrangement of multiple intervals into one or a plurality of drillable sections, with each section of the well or branch of the well being obtained. The spacing and orientation of multiple wells can be determined and used to optimize reservoir productivity. The characteristics of each well can be analyzed to plan the stages and plan the stimulation procedure. In some cases, a completion consultant may be involved, for example, to analyze vertical or subvertical wells in gas-saturated sandstones, followed by a refinement of the workflow.

[0072] Drilling planning 465 may be performed to change the oilfield work prior to performing the actual work itself at the drilling site. Drilling planning 465 can be used to determine, for example, equipment and operating parameters for performing oilfield operations. Some of these operating parameters may include, for example, perforation locations, injection flow rate, operating pressure, stimulation fluids, and other parameters used in stimulation. In changing the drilling plan, information collected from various sources, such as archival data, known data and oilfield measurements (for example, such as those obtained in Figures 1A-1D) can be used. In some cases, modeling can be used to analyze the data used in creating the drilling plan. A drilling plan created during stimulation planning can receive data on changes in 466 stages, changes in stimulation procedure 468 and prediction of 470 productivity so that information related to stimulation and (or) affecting it is estimated in the drilling plan.

[0073] As an input to the change of stages 466, drilling planning and / or MMSCS 462 can also be used 465. Reservoir data and other data can be used to change 466 stages to determine some operational parameters for stimulation. For example, a change of 466 stages may use the definition of boundaries in the well to perform stimulation work, as will be described below. Examples of stage changes are described in US Patent Application No. 2011/0247824, which is incorporated herein in its entirety by reference. The change of stages may be an input to perform a change in the procedure 468 stimulation.

[0074] A change in the stimulation procedure determines numerous stimulation parameters (for example, the location of the perforation area) to perform stimulation work. Modification of the stimulation procedure 468 can be used, for example, to model fracturing. Examples of fracturing modeling are described in US patent applications. 2008/0183451, 2006/0015310 and PCT Application No. WO2011 / 077227, which are incorporated herein in full by reference. The procedure for the stimulation procedure may involve the use of different models to determine the stimulation plan and (or) the stimulation part of the drilling plan. Further examples of modeling complex breaks are provided in SPE Paper 140185, which is incorporated herein by reference in its entirety. This modeling of complex fractures illustrates the use of two techniques for modeling complex fractures in combination with microseismic mapping to describe the complexity of cracks and evaluate completion completion. The first technique for modeling complex fractures is an analytical model for assessing the complexity of fractures and the distances between orthogonal cracks. The second technique uses a coordinate-referenced digital model that enables complex geological description and assessment of the complexity of crack propagation. These examples illustrate how embodiments of the invention can be used to evaluate how changes in hydraulic fracturing processing affect fracture complexity for each geological environment. In order to quantify the impact of changes in the fracturing procedure using complex fracture models, despite the inherent uncertainties and “real” crack growth in the MSHS, microseismic mapping and modeling of complex fractures can be combined to interpret microseismic measurements while calibrating the complex stimulation model. Such examples show that the proportion of complex fractures may vary depending on geological conditions.

[0075] The stimulation procedure diagram may integrate three-dimensional reservoir models (formation models), which may be the result of seismic interpolation, interpretation of geosteering, a model of a geological or geomechanical medium as a starting point (zone model) for a well completion scheme. For some stimulation schemes, a fracture modeling algorithm can be used to read three-dimensional MMSSs and further modeling to predict crack growth. This process can be used to take into account the spatial heterogeneity of complex reservoirs during stimulation work.

[0076] In simulation circuit 468, microseismic mapping can also be used to understand the process of growing complex cracks. Some workflows can integrate these fracture forecasting models into a single three-dimensional picture where microseismic events are superimposed (see, for example, Figure 3D), which can be used in the fracturing scheme and (or) its calibrations. Natural cracks and part of complex fractures can be evaluated using microseismic mapping and then optimized as described herein.

[0077] Natural fractures and part of complex fractures can be analyzed to select the optimal stimulation scheme and completion strategy. Fracture modeling can be used to predict the geometry of cracks that can be calibrated, and the circuit is optimized based on microseismic mapping and real-time estimation. Fracture growth can be interpreted based on existing models of formation hydraulic fracturing. Some of the modeling of the propagation of complex fractures and / or interpretation can also be performed for unconventional reservoirs (for example, gas saturated sandstones and shales), as will be described below. The reservoir properties and initial modeling assumptions can be corrected, and the fracture pattern is optimized based on microseismic estimates.

[0078] In predicting 470 productivity, a productivity estimate based on drilling planning 465, changing 466 stages, and stimulation procedure 468 can be used. The result of stimulation scheme 468 (i.e., fracture simulation models and input reservoir models) can be brought into the productivity prediction workflow, where a traditional analytical or numerical reservoir simulator can operate with models and predictions of hydrocarbon productivity based on dynamic data. Initial prediction 470 may be useful, for example, to quantify the stimulation planning process 447.

[0079] Part or all of the stimulation planning 447 may be performed multiple times, as shown by the wavy arrows in Figure 4A. As shown, optimizations can be performed after changing 466 stages, changing stimulation scheme 468 and predicting productivity 470, and can be used as feedback 472 to optimize drilling planning 465, stage scheme 466 and / or stimulation scheme 468. Optimizations that can be selectively performed for feedback are the result of part or all of the stimulation planning 447, and are repeated many times if necessary in different parts of the stimulation planning process, achieving an optimized result. Stimulation planning 447 can be done manually or integrated using an automatic optimization process, as schematically shown by optimization 472 in feedback loop 473.

[0080] Figure 4B schematically illustrates part of the planning work 447 stimulation. As illustrated in the figure, the stage diagram 446, the stimulation scheme 468, and the productivity prediction 473 can be repeated many times in the feedback loop 470 and optimized 472 to achieve an optimal result 480, such as an optimized stimulation plan with optimized transition behavior. With this iterative method, the initial data and results are generated using the stage scheme 466 and the stimulation scheme 468 for “learning from each other” and repeating with productivity prediction for optimization between them.

[0081] The different parts of the stimulation work may be changed and / or optimized. Examples of optimized fractures are described, for example, in US Pat. 6508307, which is incorporated herein in full by reference. In another example, an input to planning 447 of stimulation of financial indicators, such as the costs of hydraulic fracturing (constant and variable), oil and natural gas futures, and gross profit indicators, each of which can affect the work, can also be provided. Optimization can be done by optimizing the stimulation scheme 466 with respect to the predicted performance, taking into account the size of the financial investments. Such financial investments may involve the costs of stimulation work in the well at various stages.

[0082] Returning to Figure 4A, various optional details may be included in stimulation planning 447. For example, a multi-well planning consultant may be involved in determining the need to drill a formation in multiple wells. If multiple wells are to be developed, the multi-well planning consultant can determine the spacing and orientation of the wells, as well as the best placement in each formation to be perforated and processed. As used herein, the term "multiple wells" may refer to a plurality of wells, each of which is independently drilled from the surface of the earth to an underground formation; this term may also refer to a plurality of branches discharged from a single well drilled from the surface of the earth (see, for example, Figure 3A). Orientation of the well and branches can be vertical, horizontal or any intermediate.

[0083] After many wells are planned or drilled, simulation can be repeated for each well so that each of them has a stage plan, perforation plan and / or stimulation plan. After that, many wells can be adjusted if necessary. For example, if fracturing stimulation in one well shows that the stimulation result will be blocked by the nearest well with the planned perforation zone, the nearest well and (or) its planned perforation zone may be excluded or processed. Conversely, if a simulated hydraulic fracturing treatment cannot penetrate a specific area of the formation, because the productive zone is simply too far from the first fracture well to stimulate the productive zone effectively, or because the existence of natural cracks or highly stressed screens prevents the first fracture well from effectively stimulating the productive zone, a second well / branch or a new perforation zone may be included to provide access to the untreated area. A three-dimensional reservoir model can take into account simulation models, and show the potential location for drilling a second well / branch or to add an additional perforation zone. For convenience, the control of the oilfield processing operator may use the spatial arrangement “X′-Y′-Z”.

MODELING OF CROSSING BETWEEN HYDRAULIC FRACTURES AND NATURAL CRACKS

[0084] Considering leakage of the fracture fluid into the formation, leakage into natural fractures (PTs) is also considered, especially in conditions of low primary permeability. Natural cracks affect the spread of hydraulic fracturing (GR) in different directions. The main aspect leading to the creation of a complex network of hydraulic fractures during hydraulic fracturing stimulation is the possibility of branching hydraulic fractures at the corresponding intersections of hydraulic fractures with natural fractures. Another aspect in which natural fractures affect the fracture geometry is their effect on the flow of fluid from the fracture into permeable natural fractures, leading to a reduction in fracture length.

[0085] Figures 5.1-5.4 illustrate an example of a fracture growth pattern. As illustrated in Figure 5.1, in its initial stage, a network of gaps 506.1 with natural fissures 523 is located near an underground formation 502 with a trunk 504 passing through it. As the proppant is injected into the underground formation 502 from the barrel 504, the pressure from the proppant creates artificially created hydraulic fractures 591 near the barrel 504. The artificially created hydraulic fractures 591 continue into the underground formation 502 along the length L ₁ and length L ₂ (Figure 5.2), and collide with other cracks in the network 506.1 cracks over time, as shown in Figures 5.2-5.3. Contact points with other gaps are intersections 525.

[0086] Hydraulic fracturing can continue from the bore 504 to the natural fracture network of the underground formation 502 to create a fracture network 506.4 containing natural fractures 523 and artificially created fractures 591, as shown in Figure 5.4. The fracture growth pattern is based on the parameters of natural cracks, the minimum and maximum stresses of the underground formation 502.

[0087] As shown in Figures 5.1-5.4, intersections 525 between artificially generated fractures 591 and natural fractures 523 can cause certain transition behavior in several scenarios: (i) the artificially created fracture can continue to propagate after colliding with a natural fracture at the intersection; (ii) an artificially created hydraulic fracture can stop in the collision with a natural fracture or propagate along part of this fracture after stopping; or (iii) an artificially created hydraulic fracture can propagate along a natural fracture that collides with it at a distance, and then branch off from it by a certain distance of the indent from the intersection point. The behavior of the intersection or intersections between natural fractures and artificially created hydraulic fractures depends on various factors, such as, for example, the geometric properties of the reservoir, limiting stresses, effective pressure, friction coefficient, the connectivity properties of existing natural fractures, the viscosity of the fracture fluid, and injection fluid flow rate and the presence and content of additives to reduce fluid loss in the fracture fluid.

[0088] Depending on the borehole conditions, the fracture growth pattern may be unchanged or changed when a fracture collides with a natural fracture (ie, “colliding fractures”). If the fracture pressure is greater than the stress acting on the encountered fracture, the fracture growth pattern may propagate along a encountered crack. The fracture growth pattern may continue to propagate along the encountered crack to its end. The fracture growth pattern can change direction from the end of the natural fracture, with the fracture growth pattern continuing in the normal direction to minimize stress at the end of the natural fracture. As illustrated in Figure 5.4, artificially created fracturing continues in a new direction 527 in accordance with the local stress σ ₁ and σ ₂ .

[0089] When an artificial fracture (GR) intersects a natural fracture, the pressure of the fluid in the fracture can be transferred to the natural fracture. If the fluid pressure is less than the normal stress in a natural crack, the natural crack may remain closed. Even a closed natural fracture can have hydraulic connectivity greater than the surrounding rock skeleton, in which case the fracture fluid can burst into natural cracks in an amount greater than the outflow into the surrounding rock skeleton. Due to the loss of fracture fluid in closed natural fractures, the main fracture may have a smaller volume of fracture fluid available for further growth of the fracture.

[0090] For closed fractures, changes with fluid pressure can be expected to be equivalent to liquid permeability, since contact deformation is a function of effective normal stress. This dilatancy caused by pressure and the associated increase in connectivity can increase the flow through some sections of the natural crack paths that can be subjected to compression of the contact stress. Also, any decrease in the effective contact stress can lead to the sliding of cracks, which can lead to local changes in stress and caused by slippage expansion of gaps, which can, in turn, change the overall connectivity of the networks of cracks. This connectivity caused by shear slippage can increase pressure transmission in natural fractures, and can allow microseismic events to be triggered at a distance from actual fractures to natural fractures, which have a relatively low initial permeability.

[0091] Various regions or zones may coexist along natural fractures trapped by artificially created fractures. For example, areas along natural fractures may contain hydraulically open areas filled with fracture fluid, still closed regions of the natural fracture, but with bursting fracture fluid and / or pressure caused by the permeability of the natural fracture, and the area of the natural fracture filled with the original fluid reservoir medium. Figure 7 illustrates more information about different areas or zones.

[0092] Figure 6 illustrates a complex fracturing network 600 with microseismic events 630 caused by the outflow of fracture fluid 640 into natural fractures 650. In a manner similar to Figures 5.1-5.4, fracture fluid can flow into natural fractures at intersections 605 with fractures 620, and for cases of intersection of a natural fracture by hydraulic fracturing, and for the case of the propagation of hydraulic fractures along a natural fracture. Outflow 640 of fracturing fluid can cause fluid pressure in natural fractures 650, raising it above the original pore pressure. The raised pore pressure can reduce the limiting stresses in natural cracks 650 and cause shear slippage along the corresponding natural crack. This shear slip may be the primary mechanism for triggering microseismic events 630.

[0093] A more accurate and reliable prediction of the geometry of complex cracks can be obtained by implementing a simulation of fluid loss in natural cracks. By simulating fluid losses in natural fractures, for example, the penetration of a fracture fluid into natural fractures and the rock skeleton surrounding the fractures can be calculated. This fluid penetration can be used in the return flow and cleaning of the fracturing fluid when the well is completed, and can be performed for extremely tight permeable reservoirs where the injected fluid can block gas during well operation. Given the initial saturation of the fracture fluid in the reservoir simulation model, an estimate of productivity can be obtained. Using fluid pressure modeling in natural cracks, the conditions for possible shear slippage along natural cracks can be estimated, and the probability of microseismic events can be estimated and predicted, which can provide a direct connection between the predicted fracture geometry and microseismic descent mechanisms.

[0094] Figure 7 illustrates the intersection 700 between the artificially created hydraulic fracture 720 and the encountered natural fracture 705, and the area / zone along the intersected natural fracture 705. Four intersection zones, in particular, are presented as follows:

[0095] (1) The open zone 715 (also called the open part) of the crossed natural fracture 705 is filled with bursting fracture fluid. In open zone 715, fluid pressure may exceed the normal stress of crossed natural crack 705. The initial length 760 (also called L _opened ) of open zone 715 can be estimated from the compensation volume taken into account for crossed natural crack 705 and fluid properties that may contain the corresponding end of the asymptote. The width, pressure, height, outflow volume, pulp volume and other parameters of individual areas in the open zone 715 can be calculated from a combination of the flow equation (for example, laminar, turbulent, Darcy, etc.), the continuity equation and the elasticity equation. These calculations can also take into account height growth, transportation of proppant and its outflow.

[0096] (2) The closed penetration zone 725 (also called the “flooded closed portion of the PT” or “filtration zone”) of the crossed natural fracture 705 is filled with a fracture fluid. In the unaltered closed region 725, the fluid pressure may be higher than the pore pressure, but lower than the closing stress of the crossed natural crack 705. The initial length 770 of the closed penetration region 725 can be estimated based on Equation (5) see below, which may explain the outflow of the fracture fluid into the reservoir. The velocity of the filtration front of the closed penetration region 725 can be estimated to track the separation between the filtration zones (for example, the closed penetration region 725) and the sealed zones (for example, unchanged by the closed region 735). To evaluate the length, pressure, width, height and volume within the closed penetration region 725, considerations of pressure-independent permeability, continuity, Darcy coefficient, rock outflow, and compressibility can be taken into account.

[0097] (3) The unchanged closed region 735 (also called the “closed part under pressure” or “region under pressure”) of the crossed natural fracture 705 is filled with the original reservoir fluid pressure and does not contain a leaking fracture fluid. In the unaltered closed region 735, the fluid pressure may be higher than pore pressure. The initial length 780 (also called L _pressurized ) of the unaltered closed area 735 can be estimated based on the pressure and flow rate between the closed penetration area 725 and the unchanged closed area 735. The outflow into the rock skeleton from the unchanged closed area 735 can be controlled by compressibility. The governing equations for the unaltered closed region 735 may include equations for continuity, compressibility, Darcy coefficient, pressure and permeability permeability.

[0098] (4) The closed undisturbed zone 745 (also called the “reservoir zone”) of the encountered natural fracture 705 is filled with reservoir fluid under initial pore pressure.

[0099] In the simulation, simulations can update the zones of natural cracks, various section surfaces, and inter-surface properties related to different intersection zones. For example, the front of the closed penetration region 725 and the front of the unaltered closed region 735 can be moved to different points of the corresponding natural crack at different time steps. Partition fronts can be updated based on continuity (mass balance), compressibility considerations, and other intersection parameters. If the outflow from the closed area 725 of penetration into the rock skeleton is negligible, for example, then there may be an uncompressed area corresponding to the unchanged closed area 735.

[00100] In formations with a network of complex individual fractures, a separate assessment of intersections can be made between the closed penetration region 725 / unchanged closed region 735, the open zone 715 / closed penetration region 725, and the closed zone 715 and the open zone 715 fracturing 720. Mass balance and fluid continuity conditions can be satisfied, and corresponding rules for propagating zone boundaries through intersections 700 can be preliminarily described.

[00101] Explicit modeling of hydraulic fractures interacting with permeable natural fractures can be complicated when modeling can include certain intersection properties, such as continuity of fluid mass in a natural fracture, pressure surges along natural fractures, outflow into a formation through walls of natural fractures, and permeability of natural fractures due to changes in pressure, properties and content of natural cracks and fluid rheology of natural cracks. This simulation can be done by tracking zone boundaries along filled natural fractures.

[00102] Depending on the rocks and properties of the reservoir, modeling of zones (1), (2) and (3) can be performed using various equations.

[00103] The continuity of the mass of fluid in a natural fracture can be determined using the following equation:

Уравнение (1)

Equation (1)

- общий коэффициент оттока из закрытой зоны проникновения и зоны пласт-коллектора; и ρ_f - плотность фильтрующейся текучей среды в природной трещине.where q_m(t) is the mass flow (rate of change of fluid mass) in a natural crack; s is the increment of length along a natural crack; q_L - volumetric flow rate of the outflow per unit length; m is the mass of the fluid in the natural fracture; h is the height of the natural crack;

- the total coefficient of outflow from the closed zone of penetration and the zone of the reservoir; and ρ_f - density of the filtered fluid in a natural crack.

[00104] A pressure surge along a closed natural fracture can be determined using the following equation:

where k _NF is the permeability of a closed natural crack; µ _f is the viscosity of the filtered fluid in a closed natural crack; p _f is the density of the filtered fluid in a closed natural crack; A is the cross-sectional area of a closed natural crack, where A = wh, and where w is the effective (or average) width of the natural crack, and h is the effective height of the natural crack; p _in - inlet pressure; and q is the mass flow in a natural fracture.

[00105] The permeability of a natural crack caused by stress and a change in pressure can be determined by the following equation:

Уравнение (3)

Equation (3)

where the constants C and σ ^* (the corresponding state of stress) are determined from field data; k ₀ - permeability of the natural fracture (permeability of the reservoir in the conditions of natural occurrence); σ _n is the normal stress in a natural crack (i.e., where n means normal stress); and p is the pressure in the natural fracture.

[00106] The width of a closed waterlogged natural crack, w (s), as a function of distance along a natural crack, s, can be determined using the following equation:

Уравнение (4)

Equation (4)

where σ _eff is the normal stress in a natural crack; σ _ref ⁿ is the effective reference stress in a natural crack; w0 is the initial crack aperture; and p _f (s) is a function of distance along a natural crack.

[00107] Sliding friction can occur when shear stress reaches the ultimate tensile strength in natural cracks. Sliding can lead to an increase in the fracture in the shear regime and can increase until other cracks open that the fracture crosses. For a closed waterlogged crack, the effective stress can be reduced with increasing pressure, which can lead to a reduced tensile strength and shear slip. To calculate the friction stress and the conditions for shear slip, the Columbian law of friction can be applied. Shear slippage can be determined to enhance outflow and can lead to a displacement in the growth of the gap, as well as an alignment indicator for microseismic events. Shear slippage can also cause the expansion of the natural crack to increase the effective width w (s), which can lead to increased permeability and connectivity of the natural crack and help increase hydrocarbon productivity.

[00108] When taking into account the outflow of fracturing fluid into the reservoir through the walls of a natural well, the length 770 of the closed penetration zone 725 can be estimated using the following equation:

Уравнение (5)[00109]

Equation (5)

where Q _in is the initial flow rate of the fracture into the closed zone 725 of penetration from the open zone 715; w _litr is the average width of the closed zone 725 penetration; h is the height of the natural crack; t is the penetration time; and C _L = C _tot ^rock is the total outflow coefficient for the closed zone 725 penetration and zone 745 reservoir.

[00110] A change in fluid density as a function of pressure and temperature can be determined by the following equation:

Уравнение (6)

Equation (6)

where B is the bulk modulus of elasticity of the fluid in Pa, β is the coefficient of volume expansion, T ₀ is the temperature, and ρ ₀ is the density of the fluid at pressure p ₀ , T ₁ is the temperature, and ρ ₁ is the density of the fluid at pressure p ₁ .

[00111] The above equations can be solved analytically at a given time stage (ie, a reference point in time at which a fracturing network is simulated) for lengths and pressure surges in specific intersection zones. The above equations can also be solved using average properties for a given zone. The permeability of natural cracks can also be updated based on changes in pressure and shear slip for a given time interval (i.e., from the next time step). Solutions can also be obtained by solving these equations numerically by discretizing a natural crack into smaller elements. For example, mass balance, fluid loss in the rock skeleton, pressure jump in a natural fracture, improved permeability of a natural fracture leading to expansion and shear slip can be resolved and locally tracked on specific elements to obtain pressure distributions and fluid fronts in a natural fracture .

HYDRAULIC FRACTURING WORKS, BASED ON THE INTERSECTION PROPERTIES BETWEEN HYDRAULIC FRACTURES AND NATURAL CRACKS

[00112] Figure 8 illustrates a flowchart of a method 800 for simulating and performing hydraulic fracturing of a formation in accordance with various embodiments of the invention described herein. Obviously, although the working flowchart shows a specific order of operations, in other embodiments of the invention, operations may be performed in a different order. Further, in some embodiments of the invention, additional operations may be added to the method. Similarly, some operations or blocks may be omitted.

[00113] At block 810, integrated well data for the subterranean formation is obtained. Integrated well data may include geomechanical, geological, and / or geophysical properties of the subterranean formation. Integrated drilling data may also include the mechanical, geomechanical, and / or geometric properties of natural fractures in the formation.

[00114] At block 820, a model of the mechanical properties of the geological environment is created using integrated well data. The model of the mechanical properties of the geological environment contains a model, such as MMSS 462 described in Figure 4A.

[00115] At block 830, an intersection of one or more hydraulic fractures of one or more natural fractures is simulated. For example, simulation may include modeling the outflow of a fracture fluid from one or more artificially generated hydraulic fractures into one or more natural fractures. Also, in a simulated intersection, shear failure or shear slip of a natural crack can be modeled.

[00116] In one embodiment, the intersection simulation may include modeling one or more intersection zones as illustrated with reference to Figure 7. The intersection zones may comprise an open zone 715, a closed penetration area 725, an unchanged closed zone 735, or a closed undisturbed zone 745.

[00117] In another embodiment, the fracture growth pattern may be simulated at block 830. The fracture growth pattern may include modeling new intersections between natural fractures and artificially created fractures, as well as existing or previously created fractures. The simulated intersections may include updating various elements (i.e., intersection properties or changes in the inter-surface properties of intersected natural cracks) in one or more intersection zones at appropriate times. For example, a gradual expansion of the respective intersection zones in a natural crack can be simulated to show movement from a closed undisturbed zone to an open zone of a natural crack. This process may include modeling a crack growth pattern as described in FIGS. 5 and 6.

[00118] At block 840, one or more intersection properties are determined for the simulated intersection and / or intersected natural fracture at block 830. The intersection properties may relate to the modified intersurface properties of the intersected natural fracture, and may include specific properties related to modeling intersection zones or boundaries between zones of intersection. For example, one intersection property may include the amount of fracture fluid flowing from an artificially generated fracture into one or more natural fractures. Other intersection properties may be the length of the various intersection zones, the continuity of the mass of the fluid in the natural fracture, the outflow of the fracture fluid into the underground formation through the walls of the natural fracture, the permeability of the natural fracture due to pressure changes, the liquid rheology of the natural fracture, the change in the permeability of the natural fracture, the change in stress in the area of a natural crack or any other related properties.

[00119] At block 850, a stimulation plan is created using a model of the mechanical properties of the geological environment and one or more intersection properties. In the created stimulation plan, the intersection properties can be used as input in the same way as with the possible use of the model of mechanical properties of the geological environment as an input for stimulation planning, as described in Figures 4A-4B. For example, the amount of fluid flowing from a fracture into one or more natural fractures can be used to determine a stimulation plan with a discharge flow rate of a fracture taking into account the amount of outflow. Figures 4A-4B illustrate more information about planning and modifying stimulation.

[00120] At block 855, one or more operating parameters may be adjusted to obtain one or more intersection properties. Operating parameters may include fracture fluid viscosity, fracture fluid injection flow rate, one or more components in the fracture fluid, one or more additives in the fracture fluid, which may affect the outflow properties, the size of the proppant in the fracture fluid, and the content of the proppant in burst fluid or any other operating parameters.

[00121] The optimized intersection properties may be the same as or different from block 840. For example, the intersection property can be optimized to achieve a predetermined value for the corresponding intersection property or other intersection property (for example, adjusting the amount of outflow into a natural crack can be used to obtain optimized permeability of a natural crack). Optimized intersection properties can also be used to achieve specific results, such as increasing reservoir permeability.

[00122] At block 860, stimulation works based on the stimulation plan from block 850 or the adjusted stimulation plan from block 855 are performed. The stimulation works can be performed using the methods described in Figures 1-4B. For accuracy, reliability, or any other criteria, simulated intersections from block 830 can be verified using the observed data obtained from stimulation work.

[00123] At block 870, one or more intersection properties are compared with microseismic events in the observed data during stimulation operations from block 860.

[00124] At block 880, the hydrocarbon productivity of the subterranean formation is predicted using one or more intersection properties.

COMPUTER SYSTEM

[00125] Implementations of the various technologies described herein may be performed with multiple computing system environments or general or specific purpose configurations. Examples of well-known computer systems, environments, and / or configurations that may be suitable for use with the various technologies described herein include, but are not limited to, personal computers, server computers, handheld or knee devices, multiprocessor systems, microprocessor based systems , attachments, programmable consumer electronics, network PCs, minicomputers, mainframes, smartphones, smart watches, personal portable computer systems related over a network with other computing systems, tablet computers and distributed computing environments including any of the systems or devices mentioned, etc.

[00126] The various technologies described herein may be implemented in the general context of computer-executable instructions, such as program modules, being executed by a computer. In general, program modules include procedures, programs, objects, components, data structures, etc. that perform particular tasks or implement particular abstract data types. Although program modules can be executed on a single computer system, it is obvious that, in some embodiments of the invention, program modules can be implemented on separate computer systems or devices adapted to communicate with each other. A software module may also be some combination of hardware and software, where specific tasks performed by the software module can be performed using hardware software, or both.

[00127] The various technologies described herein can also be implemented in a distributed computing environment where tasks are performed using remotely-processing devices connected via a communications network, for example. by cable, wireless, or a combination thereof. Distributed computing environments can span multiple components and multiple carriers, ships, or boats. In a distributed computing environment, program modules can be located both locally and in a storage medium of a remote computer, including storage devices.

[00128] Figure 9 illustrates a schematic diagram of a computing system 900 in which various technologies described herein can be implemented and implemented. Although the computing system 900 may be a typical desktop or server computer, as described above, other computer system configurations may also be used.

[00129] The computer system 900 may include a central processing unit (CPU) 930, system memory 926, a graphics processor (GPU) 931, and a system bus 928 connecting various system components, including system memory 926 and CPU 930. Although one CPU is illustrated in Figure 9 It is obvious that some embodiments of the computing system 900 may include more than one CPU. GP 931 may be a microprocessor specially made for the operation and implementation of computer graphics. The CPU 930 may offload the work of the GPU 931. The GPU 931 may have its own graphics memory and / or may have access to part of the system memory 926. As with the CPU 930, the GPU 931 may contain one or more processing units, and the processing unit may contain one or more cores. The system bus 928 may be any of several types of bus structures, including a memory bus or memory controller, a peripheral bus, and a local bus using any of a variety of bus architectures. By way of example, but not limited to, such architectures include an industry standard architecture bus (ISA), microchannel architecture bus (MCA), an extended ISA bus (EISA), a local video electronic device standards association (VESA) bus, and a peripheral component communications bus ( PCI), also known as the Mezzanine bus. System memory 926 may include read-only memory (ROM) 912 and random access memory (RAM) 916. A basic input / output system (BIOS) 914 that contains basic procedures that assist in transferring information between elements in a computer system 900, such as startup time can be recorded in ROM 912.

[00130] Computing system 900 may also include a hard disk 950 for reading from and writing to a hard disk, a magnetic disk drive 952 for reading and writing to a removable magnetic disk 956, and an optical drive 954 for reading from and writing to a removable optical disk 958, such as a CD-ROM or other optical media. The hard disk 950, the magnetic disk drive 952, and the optical disk drive 954 can be connected to the system bus 928 using the hard disk interface 936, the magnetic disk drive interface 938, and the optical drive interface 940, respectively. Drives and related computer-readable media can provide a non-volatile storage of computer-readable instructions, data structures, program modules and other data for 900 computing systems.

[00131] Although the computing system 900, described herein as comprising a hard disk, a removable magnetic disk 956, and a removable optical disk 958, it will be apparent to one skilled in the art that the computing system 900 may also contain other types of computer-readable media to which may have access to a computer. For example, such a computer-readable medium may comprise computer storage medium and communication media. A computer storage medium may comprise volatile and non-volatile, as well as removable and non-removable media implemented in any method or technology for storing information, such as computer-readable instructions, data structures, program modules and other data. Computer-readable media may also include RAM, ROM, read-only programmable read-only memory (EPROM), read-only read-only programmable electronic memory (EEPROM), flash memory or other solid state memory technology, CD-ROM, DVD, or other optical media , magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other medium that can be used to store the necessary information and which can be accessed by the 900 computing system. Communication devices may provide computer-readable instructions, data structures, program modules and other data in a modulated data signal, such as a carrier wave or other transmission mechanism, and may include any information delivery medium. The term "modulated data signal" may mean a signal having one or more of the characteristics set or changed in such a way that the signal contains encoded information. By way of example, but not limited to, communication media may include cable means, such as cable networks or direct cable connections, and wireless means, such as acoustic, radio frequency, infrared, and other wireless means. Computing systems 900 may also include a host adapter 933 communicating with a storage device 935 via a Tale (SCSI) bus, fiber optic bus, eSATA bus, or any other suitable computer bus interface. The volume of computer-readable media also includes a combination of any of the above devices.

[00132] A plurality of program modules may be recorded on a hard disk 950, a magnetic disk 956, an optical disk 958, a ROM 912, or a RAM 916, including an operating system 918, one or more application programs 920, program data 924, and a database system 948. Applications 920 may include various mobile applications (“apps”) and other applications configured to perform various methods and techniques described herein. Operating system 918 may be any suitable operating system that may manage a networked personal or server computer, such as ^{Windows ® XP, Mac OS ® X} , Unix- like (e.g., Linux ^® and BSD ^®), and the like.

[00133] A user can enter commands and information into computing system 900 through input devices such as a keyboard 962 and pointing device 960. Other input devices may include a microphone, joystick, gamepad, satellite dish, scanner, and the like. These and other input devices can be connected to the CPU 930 via a serial port 942 interface that communicates with the system bus 928, but can be connected using other interfaces, such as a parallel port, game port, or universal serial bus (USB). A monitor 934 or other type of display device, such as a video adapter 932, may also be connected to the system bus 928. In addition to the monitor 934, the computing system 900 may also include other peripheral devices, such as speakers and printers.

[00134] In addition, the computing system 900 can operate in a networked environment using logical connections from one or more remote computers 974. Logical connections can be any connections that are common in offices, enterprise-wide computer networks, internal networks, and the Internet such as local area networks (LANs) 976 and wide area networks (WANs) 966. Remote computers 974 can be another computer, server computer, router, network PC, point device, or other host on a shared network, and can reap many of the elements described above relating to the computer system 900. The remote computer 974 may also each include application programs 970, similar to the computer operating functions.

[00135] When using a LAN environment, a computing system 900 may be connected to a local area network 976 via a network interface or adapter 944. When using a WAN network environment, a computing system 900 may include a router 964, a wireless router, or other means for establishing a message over a wide area network 966 such as the internet. Router 964, which may be internal or external, may be connected to the system bus 928 via the serial port interface 942. In a networked environment, program modules illustrated with respect to computing system 900 or parts thereof may be recorded to a remote storage device 972. Obviously, network connections are shown simply as examples, and other means of establishing communication between computers can be used.

[00136] The network interface 944 may also utilize remote access technologies (eg, Remote Access Service (RAS), Virtual Private Network (VPN), Secure Socket Layer (SSL), Dual Layer Tunneling (L2T), or any other suitable protocol). These remote access technologies can be implemented in conjunction with 974 remote computers.

[00137] It is obvious that the various technologies described herein can be implemented in conjunction with hardware, software, or a combination thereof. Thus, various technologies or their specific aspects or parts thereof can take the form of program code (i.e., instructions) implemented on tangible media such as floppy disks, CD-ROMs, hard drives or any other computer-readable storage device moreover, when the program code is downloaded by a machine, such as a computer, and executed by it, the machine becomes a device for implementing various technologies. If the program code is executed on programmable computers, the computing devices may comprise a processor, a storage device readable by the processor (including volatile and non-volatile memory and / or storage elements), at least one input device and at least one output device. One or more programs that can implement or use the various technologies described herein can use the application programming interface (API), reusable controls, and the like. Such programs can be implemented at a higher level in a procedural or object-oriented programming language for communicating with a computer system. However, if necessary, the program (s) can (gut) be implemented (s) in Assembler or machine language. In any case, the language may be a compiled or interpreted language, or combined with a hardware implementation. Also, the program code can be executed completely on user computing devices, partially on user computing devices, as a standalone software package, partially on a user computer and partially on a remote computer or completely on a remote computer or server computer.

[00138] It will be apparent to those skilled in the art that any of the architectures, details, or standards described above with respect to an example computing system 900 may be omitted for use with a computing system used in accordance with various embodiments of the invention described herein, as technology and standards continue to evolve.

[00139] Of course, for collected data types other than well site data, a variety of processing techniques for the collected data can also be fully used, including one or more of the techniques and methods described herein. Although specific embodiments of the invention have been described in the context of collecting and processing data from a well site, it will be apparent to those skilled in the art that one or more of the methods, techniques, and computing systems described herein can be applied in many areas and contexts where data structures arranged in three-dimensional space and (or) an interesting region of the subsoil should be collected and processed - for example, medical imaging techniques such as tomography, ultrasound, MRI and others like that, designed for human tissue; radar, sonar, and LIDAR imaging techniques; and others suitable for solving three-dimensional visualization issues.

[00140] Although the subject matter of the invention has been described in a language specifying structural details and (or) methodological actions, it is obvious that the subject matter defined in the attached claims is not limited to the above specific details or actions. Rather, the specific details and acts described above are disclosed as exemplary forms of implementing the claims.

[00141] Although the foregoing is directed to options for implementing the various technologies described herein, other and further options for their implementation can be developed without departing from its main scope. Although the subject matter of the invention has been described in a language specifying structural details and (or) methodological actions, it is obvious that the subject matter defined in the attached claims is limited to the specific details or actions set forth above. Rather, the specific details and acts described above are disclosed as exemplary forms of implementing the claims.

Claims (23)

1. A method for carrying out hydraulic fracturing of a formation near a drill drilling an underground formation, including:
obtaining integrated drilling data, while they may include the geomechanical properties of the underground formation and the geometric properties of one or more natural fractures in the underground formation;
creating a model of the mechanical properties of the geological environment using integrated drilling data;
simulation modeling of the intersection of one or more artificially created hydraulic fractures from one or more natural fractures using a model of the mechanical properties of the geological environment;
determining one or more intersection properties of intersected natural fissures; and
creating a stimulation plan using a model of the mechanical properties of the geological environment and one or more intersection properties. 2. The method according to claim 1, characterized in that one or more intersection properties includes the volume of the outflow of the fracture fluid from the artificially created hydraulic fracture into one or more natural fractures. 3. The method according to claim 1, characterized in that one or more intersection properties includes continuity of the mass of the fluid in the natural fracture, outflow of the fracture fluid into the underground formation through the walls of the natural fracture, permeability of the natural fracture due to pressure changes, liquid rheology of the natural fracture, a change in the permeability of a natural crack, a change in stress in a region of a natural crack, a change in pressure in a region of a natural crack, or a combination of the above. 4. The method according to claim 1, characterized in that the simulation of intersections includes modeling an open zone of a natural fracture filled with a fracture fluid from an artificially created hydraulic fracture, while the pressure of the fluid in the open zone exceeds the normal stress of a natural crack. 5. The method according to claim 1, characterized in that the simulation of intersections includes modeling the closed zone of a natural fracture trapped by a fracture fluid from an artificially created hydraulic fracture, while the fluid pressure in the closed zone exceeds the pore pressure of the natural fracture and is lower than the stress closing a natural crack. 6. The method according to claim 1, characterized in that the simulation of intersections includes modeling a closed zone of a natural fracture filled with the original reservoir fluid and not containing leaking fracture fluid, while the pressure of the fluid in the closed zone exceeds the pore pressure of the natural crack . 7. The method according to claim 1, additionally containing a simulation of the distribution of a network of artificially created hydraulic fractures. 8. The method according to claim 1, characterized in that the simulation of intersections includes modeling of shear fracture or shear slipping of a natural crack. 9. The method according to claim 1, characterized in that one or more intersection properties includes an increase in permeability in one or more natural fractures encountered by one or more artificially created hydraulic fractures. 10. The method according to claim 1, further comprising performing stimulation work based on a stimulation plan. 11. The method according to claim 10, further comprising verifying the simulation of intersections based on data obtained when performing stimulation works. 12. The method according to claim 1, characterized in that the stimulation plan may include viscosity or pressure flow of the fracture fluid. 13. The method of claim 10, further comprising adjusting at least one of such properties as viscosity and displacement fluid flow rate to optimize the properties of one or more intersections. 14. A method of carrying out hydraulic fracturing of a formation near a drill drilling an underground formation, comprising:
obtaining integrated drilling data, while they may include the geomechanical properties of the underground formation and the geometric properties of one or more natural fractures in the underground formation;
creating a model of the mechanical properties of the geological environment using integrated drilling data;
simulation modeling of the intersection of one or more artificially created hydraulic fractures from one or more natural fractures using a model of the mechanical properties of the geological environment;
determining one or more intersection properties of intersected natural fissures; and
predicting the hydrocarbon productivity of an underground formation using one or more intersection properties. 15. The method according to 14, characterized in that the prediction of hydrocarbon productivity uses observational data obtained during stimulation work performed on the basis of a model of the mechanical properties of the geological environment. 16. The method according to 14, characterized in that the prediction of hydrocarbon productivity includes predicting the permeability of the reservoir in the underground formation using one or more intersection properties. 17. The method according to 14, characterized in that the simulation of intersections includes at least the following:
modeling of the open zone of a natural crack filled with a fracture fluid from an artificially created hydraulic fracture, while the pressure of the fluid in the open zone exceeds the normal stress of a natural crack;
simulation of a closed zone of penetration of a natural crack into which a fracture fluid has penetrated from an artificially created hydraulic fracture, while the pressure of the fluid in the closed zone of penetration exceeds the pore pressure of a natural crack and lower than the closing stress of a natural crack; and
simulation of an unchanged closed zone of a natural fracture filled with the initial reservoir fluid and not containing leaking fracture fluid, while the pressure of the fluid in the unchanged closed zone exceeds the pore pressure of the natural crack. 18. The method according to 17, characterized in that the modeling of an open zone or one of the closed zones of natural cracks includes the use of one or more of the following parameters:
penetration rate of penetrating fracture fluid;
zone length in a natural crack;
zone width in a natural crack;
shear displacement;
fracturing aperture;
reservoir permeability;
permeability of a natural crack; and
pressure field. 19. A method of carrying out hydraulic fracturing of a formation near a drill drilling an underground formation, including:
obtaining integrated drilling data, while they may include the geomechanical properties of the underground formation and the geometric properties of one or more natural fractures in the underground formation;
creating a model of the mechanical properties of the geological environment using integrated drilling data;
simulation modeling of the intersection of one or more artificially created hydraulic fractures from one or more natural fractures using a model of the mechanical properties of the geological environment;
determining one or more intersection properties of intersected natural fissures; and
comparing one or more properties of intersections of gaps with microseisms in the observational data obtained during stimulation works based on modeling the mechanical properties of the geological environment. 20. The method according to claim 19, characterized in that the simulation of intersections includes at least the following:
modeling of the open zone of a natural crack filled with a fracture fluid from an artificially created hydraulic fracture, while the pressure of the fluid in the open zone exceeds the normal stress of a natural crack;
simulation of a closed zone of penetration of a natural crack into which a fracture fluid has penetrated from an artificially created hydraulic fracture, while the pressure of the fluid in the closed zone of penetration exceeds the pore pressure of a natural crack and lower than the closing stress of a natural crack; and
simulation of an unchanged closed zone of a natural fracture filled with the initial reservoir fluid and not containing leaking fracture fluid, while the pressure of the fluid in the unchanged closed zone exceeds the pore pressure of the natural crack. 21. A method for carrying out hydraulic fracturing of a formation near a drill drilling an underground formation, comprising:
obtaining integrated drilling data, while they may include the geomechanical properties of the underground formation and the geometric properties of one or more natural fractures in the underground formation;
creating a model of the mechanical properties of the geological environment using integrated drilling data;
simulation of the outflow of a fracture fluid from one or more artificially created hydraulic fractures into one or more natural fractures using a model of the mechanical properties of the geological environment;
development of a stimulation plan based on a model of the mechanical properties of the geological environment; and
adjusting one or more operating parameters of the stimulation plan based on a simulated fluid outflow to achieve an optimized outflow from one or more artificially created hydraulic fractures into one or more natural fractures. 22. The method according to item 21, wherein the one or more operating parameters of the stimulation plan includes at least one of such as:
fracture fluid viscosity;
discharge flow rate of the fracture fluid;
fracture fluid components;
fracture fluid additives affecting outflow properties;
proppant size in fracture fluid; and
propant content in the fracture fluid. 23. The method according to item 21, wherein the simulation of the outflow of the fracture fluid includes at least the following:
modeling of the open zone of a natural crack filled with a fracture fluid from an artificially created hydraulic fracture, while the pressure of the fluid in the open zone exceeds the normal stress of a natural crack;
simulation of a closed zone of penetration of a natural crack into which a fracture fluid has penetrated from an artificially created hydraulic fracture, while the pressure of the fluid in the closed zone of penetration exceeds the pore pressure of a natural crack and lower than the closing stress of a natural crack; and
simulation of an unchanged closed zone of a natural fracture filled with the initial reservoir fluid and not containing leaking fracture fluid, while the pressure of the fluid in the unchanged closed zone exceeds the pore pressure of the natural crack.

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