Fracture characterization while drilling

Abstract

A method may include acquiring data from a wellbore imaging tool disposed in a wellbore in a subterranean formation, wherein the wellbore includes an electrically insulating oil-based fluid introduced into the wellbore as a drilling lubricant; determining an electrically insulating oil-based fluid resistance and a reference formation resistance based on the data via a circuit model comprising a series term and a parallel term; and detecting a location of a fracture in the formation based on a change in current from the tool through the electrically insulating oil-based fluid and into the formation, the change in current is obtained by determining an effective formation resistance based on at least a portion of the data of the location and by comparing the effective formation resistance to the reference formation resistance.

Description

[0001] Cross-reference paragraphs

[0002] This application claims the benefit of European application No. 22306223.3, filed on August 12, 2022, entitled “FRACTURE CHARACTERIZATION WHILEDRILLING”, the disclosure of which is hereby incorporated herein by reference. Background Art

[0003] A reservoir may be an underground formation that can be characterized at least in part by its porosity and fluid permeability. As an example, a reservoir may be part of a basin (such as a sedimentary basin). A basin may be a depression in which sediments accumulate (e.g., caused by plate tectonic activity, sedimentation, etc.). As an example, when source rocks are combined with appropriate burial depths and durations, a petroleum system may develop within the basin, thereby forming a reservoir including hydrocarbon fluids (e.g., oil, natural gas, etc.). Various operations may be performed on site to obtain such hydrocarbon fluids and / or produce such hydrocarbon fluids. For example, consider equipment operations, in which equipment may be controlled to perform one or more operations. In such an example, the control may be based at least in part on the properties of the rock, which may exist as a three-dimensional object in a drilling fluid (e.g., mud). Summary of the invention

[0004] A method may include: acquiring data from a borehole imaging tool in a borehole disposed in a formation, wherein the borehole includes an electrically insulating oil-based fluid introduced into the borehole as a drilling lubricant; determining the electrically insulating oil-based fluid impedance and a reference formation impedance based on the data via a circuit model including series terms and parallel terms; and detecting the location of a fracture in the formation based on a change in an electric current from the tool through the electrically insulating oil-based fluid and into the formation, the change in the electric current being obtained by determining an effective formation impedance based on at least a portion of the data at the location and by comparing the effective formation impedance to a reference formation impedance. A system may include: a processor; a memory accessible to the processor; and processor-executable instructions stored in the memory, the processor-executable instructions being used to command the system to: acquire data from a borehole imaging tool in a borehole disposed in a formation, wherein the borehole includes an electrically insulating oil-based fluid introduced into the borehole as a drilling lubricant; determine the electrically insulating oil-based fluid impedance and a reference formation impedance based on the data via a circuit model including series terms and parallel terms; and detect the location of a fracture in the formation based on a change in an electric current from the tool through the electrically insulating oil-based fluid and into the formation, the change in the electric current being obtained by determining an effective formation impedance based on at least a portion of the data at the location and by comparing the effective formation impedance with a reference formation impedance. One or more non-transitory computer-readable storage media may include processor-executable instructions for commanding a computing system to: acquire data from a borehole imaging tool disposed in a borehole in a formation, wherein the borehole includes an electrically insulating oil-based fluid introduced into the borehole as a drilling lubricant; determine an electrically insulating oil-based fluid impedance and a reference formation impedance based on the data via a circuit model including series terms and parallel terms; and detect the location of a fracture in the formation based on a change in current from the tool through the electrically insulating oil-based fluid and into the formation, the change in current being obtained by determining an effective formation impedance based on at least a portion of the data at the location and by comparing the effective formation impedance to a reference formation impedance. Various other devices, systems, methods, etc. are also disclosed.

[0005] This Summary is provided to introduce a selection of concepts that are further described below in the Detailed Description. This Summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. BRIEF DESCRIPTION OF THE DRAWINGS

[0006] The features and advantages of the described implementations may be more readily understood by referring to the following description taken in conjunction with the accompanying drawings.

[0007] Figure 1 An example system including various framework components associated with one or more geological environments is shown;

[0008] Figure 2 An example of a system is shown;

[0009] Figure 3 Examples of drilling equipment and examples of wellbore shapes are shown;

[0010] Figure 4 Examples of wellbore imaging tools and examples of associated data are shown;

[0011] Figure 5 An example of a circuit is shown;

[0012] Figure 6 An example of a drawing is shown;

[0013] Figure 7 An example of a system is shown;

[0014] Figure 8 An example of a drawing is shown;

[0015] Fig. 9 An example of a drawing is shown;

[0016] Fig.10 An example of a drawing is shown;

[0017] Fig.11 Examples of methods and examples of systems are shown;

[0018] Fig.12 Examples of computers and network equipment are shown; and

[0019] Fig.13 Example components of systems and networked systems are shown. DETAILED DESCRIPTION

[0020] This description is not intended to be limiting but is made for the purpose of describing the general principles of implementations. Reference should be made to the issued claims to determine the scope of the described implementations.

[0021] Figure 1 An example of a system 100 is shown that includes a workspace framework 110 that can provide instantiation of, presentation of, interaction with, and the like of a graphical user interface (GUI) 120. Figure 1 In the example of , GUI 120 may include graphical controls for a computing framework (eg, application) 121 , projects 122 , visualization 123 , one or more other features 124 , data access 125 , and data storage 126 .

[0022] exist Figure 1In the example of, the workspace framework 110 may be customized for a specific geological environment (such as the example geological environment 150). For example, the geological environment 150 may include multiple layers (e.g., stratification) that include a reservoir 151 and may intersect a fault 153. The geological environment 150 may be equipped with various sensors, detectors, actuators, and the like. In such an environment, various types of equipment, such as, for example, equipment 152 may include communication circuits for receiving and sending information, optionally relative to one or more networks 155. Such information may include information associated with downhole equipment 154, which may be equipment for obtaining information, assisting in resource recovery, and the like. Other equipment 156 may be located at a location remote from the well site and include sensing, detection, transmission, or other circuits. Such equipment may include storage and communication circuits for storing and transmitting data, instructions, and the like. One or more satellites may be provided for purposes of communication, data acquisition, and the like. For example, Figure 1 A satellite 170 is shown in communication with a network 155 which may be configured for communication, noting that the satellite may additionally or alternatively include circuitry for imagery (eg, spatial, spectral, temporal, radiometric, etc.).

[0023] Figure 1 The geological environment 150 is also shown as optionally including equipment 157 and 158 associated with a well, the well including a substantially horizontal portion that may intersect one or more fractures 159. For example, consider a well in a formation that may include natural fractures, artificial fractures (e.g., hydraulic fractures), or a combination of natural fractures and artificial fractures. As an example, a well may be drilled into a laterally extending reservoir. In such an example, there may be lateral variations in properties, stresses, etc., wherein an assessment of such variations may assist in planning, operations, etc. to develop a laterally extending reservoir (e.g., via fracturing, injection, extraction, etc.). As an example, equipment 157 and / or 158 may include multiple components, a system or multiple systems, etc., for fracturing, seismic sensing, seismic data analysis, assessing one or more fractures, etc.

[0024] exist Figure 1 In the example of , GUI 120 shows some examples of computational frameworks, including the DRILLPLAN framework, the PETREL framework, the TECHLOG framework, the PETROMOD framework, the ECLIPSE framework, and the INTERSECT framework (Schlumberger Limited, Houston, Texas).

[0025] The DRILLPLAN framework is used for digital well construction planning and includes multiple features for automating repetitive tasks and verification workflows, thereby enabling rapid generation of drilling programs (eg, digital drill plans, etc.) of improved quality while ensuring consistency.

[0026] The PETREL framework may be part of a cognitive exploration and production (E&P) environment (Schlumberger Limited, Houston, Texas, known as the DELFI environment), used in, for example, geoscience and geoengineering to analyze subsurface data from exploration to production of fluids from reservoirs.

[0027] One or more types of frameworks may be implemented within or operatively coupled to a DELFI environment, which is a secure, cognitive, cloud-based collaborative environment that integrates data and workflows using digital technologies such as artificial intelligence (AI) and machine learning (ML). Such an environment may provide operations involving one or more frameworks. A DELFI environment may be referred to as a DELFI framework, which may be one of a plurality of frameworks. A DELFI environment may include various other frameworks that may operate using one or more types of models (e.g., simulation models, etc.).

[0028] The TECHLOG framework can handle and process field and laboratory data from a variety of geological environments (e.g., deepwater exploration, shale, etc.). The TECHLOG framework can structure wellbore data for analysis, planning, etc.

[0029] The PIPESIM simulator includes a solver that can provide simulation results, such as, for example, multiphase flow results (e.g., from the reservoir to the wellhead and beyond), flowlines and surface facility performance, etc. The PIPESIM simulator can be integrated, for example, with the AVOCET production operations framework (Schlumberger Limited, Houston Texas). The PIPESIM simulator can be an optimizer that can optimize, at least in part, one or more operating scenarios by simulating physical phenomena.

[0030] The ECLIPSE framework provides numerical solvers for reservoir simulators to predict the dynamic behavior of various types of reservoirs and development scenarios.

[0031] The INTERSECT framework provides a high-resolution reservoir simulator for simulating geological features and quantifying uncertainties, for example, by creating production scenarios, and when integrating accurate models of surface facilities and field operations, the INTERSECT framework can produce results that can be continuously updated through real-time data exchange (e.g., one or more types of data acquisition equipment from the field that can acquire data during one or more types of field operations, etc.). The INTERSECT framework can provide completion configurations for complex wells, where such configurations can be built in the field; can provide detailed chemical enhanced oil recovery (EOR) recipes, where such recipes can be implemented in the field; can analyze the application of steam injection and other thermal EOR technologies to implement advanced production control in terms of reservoir coupling and flexible field management in the field, and the flexibility to write customized solutions for improved modeling and field management control. Like other example frameworks, the INTERSECT framework can be used as part of the DELFI environment, for example, for fast simulation of multiple concurrent cases.

[0032] The aforementioned DELFI environment provides various features for workflows related to subsurface analysis, planning, construction, and production, as shown, for example, in the workspace framework 110. Figure 1 As shown, the output from the workspace framework 110 can be used to guide, control, etc. one or more processes in the geological environment 150, and feedback 160 (e.g., data obtained about operating conditions, equipment conditions, environmental conditions, etc.) can be received via one or more interfaces in one or more forms.

[0033] exist Figure 1 In the example of , visualization features 123 may be implemented via workspace framework 110, for example, to perform tasks associated with one or more of a subsurface region, planning operations, constructing well and / or surface fluid networks, and producing from a reservoir.

[0034] The visualization features may provide visualizations of various earth models, properties, etc., in one or more dimensions. As an example, the visualization features may include one or more control features for controlling equipment, which may include, for example, field equipment that can perform one or more field operations. The workflow may utilize one or more frameworks to generate information that can be used to control one or more types of field equipment (e.g., drilling equipment, cable equipment, fracturing equipment, etc.).

[0035] With respect to reservoir models that may be suitable for use by a simulator, consider the acquisition of seismic data such as acquired via reflection seismology, which can be used in geophysics, for example, to estimate the properties of subsurface formations. Seismic data can be processed and interpreted, for example, to better understand the composition, fluid content, extent, and geometry of subsurface rocks. Such interpretations can be used to plan, simulate, perform, etc., one or more operations for producing fluids from a reservoir (e.g., reservoir rock, etc.). Field acquisition equipment can be used to acquire seismic data, which can be in the form of traces, wherein the traces can include values ​​organized with respect to time and / or depth (e.g., considering 1D, 2D, 3D, or 4D seismic data).

[0036] The model may be a simulated version of a geological environment, wherein the simulator may include multiple features for simulating physical phenomena in a geological environment based at least in part on one or more models. A simulator such as a reservoir simulator may simulate fluid flow in a geological environment based at least in part on a model that may be generated via a framework that receives seismic data. The simulator may be a computerized system (e.g., a computing system) that may use one or more processors to execute instructions to solve a set of equations describing physical phenomena subject to various constraints. In such an example, the set of equations may be spatially defined (e.g., numerically discretized) according to a spatial model including rock layers, geological bodies, etc., which have corresponding positions that may be based on interpretations of seismic and / or other data. The spatial model may be a cell-based model, wherein the cell is defined by a grid (e.g., a net). The cells in a cell-based model may represent a physical region or volume in a geological environment, wherein the cells may be assigned physical properties (e.g., permeability, fluid properties, etc.) that may be closely related to one or more physical phenomena (e.g., fluid volume, fluid flow, pressure, etc.). The reservoir simulation model may be a cell-based spatial model.

[0037] Although in Figure 1Several simulators are shown in the examples of, but one or more other simulators may be utilized in addition or alternatively. For example, consider the VISAGE geomechanical simulator (Schlumberger Limited, Houston Texas) or the PETROMOD simulator (Schlumberger Limited, Houston Texas). The VISAGE simulator includes a finite element numerical solver that can provide simulation results, such as, for example, compaction and settlement of the geological environment, well and completion integrity in the geological environment, cap rock and fault closure integrity in the geological environment, fracturing behavior in the geological environment, thermal recovery in the geological environment, CO2 disposal, etc. The PETROMOD framework provides petroleum system modeling capabilities that can combine one or more of seismic, well and geological information to model the evolution of sedimentary basins. The PETROMOD framework can predict whether and how a reservoir is filled with hydrocarbons, including the source and time of hydrocarbon generation, migration routes, amount, and hydrocarbon types under underground or surface conditions. The MANGROVE simulator (Schlumberger Limited, Houston, Texas) optimizes stimulation designs (e.g., stimulation treatment operations such as hydraulic fracturing) in a reservoir-centric environment. The MANGROVE framework can combine scientific and experimental work to predict the geomechanical propagation of hydraulic fractures, reactivation of natural fractures, etc., and production predictions within a 3D reservoir model (e.g., production from drainage areas of a reservoir, where fluids move into and / or out of a well via one or more types of fractures). The MANGROVE framework can provide results related to the heterogeneous interactions between hydraulic fracture networks and natural fracture networks, which can assist in optimizing the number and location of fracture treatment stages (e.g., stimulation treatments), for example, to improve perforation efficiency and recovery.

[0038] Figure 2 An example of a system 200 is shown that is operatively coupled to one or more databases, data streams, etc. For example, one or more field devices, laboratory devices, computing devices (e.g., local and / or remote), etc. may provide and / or generate data that may be used in the system 200.

[0039] As shown, system 200 may include a geological / geophysical data block 210, a ground model block 220 (e.g., for one or more structural models), a volume model block 230, an application block 240, a numerical processing block 250, and an operational decision block 260. Figure 2As shown in the example of , the geological / geophysical data block 210 may include data 212 from the well top or borehole, data 214 from seismic interpretation, data from outcrop interpretation, and optionally data from geological knowledge. As an example, the geological / geophysical data block 210 may include data from digital images, which may include digital images of cores, cuttings, caves, outcrops, etc. Regarding the ground model block 220, it may provide one or more ground models to be created, edited, etc. based on, for example, one or more of a fault plane 222, a ground plane 224, and an optional topological relationship 226. Regarding the volume model block 230, it may provide one or more volume models to be created, edited, etc. based on, for example, one or more of a boundary representation 232 (e.g., forming a watertight model), a structured grid 234, and an unstructured net 236.

[0040] like Figure 2 As shown in the example of , the system 200 may allow implementation of one or more workflows, for example, where the data of the data block 210 is used to create or edit one or more ground models of the iso-ground model block 220, and the ground models may be used to create or edit one or more volume models of the iso-volume model block 230. Figure 2 As indicated by the example of , the ground model block 220 may provide one or more structural models that may be input to the application block 240. For example, such structural models may be provided to one or more applications, optionally without performing one or more processes of the volume model block 230 (e.g., for the purpose of numerical processing by the numerical processing block 250). Thus, the system 200 may be adapted for one or more workflows for structural modeling (e.g., optionally without performing numerical processing as per the numerical processing block 250).

[0041] With respect to the application block 240, it may include a plurality of applications, such as a well prediction application 242, a reserve calculation application 244, and a well stability assessment application 246. With respect to the numerical processing block 250, it may include a seismic velocity modeling process 251 and subsequent seismic processing 252, a phase and rock physical property interpolation process 253 and subsequent flow simulation 254, and a geomechanical simulation process 255 and subsequent geochemical simulation 256. As indicated, as an example, the workflow may proceed from the volume model block 230 to the numerical processing block 250, and then to the application block 240 and / or the operational decision block 260. As another example, the workflow may proceed from the ground model block 220 to the application block 240, and then to the operational decision block 260 (e.g., considering an application that operates using a structural model).

[0042] exist Figure 2In the example of FIG. 2 , operation decision block 260 may include seismic survey design process 261, well rate adjustment process 252, well trajectory planning process 263, completion planning process 264, and processes for one or more exploration areas, for example, to decide whether to explore, develop, abandon, etc. an exploration area.

[0043] Referring again to data block 210, well top or borehole data 212 may include the spatial location of an interface between two geological layers of a subsurface discontinuity (such as a geological fault) and, optionally, the surface dip; seismic interpretation data 214 may include a set of points, lines, or surface patches interpreted from seismic reflection data and representing an interface between a medium (e.g., geological formations with different seismic wave velocities) or a subsurface discontinuity; outcrop interpretation data 216 may include a set of lines or points, optionally associated with measured dips, representing boundaries between geological layers or geological faults interpreted on the earth's surface; and geological knowledge data 218 may include, for example, knowledge of the paleo-tectonic and sedimentary evolution of a region.

[0044] With respect to the structural model, it can be, for example, a set of grids or mesh surfaces that represent one or more interfaces between geological layers (e.g., ground planes) or subsurface mechanical discontinuities (fault planes). As an example, the structural model can include some information about one or more topological relationships between ground surfaces (e.g., fault A cuts off fault B, fault B intersects fault C, etc.).

[0045] Regarding one or more boundary representations 232, they may include a numerical representation in which the subsurface model is divided into various closed cells representing geological layers and fault blocks, where an individual cell may be defined by its boundaries and, optionally, by a set of internal boundaries (such as fault planes).

[0046] With respect to one or more structured grids 234, they may include a grid that divides the volume of interest into different elementary volumes (cells), which may be indexed, for example, according to a predefined repeating pattern. With respect to one or more unstructured grids 236, they may include a grid that divides the volume of interest into different elementary volumes, which may not be easily indexed according to a predefined repeating pattern, for example (e.g., consider a Cartesian cube with indices I, J, and K along the x-axis, y-axis, and z-axis).

[0047] With respect to seismic velocity modeling 251, it may include calculating the propagation velocity of seismic waves (e.g., seismic velocity depends on the type of seismic wave and the direction in which the wave is propagating). With respect to seismic processing 252, it may include a set of processes that allow identification of the locations of seismic reflectors in space, the physical properties of the rocks between these reflectors, etc.

[0048] Regarding facies and petrophysical property interpolation 253, this may include an assessment of rock types and their petrophysical properties (e.g., porosity, permeability), such as optionally in areas not logged or cored. As an example, such interpolation may be limited by interpretation and prior geological knowledge from log and core data.

[0049] With respect to flow simulation 254, as an example, it can include simulating the flow of subsurface hydrocarbons, for example, through geological time (e.g., in the context of petroleum systems modeling, when trying to predict the presence and quality of oil in undrilled formations) or during extraction of a hydrocarbon reservoir (e.g., when some fluid is pumped from or into a reservoir).

[0050] With respect to geomechanical simulation 255, it may include simulations of rock deformation under boundary conditions. Such simulations may be used, for example, to assess the degree of compaction of a reservoir (e.g., associated with reservoir depletion as hydrocarbons are pumped out of the porous and deformable rocks that comprise the reservoir). As an example, geomechanical simulations may be used for a variety of purposes, such as, for example, predicting fracturing, reconstructing the ancient geometry of a reservoir prior to structural deformation, and the like.

[0051] With respect to geochemical modeling 256, such simulations may simulate the evolution of hydrocarbon formations and compositions over geological history (eg, to assess the likelihood of petroleum accumulation in a particular subsurface formation when exploring a new prospect).

[0052] With respect to the various applications of application block 240, a well prediction application 242 may include predicting the types and characteristics of geological formations that a drill bit may encounter, and the locations where such rock may be encountered (e.g., prior to drilling a well); a reserve calculation application 244 may include assessing the total amount of hydrocarbon or ore material present in a subsurface environment (e.g., estimating the fraction that is recoverable given a set of economic and technical constraints); and a well stability assessment application 246 may include estimating the risk of collapse or damage to a drilled or yet-to-be-drilled well due to subsurface stresses.

[0053] With respect to operational decision block 260, the seismic survey design process 261 may include deciding where to place seismic sources and receivers to optimize coverage and quality of collected seismic information while minimizing acquisition costs; the well rate adjustment process 262 may include controlling injection and production well schedules and rates (e.g., to maximize recovery and production); the well trajectory planning process 263 may include designing well trajectories to maximize potential recovery and production while minimizing drilling risks and costs; the well trajectory planning process 264 may include selecting appropriate wellbore, casing, and completions (e.g., to meet expected production or injection targets in a specified reservoir); and the exploration process 265 may include making decisions in the context of exploration to continue exploration, begin production, or abandon exploration (e.g., based on a comprehensive assessment of technical and financial risks and expected returns).

[0054] System 200 may include and / or be operatively coupled to, for example, Figure 1 The system 100 of the system. For example, the workspace framework 110 may provide instantiation, rendering, interaction with, etc. of a graphical user interface (GUI) 120 to perform one or more actions with respect to the system 200. In such an example, access to one or more frameworks (e.g., DRILLPLAN, PETREL, TECHLOG, PIPESIM, ECLIPSE, INTERSECT, etc.) may be provided. The one or more frameworks may provide geographic data acquisition such as in block 210, structural modeling such as in block 220, volume modeling such as in block 230, application execution such as in block 240, numerical processing such as in block 250, operational decision making such as in block 260, etc.

[0055] As an example, the system 200 may provide monitoring data, which may include geographic data for each geographic data block 210. In various examples, the geographic data may be acquired during one or more operations. For example, consider acquiring geographic data via downhole equipment and / or surface equipment during a drilling operation. As an example, the operational decision block 260 may include functionality for monitoring, analyzing, and the like such data in order to make one or more operational decisions, which may include controlling equipment, modifying operations, modifying plans, and the like. In such an example, data may be fed into the system 200 at one or more points where data quality may be of particular concern. For example, data quality may be characterized by one or more metrics, wherein data quality may provide indications of confidence, probability, and the like, which may be relevant to operational decisions and / or other decisions.

[0056] Figure 3 An example of a wellsite system 300 is shown (e.g., at a wellsite that may be located onshore or offshore). As shown, the wellsite system 300 may include: a mud tank 301 for storing mud and other materials (e.g., where the mud may be drilling fluid); a suction line 303 that serves as an inlet for a mud pump 304 that pumps mud from the mud tank 301 so that the mud flows to a vibrating hose 306; a winch 307 that hoists one or more drilling wire ropes 312; a riser 308 that receives mud from the vibrating hose 306; and a kelly hose 309 that receives mud from the riser 308. ; a gooseneck or goosenecks 310; a traveling block 311; a crown block 313 for carrying the traveling block 311 via one or more drilling wire lines 312; a derrick 314; a kelly 318 or a top drive 340; a kelly drive bushing 319; a rotary table 320; a drill floor 321; a bell-mouth nipple 322; one or more blowout preventers (BOPs) 323; a drill string 325; a drill bit 326; a casing head 327; and a flow tube 328, which transports mud and other materials to, for example, a mud tank 301.

[0057] exist Figure 3 In the example system, a wellbore 332 is formed in a subsurface formation 330 by rotary drilling; it should be noted that various example embodiments may also use one or more directional drilling techniques, equipment, etc.

[0058] like Figure 3 As shown in the example of FIG. 3 , a drill string 325 is suspended in a wellbore 332 and has a drill string assembly 350 including a drill bit 326 at its lower end. As an example, the drill string assembly 350 may be a bottom hole assembly (BHA).

[0059] The wellsite system 300 can provide for the operation of the drill string 325 and other operations. As shown, the wellsite system 300 includes a traveling block 311 and a derrick 314 positioned above a wellbore 332. As mentioned, the wellsite system 300 can include a rotary table 320, wherein the drill string 325 passes through an opening in the rotary table 320.

[0060] like Figure 3 As shown in the example of , the wellsite system 300 may include a kelly 318 and associated components, or a top drive 340 and associated components. With respect to the kelly example, the kelly 318 may be a square or hexagonal metal / alloy rod with holes drilled therein for use as a mud flow path. The kelly 318 may be used to transfer rotational motion from the rotary table 320 to the drill string 325 via the kelly drive bushing 319, while allowing the drill string 325 to be lowered or raised during rotation. The kelly 318 may pass through the kelly drive bushing 319, which may be driven by the rotary table 320. As an example, the rotary table 320 may include a square bushing that is operatively coupled to the kelly drive bushing 319, such that rotation of the rotary table 320 may cause the kelly drive bushing 319 to rotate and, therefore, cause the kelly 318 to rotate. The kelly drive bushing 319 may include an inner profile that matches the outer profile of the kelly 318 (e.g., square, hexagonal, etc.); however, the kelly drive bushing has a slightly larger size so that the kelly 318 can move freely up and down within the kelly drive bushing 319.

[0061] With respect to the top drive example, the top drive 340 can provide the functions performed by the kelly and rotary table. The top drive 340 can rotate the drill string 325. As an example, the top drive 340 can include one or more (e.g., electric and / or hydraulic) motors connected to a small section of pipe called a cannula using appropriate gearing, which in turn can be tightened to a saver sub or the drill string 325 itself. The top drive 340 can be suspended on the traveling block 311 so that the rotating mechanism can move freely up and down along the derrick 314. As an example, the top drive 340 can allow drilling to be performed using more single columns than the kelly / rotary table approach.

[0062] exist Figure 3In the example of, mud tank 301 can store mud, and mud can be one or more types of drilling fluids. As an example, a wellbore can be drilled to produce fluids, inject fluids, or both (e.g., hydrocarbons, minerals, water, etc.).

[0063] exist Figure 3 In the example of FIG. 3 , a drill string 325 (e.g., including one or more downhole tools) may be composed of a series of tubes that are threaded together to form a long tube with a drill bit 326 at the lower end. As the drill string 325 is entered into the wellbore for drilling, mud may be pumped from a mud tank 301 (e.g., or other source) to the mouth of the kelly 318, or, for example, to the mouth of the top drive 340, via pipelines 306, 308, and 309 by a pump 304, prior to or at some point in time coinciding with the drilling. The mud may then flow through a channel (e.g., or multiple channels) in the drill string 325 and out of a port located on the drill bit 326 (see, e.g., directional arrows). As the mud leaves the drill string 325 through the port in the drill bit 326, the mud may then loop back upward through the annular region between the outer surface of the drill string 325 and the surrounding wall (e.g., open hole, casing, etc.), as indicated by the directional arrows. In this manner, the mud lubricates the drill bit 326 and carries heat energy (eg, frictional or other energy) and formation cuttings to the surface, where the mud may be returned to the mud tank 301 after being processed to remove cuttings and other materials, such as for recirculation.

[0064] exist Figure 3 In the example of , the treated mud pumped into the drill string 325 by the pump 304 can form a mud cake lining the wellbore after leaving the drill string 325, which can, among other things, reduce the friction between the drill string 325 and the surrounding walls (e.g., the wellbore, casing, etc.). The reduction in friction can facilitate the advancement or retraction of the drill string 325. During the drilling operation, the entire drill string 325 can be pulled out of the wellbore and optionally replaced, for example, with a new or sharp drill bit, a smaller diameter drill string, etc. As mentioned, the action of pulling out the drill string from the wellbore or replacing the drill string in the wellbore is called tripping. Depending on the tripping direction, tripping can be called tripping up or tripping out or tripping down or tripping in.

[0065] As an example, consider drilling down, where when the drill bit 326 of the drill string 325 reaches the bottom of the wellbore, the pumping of mud begins to lubricate the drill bit 326 for drilling purposes to expand the wellbore. As mentioned, the mud can be pumped into the channel of the drill string 325 by the pump 304, and when filling the channel, the mud can be used as a transmission medium for transmitting energy (e.g., energy that can encode information as in mud pulse telemetry). The characteristics of the mud can be used to determine how the pulse is transmitted (e.g., pulse shape, energy loss, transmission time, etc.).

[0066] As an example, a mud pulse telemetry device may include a downhole device configured to implement changes in mud pressure to generate an acoustic wave or multiple acoustic waves based on which information can be modulated. In such an example, information from the downhole device (e.g., one or more modules of the drill string 325) can be transmitted up the wellbore to the wellhead device, which can relay such information to other equipment for processing, control, etc.

[0067] As an example, the telemetry equipment may operate by transmitting energy through the drill string 325 itself. For example, consider a signal generator that transmits a coded energy signal to the drill string 325, and a repeater that may receive such energy and relay it for further transmission of the coded energy signal (e.g., information, etc.).

[0068] As an example, the drill string 325 may be equipped with a telemetry device 352, the telemetry device comprising: a rotatable drive shaft; a turbine wheel mechanically coupled to the drive shaft so that mud can rotate the turbine wheel; a modulator rotor mechanically coupled to the drive shaft so that rotation of the turbine wheel causes the modulator rotor to rotate; a modulator stator mounted adjacent or proximate to the modulator rotor so that rotation of the modulator rotor relative to the modulator stator generates pressure pulses in the mud; and a controllable brake for selectively braking rotation of the modulator rotor to modulate the pressure pulses. In such an example, an alternator may be coupled to the aforementioned drive shaft, wherein the alternator includes at least one stator winding, the at least one stator winding being electrically coupled to a control circuit to selectively short-circuit the at least one stator winding to electromagnetically brake the alternator and thereby selectively brake rotation of the modulator rotor to modulate pressure pulses in the mud.

[0069] exist Figure 3 In an example of wellhead control and / or data acquisition system 362, wellhead control and / or data acquisition system 362 may include circuitry for sensing pressure pulses generated by telemetry device 352 and, for example, transmitting the sensed pressure pulses or information derived therefrom for processing, control, etc.

[0070] The illustrated example assembly 350 includes a logging while drilling (LWD) module 354, a measurement while drilling (MWD) module 356, an optional module 358, a rotary steerable system (RSS) and / or motor 360, and a drill bit 326. Such components or modules may be referred to as tools, wherein a drill string may include multiple tools.

[0071] With respect to RSS, it relates to techniques used for directional drilling. Directional drilling involves drilling into the earth to form a deflected borehole so that the trajectory of the borehole is not vertical; instead, the trajectory deviates from vertical along one or more portions of the borehole. As an example, consider a target located at a lateral distance from a surface location where a drilling rig may be stationary. In such an example, drilling may begin at a vertical portion and then deviate from vertical so that the borehole is aligned with the target and ultimately reaches the target. Directional drilling may be implemented in the following situations: where the target is not reachable from a vertical position on the earth's surface, where there are materials in the earth that may hinder drilling or are otherwise harmful (e.g., consider salt domes, etc.), where the formations are laterally extended (e.g., consider relatively thin but laterally extended reservoirs), where multiple boreholes are to be drilled from a single surface borehole, where a relief well is required, etc.

[0072] One method of directional drilling involves a mud motor; however, mud motors can present some challenges depending on factors such as rate of penetration (ROP), weight transfer to the drill bit (e.g., weight on bit WOB) due to friction, etc. A mud motor can be a positive displacement motor (PDM) that operates to drive a drill bit (e.g., during directional drilling, etc.). A PDM operates when drilling fluid is pumped through it, where the PDM converts the hydraulic power of the drilling fluid into mechanical power to rotate the drill bit.

[0073] As an example, the PDM may be operated in a combined rotation mode, in which surface equipment is used to rotate the drill bit of the drill string by rotating the entire drill string (e.g., rotary table, top drive, etc.), and drilling fluid is used to rotate the drill bit of the drill string. In such an example, the surface RPM (SRPM) may be determined using the surface equipment, and the downhole RPM of the mud motor may be determined using various factors related to the flow of drilling fluid, the type of mud motor, etc. As an example, in the combined rotation mode, the drill bit RPM may be determined or estimated as the sum of the SRPM and the mud motor RPM, assuming that the SRPM and the mud motor RPM are in the same direction.

[0074] The PDM mud motor can be operated in various modes, such as, for example, a rotation mode and a so-called sliding mode, which is achieved when the drill string is not rotated from the surface. In such an example, the drill bit RPM can be determined or estimated based on the RPM of the mud motor.

[0075] The RSS can perform directional drilling from the place of continuous rotation of the surface equipment, which can mitigate slippage of the directional motor (e.g., PDM). The RSS can be deployed when drilling directionally (e.g., deviated, horizontal, or extended wells). The RSS can be designed to minimize its interaction with the wellbore wall, which can help maintain wellbore quality. The RSS can be designed to apply a fairly consistent lateral force similar to a stabilizer that rotates with the drill string or orients the drill bit in a desired direction while continuously rotating at the same RPM as the drill string.

[0076] The LWD module 354 may be housed in a suitable type of drill collar and may include one or more selected types of logging tools. It should also be understood that more than one LWD module and / or MWD module may be employed, for example, as represented by module 356 of the drill string assembly 350. Where reference is made to the location of an LWD module, by way of example, it may refer to a module at the location of the LWD module 354, module 356, etc. The LWD module may include capabilities for measuring, processing, and storing information, as well as communicating with surface equipment. In the example shown, the LWD module 354 may include a seismic measurement device.

[0077] The MWD module 356 may be housed in a suitable type of drill collar and may include one or more devices for measuring characteristics of the drill string 325 and the drill bit 326. As an example, the MWD tool 354 may include, for example, a device for generating electricity to power various components of the drill string 325. As an example, the MWD tool 354 may include, for example, a telemetry device 352 in which a turbine wheel may generate electricity through the flow of mud; it should be understood that other power sources and / or battery systems may be used to power the various components. As an example, the MWD module 356 may include one or more of the following types of measurement devices: a bit pressure measurement device, a torque measurement device, a vibration measurement device, an impact measurement device, a stick-slip measurement device, a direction measurement device, and an inclination measurement device.

[0078] Figure 3 Also shown are some examples of the types of wellbores that can be drilled. For example, consider a slanted straight wellbore 372, an S-shaped wellbore 374, a deeply deviated wellbore 376, and a horizontal wellbore 378.

[0079] The drilling operation may include directional drilling, wherein, for example, at least a portion of the well includes a curved axis. For example, consider a radius of curvature defined wherein the inclination relative to the vertical may vary until reaching an angle between about 30 degrees and about 60 degrees, or, for example, reaching an angle of about 90 degrees or possibly greater than about 90 degrees.

[0080] A directional well may include several shapes, each of which may be designed to meet specific operational requirements. As an example, a drilling process may be performed based on information and when the information is communicated to a drilling engineer. As an example, the inclination and / or direction may be modified based on information received during the drilling process.

[0081] As explained, the system may be a guidance system and may include equipment for performing methods such as geosteering. The guidance system may include equipment located on the lower portion of the drill string, just above the drill bit, where a bent sub may be installed. Above the directional drilling equipment, the drill string may include MWD equipment and / or LWD equipment that provides real-time or near real-time data of interest (e.g., inclination, direction, pressure, temperature, actual weight on the drill bit, torque stress, etc.). With respect to the latter, the LWD equipment may send various types of data of interest to the surface, including, for example, geological data (e.g., gamma ray logging, resistivity, density, and sonic logging, etc.).

[0082] The coupling of sensors that provide information about the well trajectory route in real time or near real time with one or more well logs that characterize the formation from a geological point of view, for example, can allow for the implementation of geosteering methods. Such methods may include navigating the subsurface environment to follow a desired route to a desired target or targets.

[0083] The drill string may include: an azimuthal density neutron (AND) tool for measuring density and porosity; an MWD tool for measuring inclination, azimuth, and shock; a compensated dual resistivity (CDR) tool for measuring resistivity and gamma-ray related phenomena; one or more variable diameter stabilizers; one or more curved joints; and a geosteering tool, which may include a motor and optionally equipment for measuring and / or responding to one or more of inclination, resistivity, and gamma-ray related phenomena.

[0084] Geosteering may include intentional directional control of a wellbore based on downhole geological logging measurements in a manner intended to maintain the directional wellbore within a desired area, zone (e.g., a pay zone), etc. Geosteering may include directing the wellbore to maintain the wellbore in a particular section of a reservoir, e.g., to minimize breakthrough of gas and / or water, and e.g., to maximize economic production from a well that includes the wellbore.

[0085] Reference again Figure 3 , the wellsite system 300 may include one or more sensors 364 that are operatively coupled to the control and / or data acquisition system 362. As an example, the sensor or sensors may be at a surface location. As an example, the sensor or sensors may be at a downhole location. As an example, the sensor or sensors may be at one or more remote locations that are more than about one hundred meters away from the wellsite system 300.

[0086] The system 300 may include one or more sensors 366 that may sense signals and / or transmit signals to a fluid conduit, such as a drilling fluid conduit (e.g., a drilling mud conduit). For example, in the system 300, one or more sensors 366 may be operatively coupled to a portion of the riser 308 through which mud flows. As an example, a downhole tool may generate pulses that may pass through the mud and be sensed by one or more of the one or more sensors 366. In such an example, the downhole tool may include associated circuitry, such as, for example, an encoding circuit that may encode the signal, for example, to reduce the requirements for transmission. The circuitry at the surface may include a decoding circuit to decode the encoded information transmitted at least in part via mud pulse telemetry. The circuitry at the surface may include an encoder circuit and / or a decoder circuit, and the downhole circuitry may include an encoder circuit and / or a decoder circuit. As an example, the system 300 may include a transmitter that may generate a signal that may be transmitted downhole via mud (e.g., drilling fluid) as a transmission medium.

[0087] During drilling operations, one or more portions of the drill string may become stuck. The term "stuck" may refer to one or more varying degrees of inability to move or remove the drill string from the borehole. As an example, in a stuck condition, it may be possible to rotate the drill rod or return it to the borehole, or, for example, in a stuck condition, it may not be possible to axially move the drill string in the borehole, although some degree of rotation may be possible. As an example, in a stuck condition, it may not be possible to axially and rotationally move at least a portion of the drill string.

[0088] With respect to the term "stuck drill," this may refer to a portion of the drill string being unable to rotate or move axially. A condition known as "differential stuck drill" may be a condition in which the drill string is unable to move (e.g., rotate or reciprocate) along the axis of the borehole. Differential stuck drill may occur when high contact forces caused by low reservoir pressure, high wellbore pressure, or both, are applied over a sufficiently large area of ​​the drill string. Differential stuck drill may have both temporal and economic costs.

[0089] The sticking force can be the product of the pressure differential between the wellbore and the reservoir and the area over which the pressure differential acts. This means that applying a relatively low pressure differential (Δp) over a large working area can have the same effect on sticking as applying a high pressure differential over a small area.

[0090] A condition known as "mechanical stuck drill" may be a condition in which drill string movement is restricted or prevented by a mechanism other than differential pressure stuck drill. Mechanical stuck drill may be caused, for example, by one or more of trash in the wellbore, wellbore geometry anomalies, cement, keyway or cuttings accumulation, and / or collapse in the annulus.

[0091] Various downhole tools can generate information closely related to the wellbore conditions. For example, images of the walls that form the wellbore during drilling can provide information about layers, boundaries, formation characteristics, etc. In various cases, fractures can be detected via analysis of downhole images. Fractures can include natural fractures and fractures caused by drilling and / or other downhole operations. Information about fractures can be used when planning and / or performing downhole operations, which can include, for example, completion operations, drilling operations, etc. As an example, an imaging tool can use resistivity to obtain images of the wellbore wall during drilling operations. In such examples, the drilling operation can be controlled at least in part based on such acquired images.

[0092] As an example of an imaging tool, consider the FMI Fullbore Formation Microimager (Schlumberger Limited, Houston, Texas), which provides real-time microresistivity formation images and dip data. With 80% borehole coverage in an 8-inch borehole (e.g., about 20 cm) and 0.2-inch image resolution in the vertical and azimuthal directions (e.g., about 0.5 cm), imaging with the FMI Microimager can provide data that can help determine net pay in layered sediments such as fluvial and turbidite depositional environments. Understanding the sedimentary features can assist in determining reservoir geometry and reservoir petrophysical parameters. In various cases, image details can be discerned to 50 microns, which can supplement coring and sampling data. Interpretation combining images with sedimentary dip data derived from the imaging tool can provide a deeper understanding of structure, particularly natural structure and / or drilling-induced structure.

[0093] Data acquired by imaging tools can be used to build mechanical earth models, which can help predict the type and location of drilling-induced features in the wellbore. In this approach, understanding the direction and relative magnitude of the principal stresses can help optimize drilling, completions, etc. For completions, image data analysis can help identify the direction of maximum permeability in a fractured reservoir to assist in the design of completions that achieve optimal production.

[0094] The aforementioned FMI microimager tool can use more than one hundred microresistivity measurements to generate an electrical image of the borehole. Focusing circuits can act to force the measurement current into the formation, where the current can produce a low-frequency signal rich in petrophysical and lithological information and a high-resolution component of the microresistivity data provided for imaging, which can assist in dip interpretation. The spacing of the button electrodes, the pad and flap design, and the high-frequency data transmission provide a vertical and azimuthal resolution of 0.2 inches (e.g., about 0.5 cm), so that features of 0.2 inches (e.g., about 0.5 cm) or larger can be easily estimated from the image; it should be noted that the size of features less than 0.2 inches (e.g., about 0.5 cm) can be estimated by quantifying the electrode current.

[0095] As an example, a borehole imaging tool such as the TERRASPHERE service tool (Schlumberger Limited, Houston, Texas) may be utilized. Such a tool includes an electromagnetic subsystem that can send pulses from a sensor through the mud and into the formation at a wide range of frequencies to produce resistivity images over a wide range of resistivities encountered in underground geological environments. An acoustic subsystem may be included that transmits short ultrasonic pulses and detects the resulting echoes from the borehole wall, which can provide reliable measurements in drilling fluids with heavy mud weights that are highly attenuated. Such a tool can utilize frequent sensor sampling and focusing to achieve resolution comparable to that of a wireline ultrasonic imaging tool in both oil-based and water-based mud systems.

[0096] As explained, borehole imaging tools may include multi-physics technologies integrated into one tool to enhance the understanding of geology and boreholes in various environments while drilling. Multi-physics tools may generate complementary images, where resistivity images are rich in bedding features, while ultrasonic images are more sensitive to fractures and borehole conditions.

[0097] Figure 4 An example of a formation 401 having a borehole 410 (e.g., a wellbore) and a wellbore imaging tool 415 disposed in the wellbore that can be configured to acquire electrical wellbore images and current related information. As mentioned, the wellbore imaging tool can be part of a drill string that can acquire data during drilling operations. As an example, the wellbore imaging tool 415 can be included as part of the drill string. As an example, the wellbore imaging tool 415 can include multi-physics capabilities.

[0098] For example, a data acquisition sequence for tool 415 may include: delivering current into the material defining the wellbore while translating and / or rotating the tool in the wellbore; and sensing the current as it changes due to interaction with the material. The acquired data may include, for example, data having at least some petrophysical and / or geological relevance.

[0099] exist Figure 4 In the example of FIG. 4 , tool 415 may acquire raw data as a plurality of electrode readings. The sampling rate of the electrode data may be about 120 samples / foot (e.g., about 400 samples / meter). The area coverage of the wellbore face may depend on the width of the electrode array, the wellbore diameter, etc. As an example, less than the entire wellbore face may be imaged. Where no data was collected (so-called "non-imaged portions"), the raw data may be separated by blank "strips" (e.g., between adjacent pads on the resulting wellbore log).

[0100] like Figure 4As shown in the example of , at least a portion of the acquired data is an electrical (or other petrophysical parameter) image of formations and features present at the wellbore, and may be referred to as cylindrical surface data 420, which may be defined using one or more radii r and a wellbore axis z. As an example, the image may be a circumferential image, where the data is organized around a circumference, which may correspond to the circumference of the wellbore, a circumference at a radial distance outside the wellbore surface, etc. (e.g., depending on the technology implemented for data acquisition). Figure 4 Also shown is how bedding planes 430 may be identified by "unrolling" cylindrical surface data 420 or by converting it to a sheet-like format 440, where directions and / or angles may be specified.

[0101] As an example, a wellbore may be drilled in a formation or structure, wherein a wellbore imaging tool may be disposed in the wellbore to acquire data. In such an example, the data acquired from the wellbore imaging tool may be used to detect fractures and orientations of the fractures and optionally one or more other features. In such an example, the image and / or current related data may be analyzed. As an example, a method may include utilizing the wellbore imaging data to detect and / or monitor fractures and / or cracks in a porous medium exposed to a fluid, such as, for example, water and oil, wherein the porous medium may include one or more of a subterranean formation, a masonry structure, a cement structure, and the like.

[0102] As mentioned, drilling can utilize drilling fluids, which can be referred to as mud or drilling mud. Drilling fluid categories can include water-based muds (WBM) and non-aqueous fluids (NAF), within the latter group, the non-aqueous fluids can be distinguished into oil-based muds (OBM) and synthetic-based muds (SBM).

[0103] In cases where the lubricating properties of an OBM are superior to those of a WBM, an OBM may be utilized. An OBM may also be more expensive than a WBM; it should be noted that recovery costs and processes may be considered in the mud stage. As an example, an OBM may be selected over a WBM for challenging drilling scenarios and / or where salt formations may be encountered (e.g., given the ability of water to dissolve various salts). As an example, offshore drilling to greater depths may utilize an OBM, particularly where salt formations are present. As an example, consider a stratum that may include a pre-salt layer, which may be a series of intertemporal geological layers on the continental shelf of an extensional basin formed after the breakup of the Gondwana continent, characterized by the deposition of thick layers of evaporites (mostly salt). Due to salt domes, some of the oil produced by the sediments in the pre-salt layer did not migrate upward to the post-salt layer above (e.g., consider areas adjacent to the coasts of Africa and Brazil). Therefore, drilling may involve drilling through one or more salt layers (e.g., salt formations, etc.).

[0104] Where the borehole imaging tool relies on electrical current, the electrical properties of the fluid at and / or near the borehole wall may affect the effectiveness of the borehole imaging tool. In various examples, the borehole imaging tool may be used in an environment including oil where, for example, different methods may be implemented than those suitable for an oil-free environment.

[0105] As explained, imaging tools may provide the ability to locate fractures when drilling in a hydrocarbon reservoir, which may be utilized to control the drilling process for hydrocarbon production.

[0106] When drilling, mechanical stresses can be concentrated near the wellbore, which can affect wellbore integrity. For example, the wellbore may deform, begin fracturing to relieve stress, etc. When this happens, the drill string may get stuck and become jammed, or may suffer mud loss, for example, when mud flows from the wellbore into the formation. A more significant break-out may then occur, putting the zonal isolation achieved by cementing at risk.

[0107] Fractures may be visible on the image, where such fractures may be of geological origin, cemented or filled by formation fluids. The ability to characterize fractures enables identification of the type of fracture (e.g., natural fractures or drilling-induced fractures) and allows operators, managers, etc. to make appropriate diagnoses, and they may adjust drilling parameters (e.g., mud weight, mud flow rate, RPM, weight on bit (WOB), etc.) to limit or otherwise address wellbore damage.

[0108] Hydrocarbon production in carbonates or sandstones often relies on fractures in the rock because the rock matrix itself may have too low permeability and hydrocarbon mobility. Reliable production predictions and interpretations require accurate fracture characterization. In particular, fractures can be characterized as open and supporting flow, or as closed and filled with minerals or other solids. Distinguishing between natural fractures and induced fractures can also assist in drilling and / or other operations.

[0109] In wells using conductive water-based muds, fracture characterization can be performed using techniques where the water-based electrical properties are sufficiently characterized. Electrical and ultrasonic borehole images, or a combination of both, can be used to identify fractures and quantify their status: open fractures allow the ingress of conductive water-based drilling fluids (e.g., WBM), which makes the fractures quite obvious on electrical images as conductive streaks and as low-amplitude traces on ultrasonic images. On the other hand, closed fractures do not allow the ingress of fluids, so that where mineralized, the fractures appear electrically resistive and as high-amplitude features on ultrasonic images. When the fracture is open, in a water-based environment, the aperture of the fracture can be quantified based on the excess current measured when the tool passes through the fracture.

[0110] As explained, the electrical imaging tool may be part of a MWD and / or LWD enabled drill string where, for one or more reasons, drilling may utilize oil-based mud (e.g., non-aqueous mud). Where oil-based mud is utilized, various techniques for aqueous mud environments will produce suboptimal results because the electrical response to fractures is more complex when oil is present. For example, a reading in the presence of oil-based mud may show an impedance maximum at the edge of a fracture. In various scenarios, relying solely on ultrasonic images may not be a viable option because fracture characterization becomes non-quantifiable when the fracture thickness is less than half the sensor resolution; it should be noted that many fractures encountered downhole may be below this resolution.

[0111] As an example, the method can provide electrical characterization of fractures, cracks, etc. over a wide frequency range (e.g., about 1 MHz to 100 MHz) in a manner suitable for operations in the presence of oil at or near the wellbore. This method can be applied to wellbores drilled using oil-based mud (OBM), for example, to classify fractures in an OBM environment. Knowing that the resistivity / dielectric constant in fractures varies with frequency can help distinguish the low dielectric constant of the oil-based mud filtrate from the higher dielectric constant present in the porous rock matrix or fracture filling. The dielectric constant of the oil-based mud and its filtrate exhibits a dielectric constant dispersion having different properties than the dielectric constant encountered in porous media (e.g., generally having a stronger dispersion). One or more physical properties (including their dispersion) can provide effective classification, for example as one or more criteria for open fractures versus closed fractures.

[0112] As an example, if a crack is detected as open, the method may include quantifying its thickness. Additionally, if the crack is thick enough that ultrasonic measurements can quantify the crack thickness, the method may quantify electrical parameters of the crack, even in various cases below the resolution of the electrical imager.

[0113] As explained, borehole imaging tools can provide centimeter-resolution images of the rock surface at the borehole wall. Ultrasonic images provide pure surface information, while electrical or electromagnetic images detect material properties of porous rock (e.g., one porous rock medium or multiple porous rock media) exposed to the borehole. Laterolog electrical imagers operating at a frequency of 1.5 kHz in a conductive water-based mud tend to be most sensitive to the fluid content of the rock. Ultrasonic images and electromagnetic images alone can allow the identification of fractures in the rock; it should be noted that electromagnetic images can allow the characterization of the material content of fractures close to the borehole wall.

[0114] As mentioned, the electrical properties of oil-based and water-based fluids can differ. Generally speaking, oil-based drilling fluids are electrically insulating compared to water-based drilling fluids. In addition, the rock matrix can be electrically insulating due to its mineral content. The presence of water in the environment provides a certain degree of conductivity. Therefore, electrical images of wells filled with oil-based mud can only detect the presence of water, which is usually bound water in the porous rock. In various cases, over-pressurized oil-based mud filtrate will push mobile water away from the wellbore wall. Lower frequency electrical images tend to be limited by the insulating film of the oil-based mud, which is measured in tandem with the much lower resistivity of the rock formation. Therefore, at least in cases where the formation is more conductive than the drilling mud, electrical images tend to fail to visualize fractures in such oil-based mud wells.

[0115] On the other hand, higher frequency EM imager measurements in the multi-MHz frequency range involve capacitive coupling and electromagnetic (radio wave) radiation to penetrate the oil-based mud film between its measuring button electrode and the formation. In addition to the conductivity caused by the presence of bound water, these measurements also detect the dielectric properties of the surrounding medium.

[0116] In Maxwell's equations, the dielectric constant is combined with the conductivity as the real and imaginary parts of a complex-valued material parameter called the complex dielectric constant. Given the operating frequency f and the circular frequency ω = 2πf, the overall time dependence e is given by –iωt , so that each time derivative are replaced by the multiplier –iω. The microscopic form of Ohm’s law converts the current density With electric field Relate via conductivity σ: The dielectric constant ε converts the electric field and displacement current Get in touch These identities simplify Maxwell-Ampère's equation:

[0117]

[0118] Here the source current density can be used to describe the emitter, where the complex dielectric constant is: * =ε+iσ / ω.

[0119] As an example, the method may include estimating the formation impedance. As mentioned, the oil-based mud may be considered an electrical insulator, which may be characterized by its dielectric constant ε and its loss tangent tan δ. The loss tangent may be given by knowing the conductivity σ, such as:

[0120]

[0121] The complex impeditivity of the fluid can be expressed by the Z in [ohm.m]. m To describe:

[0122] 1 / Z m =σ+jωε

[0123] Equivalently, the electrical properties of the formation can be described by impedance, which can be understood in a first-order approximation by a resistor-capacitor (RC) parallel circuit. In this approach, the equivalent impedance will then follow a dependence on frequency described by:

[0124]

[0125] The response of an electrical imager tool can be physically interpreted as an impedance modeled by an equivalent circuit.

[0126] Figure 5 An example of an equivalent circuit 500 (eg, a circuit model or a portion of a circuit model) is shown, the equivalent circuit including impedances, where Z 地层 is the formation impedance, and where Z 泥浆1 and Z 泥浆2 are the mud impedances and they are defined as:

[0127] Z 泥浆1 =k1(s)·Z m And Z 泥浆2 =k2(s)·Z m

[0128] where k1 and k2 are geometric functions that depend on tool geometry (eg, fixed geometry) and spacing.

[0129] The apparent impedance measured by the electrical imager tool can be related to the contribution of the mud via the following equation:

[0130]

[0131] Where k is the tool geometry factor and the spacing value is s.

[0132] In each case, the mud electrical properties do not change during field operations, and their electrical properties can be estimated while the electrical imager tool is in the casing section (e.g., the casing section of the wellbore). The equivalent circuit can be simplified so that equation (1) becomes:

[0133]

[0134] Regarding equation (2), it can be based on the fact that the casing impedance can be approximated to zero (null value) and it can be shown that the apparent impedance in the casing is proportional to the mud impedance with a proportionality factor that depends only on the spacing.

[0135] Figure 6 An example of a plot 600 of impedance versus spacing is shown to illustrate the impedance spacing dependency. As shown, impedance generally increases as spacing increases, with some leveling off at higher spacing values. Figure 6 In the example of , within a certain range of spacing values, the relationship can be approximately linear. As an example, the relationship shown in plot 600 can be monotonic.

[0136] In view of the above, the method may include estimating the mud resistance Z inside the casing section once the spacing is given by, for example, ultrasonic measurement m (e.g., mud electrical properties). As mentioned, in various cases, the spacing dependence can be monotonic (see e.g. Figure 6 Drawing 600).

[0137] If no data is acquired in a casing section (e.g., a casing section of a wellbore), or if the logging mud changes, the method can estimate an online value of the mud resistance, where, for example, two sensors are located on the drill collar through two different grooves, thereby providing two measurements at two known spacings in front of the same location (e.g., at different times). Such a tool arrangement can be described via a set of equations, such as:

[0138]

[0139] The above set of nonlinear equations can be solved for Z m , since k1 and k2 are known for two spacing values, we can make the following assumption: if the spacing values ​​are not much different, then k(s1)≈k(s2). In this case, Z m Yes and Z f Solutions of unrelated second-order polynomials.

[0140] Given that the mud impedance can be estimated, the formation impedance can also be estimated. Knowledge of the spacing (e.g., from ultrasonic measurements) allows the calculation of the geometric factors k1 and k2, and equation (1) provides (k, Z f ), which is the formation impedance.

[0141] Far away from the fracture, the formation impedance Can be used as a reference background value. As an example, once a borehole imaging tool's sensor passes through a fracture (whose dielectric constant / conductivity is different from the formation), the estimated formation impedance across the fracture can be compared to the background formation impedance, which can reveal how much current increase or decrease occurred when scanning the fracture.

[0142] As an example, the method may consider the response of a wellbore imaging tool to a fracture or multiple fractures. For example, consider Figure 4 Tool 415, wherein electromagnetic modeling in front of a crack or multiple cracks can produce insights into the ability to detect and characterize a crack or multiple cracks.

[0143] Figure 7 An example of a system 700 is shown, wherein a formation 701 (e.g., a rock matrix) includes a wellbore 703, which intersects a fracture 705 extending outward from the wellbore 703, such that fluid in the wellbore can permeate the fracture 705. In three dimensions, the fracture 705 can be represented as a relatively thin plane, and the wellbore 703 can be represented as a tube passing through the relatively thin plane at a specific angle, wherein the wellbore is in fluid communication with the relatively thin plane. As shown, a wellbore imaging tool 711 is disposed in the wellbore 703, wherein the wellbore imaging tool may include an electrical imager 715 and another imager 717, which may be an ultrasonic imager.

[0144] As an example, the model may consider a borehole imaging tool embedded in a borehole filled with OBM. In this example, the formation outside the borehole can be considered as a homogeneous medium and is cut by the fractures filled with OBM. The model can be represented as something like Figure 7 700 and displays the geometry and expected responses. Such a model may consider the expected responses in two different background formations.

[0145] Figure 8 Example plots 810 and 830 of apparent dielectric constant versus conductivity for two different scenarios are shown. In particular, high frequency equivalent impedances corrected for mud effects are shown for two different formations and four fracture thicknesses of 0.5 mm, 1 mm, 2 mm, and 4 mm. In plots 810 and 830, the x-axis is about conductivity, and the y-axis is about the apparent dielectric constant derived from the equivalent impedance. As an example, away from the fracture, a series model between mud impedance (see, e.g., mud marked with circular marks) and formation impedance (see, e.g., formation marked with square marks) can be used to appropriately simulate the equivalent formation impedance. This electrical model is still valid at high resistivity, such as when the button (e.g., electrode button) of an electrical imaging tool is getting closer to the fracture. However, at lower resistivity, when the button is close to the fracture, this simple electrical model does not hold. To explain this phenomenon, the parallel contribution of the fracture can be added to the model.

[0146] As an example, the response can be plotted as a function of distance from the tool button to the crack location to show that when the crack is thick enough, the crack can be distinguished from the background response, with a clear increase in the rejection level as one gets closer to the crack.

[0147] Fig. 9 Example plots 910 and 930 of equivalent impedance versus fracture location and thickness for two different formation background properties (ε=20, σ=1 S / m and ε=10, σ=0.01 S / m) are shown. In the example plots 910 and 930, the fracture is modeled as perpendicular to the wellbore, with the response localized on one side of the fracture because the fracture is symmetric on the other side.

[0148] Analogous to the quantification proposed for conductive fractures with WBM imagers, here the quantity is defined by integrating along the logging direction:

[0149]

[0150] This gives direct information about the fracture thickness when the mud and background formation properties are known.

[0151] Fig.10 Example plots 1010 and 1030 of the integrated value versus fracture thickness in inches are shown. The relationship between fracture thickness and the integrated value tends to be largely linear, e.g., with a factor that depends on the ratio between fracture and formation impedance; it should be noted that in plot 1010, some slight nonlinearity is shown with respect to increasing fracture thickness (th).

[0152] Similar to the water-based mud (WBM) scenario, the following kinds of relationships may exist:

[0153] th≈cA|Z m b .Z f 1-b |

[0154] Therefore, a method can be adopted that can capture at a sufficient level of accuracy, since the impact of impedance is contrasted with this effect.

[0155] As an example, the method can be applied to one or more operating frequencies. For example, multiple tool frequencies can be utilized, wherein data from each of the multiple tool frequencies is processed. When processed at each operating frequency, a relationship between the current leakage of the current integration near the crack and its electrical characteristics and thickness can be established.

[0156] As explained, the wellbore imaging tool may operate at one or more frequencies that may be in a certain range, such as about 1 MHz to about 100 MHz, to conduct an electric current from the tool to the formation, which may pass through an isolation layer of oil-based mud (e.g., an electrical insulator) so that the current propagates from the tool through the oil-based mud and into the formation, which may or may not include fractures, cracks, etc.

[0157] As an example, the method may include estimating the mud resistance Z in one or more ways: m , which can be done based on casing measurements (if available) and / or based on multiple sensors offset in the radial direction (if available). This method can include identifying the fracture location, extent, and background impedance (e.g., formation impedance). This method can include, for example, calculating the effective formation impedance when passing through the fracture based on ultrasonic spacing. This method can also include calculating the integral of the current leakage of the fracture. As an example, this method can include one or more of the following: if the fracture impedance dispersion is comparable to the mud or mud cake impedance dispersion, then testing whether the fracture is open or closed; estimating the fracture aperture according to a formula, assuming that the fracture is filled with whole mud; and for larger fractures, assuming the fracture thickness (e.g., based on ultrasonic data) and estimating the fracture impedance according to a formula.

[0158] An article by Luthi et al., "Fracture apertures from electrical borehole scans" (Geophysics, Vol. 55, No. 7 (July 1990); pp. 821-833), incorporated herein by reference, considers conductive, non-electrically insulating muds. The aforementioned article describes a three-dimensional finite element model for fractures in response to a borehole imaging tool that records high-resolution electrical scans of the borehole wall, where the equation W = cAR b m R l x0 It describes the fracture width W (in mm), formation sensitivity R under two orders of magnitude resistivity contrast between the wellbore mud and the formation. x0 , Mud resistivity R m and the relationship between the additional current A caused by the presence of fractures. In the aforementioned equation, A is the additional current that can be injected into the formation divided by the voltage, integrated along a line perpendicular to the fracture trace. The coefficient c and the exponent b can be obtained numerically by forward modeling. In the Luthi article, it was found that tool spacings up to 2.5 mm and fracture inclinations in the range of 0° to 40° had little effect on the relationship. The Luthi article pointed out that circular areas around multiple locations were integrated to collect excess current, and then the integral geometry was simplified to approximate the line integral A. The resulting fracture aperture ranged from 10 microns to 1 mm. For wider fractures, consistent results on the aperture were obtained by Stoneley wave reflection measurements. The detection threshold for detection and characterization of fractures in the wellbore is approximately 10 microns, while resolving fractures with spacings as small as 1 cm, as well as the azimuthal orientation of the fractures.

[0159] As explained, in the presence of an electrically insulating fluid (such as, for example, an oil-based mud), the method can provide a characterization of fractures, cracks, and the like. In a wellbore drilled in a formation using such an electrically insulating fluid, the method can include characterizing the fractures as one or more of natural fractures, cemented fractures, drilling-induced fractures, and the like. For example, drilling-induced fractures can be open and not cemented, so that drilling fluid can penetrate drilling-induced fractures, while cemented fractures can be closed and will not withstand drilling fluid penetration. Natural fractures may initially be in an open state or a closed state, wherein drilling may change the state. For example, drilling may result in a transition from a closed state to an open state. In such an example, the change in natural fractures may have an impact on the wellbore geomechanics, so that the wellbore may tend to be more fragile at the location of the already opened natural fractures. As mentioned, drilling-induced fractures may occur, which may result in a weakening of the geomechanics of the wellbore.

[0160] As an example, the method may include quantifying the aperture of the fracture as the size of the opening at the wellbore wall of the fracture. In such an example, when the wellbore pressure exceeds the formation pressure, the aperture may provide an indication of how much fluid may infiltrate or otherwise flow into the fracture at a given pressure. With respect to cemented fractures, it may include a cement containing water so that the cemented fractures exhibit a relatively low resistivity, which may be contrasted with open fractures that absorb the electrically insulating oil in the oil-based mud, causing the resistivity to increase. In the case of utilizing water-based mud, as can be appreciated, an open fracture that absorbs water-based mud will not contrast with a cemented fracture as an open fracture that absorbs oil-based mud (e.g., the resistivity of the water-based mud is less than the resistivity of the oil-based mud).

[0161] As an example, when a fracture cluster is encountered in a wellbore, the method may include providing information about fracture density. For example, considering fracture density given as the number of fractures per distance, etc.

[0162] As about Figure 4 As explained in the example of , the data acquired by the borehole imaging tool may be cylindrical surface data, in which sinusoidal wave-type features may be discerned (see, e.g., plot 430 ), which may represent a plane through the borehole (see, e.g., plot 440 ). In this example, although Figure 4 refers to a bedding plane, but a plane may be a fracture, crack, etc. Such cylindrical surface data and / or other related data may be provided for determining the location and orientation of the fracture, crack, etc. For example, the angle of the wellbore and / or the angle of the fracture may be determined (see, e.g., plot 440), where the angle may not be 90° (see, e.g., Figure 7705). This determination may be used for one or more purposes. For example, considering using fracture location and fracture orientation, optionally together with fracture characteristics (such as, for example, one or more of open, closed, aperture, etc.) to evaluate wellbore geomechanics.

[0163] As an example, a model may be generated that may represent fractures in a matrix that may be defined by matrix resistivity (e.g., in regions away from the fractures) as well as their orientation. Such a model may be used to integrate excess current in the region surrounding the fracture (e.g., at the wellbore wall), where the excess current may be used to quantify the aperture of the fracture. As an example, the aperture may be measured at a relatively shallow distance (e.g., a few millimeters) from the wellbore wall. As explained, the model may be used to quantify the aperture of the fracture in the presence of oil and / or other electrically insulating fluids.

[0164] As an example, the method may include acquiring data in a cased section of the wellbore and acquiring data in an open hole section of the wellbore. In such an example, the data from the cased section may be provided for calibration and / or reference value determination.

[0165] As an example, the method may include drilling a wellbore in sections, wherein each successive section has a smaller diameter, so that the wellbore diameter decreases relative to the depth, which may be a measured depth and / or a true vertical depth. As the wellbore gets deeper, the pressure in the annulus filled with mud (e.g., the annulus between the drill string and the wellbore wall, whether cased or open) increases. Therefore, the mud density may be adjusted to ensure a proper balance between the formation pressure and the wellbore pressure. When the wellbore pressure is too high, there is a risk that the mud may flow into the formation and damage the wellbore. Conversely, when the wellbore pressure is too low, formation fluids will flow into the wellbore. As an example, the method may include planning and / or controlling drilling operations, casing operations, etc. based at least in part on fracture assessment. For example, when more natural open fractures are detected and / or when more drilling-induced fractures are detected, the drilling operation may become more conservative in an effort to reduce potential damage to the wellbore wall, which may result in undesirable wellbore instability. It may be intended by this approach to avoid wellbore collapse, which, as explained, may lead to stuck pipe or other complications (eg, in drilling, completion, production, etc.).

[0166] As an example, a method may include characterizing a formation based on borehole imaging tool data acquired in a borehole including an electrically insulating oil. In such an example, the method may include characterizing the formation according to one or more secondary permeabilities. For example, a reservoir may produce fluids via fractures having a permeability that is different from a matrix permeability of the reservoir. In such an example, a reservoir model suitable for use by a fluid flow simulator may directly and / or indirectly utilize one or more secondary permeabilities to achieve the purpose of simulating the flow of fluids from the reservoir to a wellbore (e.g., a completed well, etc.).

[0167] As an example, a method may be utilized to characterize carbonate formations where a porosity model may account for geometric variations in the pores in the carbonate formation. In such an example, a borehole imaging tool may be used to achieve the pore characterization. When utilizing electrical imaging without OBM-related processing as described herein, drilling requires WBM, which, as mentioned, may be damaging to the formation (e.g., dissolving formation components) and / or may not be as lubricating as OBM. With OBM-related processing, drilling may utilize OBM and still obtain electrical imaging data that can be used to properly characterize the formation.

[0168] As an example, a borehole imaging tool may include circuitry that can execute a method of characterizing a formation (which may include characterizations of fractures, cracks, etc.). In such an example, the tool may include a processor and a memory and processor executable instructions stored in the memory to generate information, which may then be stored and / or transmitted. As an example, a drill string may include multiple tools that can communicate with each other directly and / or indirectly. In such an example, one tool may generate information that can be used to control another tool in the tool. For example, consider controlling a directional drilling tool based at least in part on information generated from a borehole imaging tool.

[0169] As explained, the bandwidth for transmitting data from the downhole tool to the surface may be limited (e.g., consider mud pulse telemetry transmission). In the case of limited bandwidth, the ability to generate characterization information downhole can provide faster transmission than transmitting raw data. For example, the raw data can be processed downhole into meaningful information, which can then be compressed, encoded, etc. and transmitted uphole (e.g., to surface equipment) for the purpose of evaluating and / or controlling one or more operations. When the downhole tool includes multiple instruments (some of which can be controllable), the transmission can be from one instrument to another. For example, consider triggering a measurement of one instrument based on fracture-related information generated by a measurement of another instrument. As an example, one or more downhole drilling parameters can be controllable, for example, consider using information generated by one or more downhole instruments to control a tool face parameter of a drill bit. In such an example, tool face parameter control can be intended to improve wellbore geomechanics in the presence of one fracture, multiple fractures, a group of fractures, etc.

[0170] As an example, in Figure 2 One or more representations from electrical imaging tool data are utilized in the system of system 200. For example, consider use in geographic data block 210, surface model block 220, volume model block 230, application block 240 (e.g., well stability assessment 246, etc.), numerical processing block 250, and / or operational decision block 260.

[0171] As an example, the method may include stopping a section of the wellbore and starting a smaller diameter section of the wellbore in response to detection of fracture characteristics indicating possible wellbore damage. Generally, in such situations, a small diameter drill bit will cause less damage than a large diameter drill bit.

[0172] Fig.11 An example of a method 1100 and an example of a system 1190 are shown. As shown, the method 1100 may include an acquisition block 1110 for acquiring data from a borehole imaging tool disposed in a borehole in a formation, wherein the borehole includes an electrically insulating oil-based fluid introduced into the borehole as a drilling lubricant; a determination block 1120 for determining an electrically insulating oil-based fluid impedance and a reference formation impedance based on the data via a circuit model including series terms and parallel terms; and a detection block 1130 for detecting a location of a fracture in the formation based on a change in current from the tool through the electrically insulating oil-based fluid and into the formation, the change in current being obtained by determining an effective formation impedance based on at least a portion of the data at the location and by comparing the effective formation impedance with a reference formation impedance.

[0173] Method 1100 Fig.11 1100 is shown as being associated with various computer readable media (CRM) blocks 1111, 1121, and 1131. Such blocks typically include instructions suitable for execution by one or more processors (or processor cores) to command a computing device or system to perform one or more actions. Although various blocks are shown, a single medium may be configured with instructions to at least partially allow the execution of various actions of method 1100. As an example, a computer readable medium (CRM) may be a non-transitory and non-carrier computer readable storage medium. As an example, one or more of blocks 1111, 1121, and 1131 may be in the form of processor executable instructions.

[0174] exist Fig.11 In the example of , system 1190 includes one or more information storage devices 1191, one or more computers 1192, one or more networks 1195, and instructions 1196. With respect to one or more computers 1192, each computer may include one or more processors (e.g., or processing cores) 1193 and a memory 1194 for storing instructions 1196, which instructions may be executed, for example, by at least one of the one or more processors 1193 (see, for example, blocks 1111, 1121, and 1131). As an example, a computer may include one or more network interfaces (e.g., wired or wireless), one or more graphics cards, a display interface (e.g., wired or wireless), and the like.

[0175] As an example, a method may include: acquiring data from a borehole imaging tool disposed in a borehole in a formation, wherein the borehole includes an electrically insulating oil-based fluid introduced into the borehole as a drilling lubricant; determining the electrically insulating oil-based fluid impedance and a reference formation impedance based on the data via a circuit model including series terms and parallel terms; and detecting the location of a fracture in the formation based on a change in current from the tool through the electrically insulating oil-based fluid and into the formation, the change in current being obtained by determining an effective formation impedance based on at least a portion of the data at the location and by comparing the effective formation impedance to a reference formation impedance. In such an example, the borehole imaging tool may operate at one or more frequencies in the range of about 1 MHz to about 100 MHz. For example, the tool may include circuitry that may select one or more operating frequencies in the range of 1 MHz to 100 MHz; it should be noted that various tools may provide narrower or wider ranges and / or range limits.

[0176] As an example, the electrical insulating oil-based fluid impedance may be determined based on a portion of data acquired in a casing section of a wellbore. In such an example, the casing may be a metal casing located within the wellbore and disposed between the tool and the wellbore wall, such as formed by the formation, wherein, for example, cement may be disposed between an outer surface of the metal casing and the wellbore wall.

[0177] As an example, the electrical insulating oil-based fluid resistance may be determined based on a portion of data acquired by two sensors disposed at two different distances from the wall of the wellbore.

[0178] As an example, the circuit model may include a first fluid impedance term and a second fluid impedance term, wherein the second fluid impedance term is in series with the formation impedance term.As an example, the circuit model may include one or more tool geometry parameters and a spacing parameter.

[0179] As an example, the method may include determining the thickness of the fracture by integrating the difference between the inverse of the effective formation impedance and the inverse of the reference formation impedance with respect to the distance along the wellbore. In such an example, the fracture may include a portion of an electrically insulating oil-based fluid, which may be an oil-based mud used to drill at least a portion of the wellbore. As mentioned, the method may provide fracture detection and / or characterization in one or more types of media, wherein a tool may be inserted into a wellbore in the medium (e.g., a matrix, a formation, etc.).

[0180] As an example, the method may include determining the orientation of the fracture relative to the wellbore. As an example, the method may include determining whether the fracture is open or closed. For example, the method may include determining whether the fracture is open or closed by comparing the fracture impedance dispersion with the electrical insulating oil-based fluid impedance dispersion.

[0181] As an example, the method may include classifying the fracture as a natural fracture or a drilling induced fracture. In such an example, the method may also include classifying the natural fracture as a cemented fracture or a fracture that includes a portion of an electrically insulating oil-based fluid.

[0182] As an example, a borehole imaging tool may include a resistivity unit and an ultrasonic unit. In such an example, the acquired data may include ultrasonic measurement data, wherein the method may include determining a standoff of the borehole imaging tool relative to a wall of the borehole based on the ultrasonic measurement data.

[0183] As an example, a wellbore imaging tool may include a processor that may perform various tasks, such as determination and detection tasks.

[0184] As an example, a borehole imaging tool may include a memory storing information indicating the location of a fracture. In such an example, the information may be transmitted to another downhole tool and / or uphole equipment and / or the memory may be read once the borehole imaging tool is pulled out of the borehole using appropriate equipment, for example.

[0185] As an example, a method may include issuing a control signal to a drilling device performing drilling to extend the wellbore based on the determined location of the fracture achieved by a wellbore imaging tool disposed in the wellbore.

[0186] As an example, a system may include: a processor; a memory accessible to the processor; and processor-executable instructions stored in the memory, the processor-executable instructions for commanding the system to: acquire data from a borehole imaging tool disposed in a borehole in a formation, wherein the borehole includes an electrically insulating oil-based fluid introduced into the borehole as a drilling lubricant; determine the electrically insulating oil-based fluid impedance and a reference formation impedance based on the data via a circuit model including series terms and parallel terms; and detect the location of a fracture in the formation based on a change in current from the tool through the electrically insulating oil-based fluid and into the formation, the change in current being obtained by determining an effective formation impedance based on at least a portion of the data at the location and by comparing the effective formation impedance to a reference formation impedance. In such an example, the processor and memory may be part of the borehole imaging tool. As an example, the system may include an electrical imaging unit and an additional ultrasonic imaging unit.

[0187] As an example, one or more non-transitory computer-readable storage media may include processor-executable instructions for commanding a computing system to: acquire data from a borehole imaging tool in a borehole disposed in a formation, wherein the borehole includes an electrically insulating oil-based fluid introduced into the borehole as a drilling lubricant; determine the electrically insulating oil-based fluid impedance and a reference formation impedance based on the data via a circuit model including series terms and parallel terms; and detect the location of a fracture in the formation based on a change in current from the tool through the electrically insulating oil-based fluid and into the formation, the change in current being obtained by determining an effective formation impedance based on at least a portion of the data at the location and by comparing the effective formation impedance to a reference formation impedance. In such an example, the circuit model may include a first fluid impedance term and a second fluid impedance term, wherein the second fluid impedance term is connected in series with the formation impedance term. For example, in Figure 5 In the equivalent circuit 500 which can be a circuit model or a part of a circuit model, item Z 泥浆1 With item Z 地层 In series, while item Z 泥浆2 With the series term Z 泥浆1 and Z 地层 In parallel. Figure 5 The symbols in make use of "1" and "2", but the term Z 泥浆1 can be called the second fluid impedance, and the term Z 泥浆2 It may be referred to as the first fluid impedance. As explained, the circuit model may include one or more tool geometry parameters and spacing parameters.

[0188] As an example, a computer program product may include one or more computer-readable storage media, which may include processor-executable instructions for instructing a computing system to perform one or more methods and / or one or more parts of a method.

[0189] In some embodiments, one or more methods may be performed by a computing system. Fig.12 An example of a system 1200 is shown, which may include one or more computing systems 1201-1, 1201-2, 1201-3, and 1201-4, which may be operatively coupled via one or more networks 1209, which may include wired networks and / or wireless networks.

[0190] By way of example, a system may include a single computer system or an arrangement of distributed computer systems. Fig.12 In the example of , computer system 1201-1 may include one or more modules 1202, which may be or may include, for example, processor-executable instructions that can be executed to perform various tasks (e.g., receive information, request information, process information, simulate, output information, etc.).

[0191] As an example, the modules may be executed independently or in conjunction with one or more processors 1204, which are operatively coupled to one or more storage media 1206 (e.g., via wires, wirelessly, etc.). As an example, one or more of the one or more processors 1204 may be operatively coupled to at least one of the one or more network interfaces 1207. In such an example, the computer system 1201-1 may transmit and / or receive information, for example, via one or more networks 1209 (e.g., consider one or more of the Internet, a private network, a cellular network, a satellite network, etc.). As shown, one or more other components 1208 may be included in a computer system such as computer system 1201-1.

[0192] As an example, computer system 1201-1 may receive information from and / or transmit information to one or more other devices, which may be or may include, for example, one or more of computer systems 1201-2, etc. The device may be located at a different physical location than computer system 1201-1. As an example, the location may be, for example, a processing facility location, a data center location (e.g., a server farm, etc.), a drilling rig location, a well site location, a downhole location, etc.

[0193] As an example, a processor may be or may include a microprocessor, a microcontroller, a processor module or subsystem, a programmable integrated circuit, a programmable gate array, or another control or computing device.

[0194] As an example, storage media 1206 can be implemented as one or more computer-readable or machine-readable storage media. As an example, storage can be distributed within and / or between multiple internal and / or external enclosures of the computing system and / or additional computing systems.

[0195] As an example, a storage medium or multiple storage media may include one or more different forms of memory, including: semiconductor memory devices, such as dynamic or static random access memory (DRAM or SRAM), erasable and programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM), and flash memory; disks, such as fixed disks, floppy disks, and removable disks; other magnetic media, including magnetic tape; optical media, such as compact disks (CDs) or digital video disks (DVDs), Blu-ray disks, or other types of optical storage devices; or other types of storage devices.

[0196] As an example, the storage medium or media may be located in the machine running the machine-readable instructions, or located at a remote site from which the machine-readable instructions may be downloaded over a network for execution.

[0197] As examples, various components of a system such as, for example, a computer system may be implemented in hardware, software, or a combination of both hardware and software (eg, including firmware), including one or more signal processing circuits and / or application specific integrated circuits.

[0198] As an example, a system may include a processing device, which may be or may include a general purpose processor or a dedicated chip (eg, or chipset) such as an ASIC, FPGA, PLD, or other suitable device.

[0199] Fig.13 Components of an example of a computing system 1300 and an example of a networking system 1310 with a network 1320 are shown. As an example, Figure 4 The digital microscopy system 400 or another digital microscopy system may include Fig.13 The various features of system 1300 and / or system 1310 and / or operatively coupled to Fig.13 One or more instances of system 1300 and / or system 1310.

[0200] exist Fig.13 In the example, system 1300 includes one or more processors 1302, memory and / or storage components 1304, one or more input and / or output devices 1306, and bus 1308. In an example embodiment, instructions may be stored in one or more computer-readable media (e.g., memory / storage components 1304). Such instructions may be read by one or more processors (e.g., processor 1302) via a communication bus (e.g., bus 1308), which may be wired or wireless. One or more processors may execute such instructions to implement (in whole or in part) one or more properties (e.g., as part of a method). A user may view output from a process and interact with the process via an I / O device (e.g., device 1306). In an example embodiment, a computer-readable medium may be a storage component, such as a physical memory storage device, such as a chip, a chip on a package, a memory card, etc. (e.g., a computer-readable storage medium).

[0201] In an example embodiment, the components may be distributed, such as distributed in a network system 1310. The network system 1310 includes components 1322-1, 1322-2, 1322-3, ... 1322-N. For example, component 1322-1 may include a processor 1302, and component 1322-3 may include a memory accessible to processor 1302. In addition, component 1322-2 may include an I / O device for displaying and optionally interacting with a method. Network 1320 may be or may include the Internet, an intranet, a cellular network, a satellite network, etc.

[0202] As an example, the device may be a mobile device including one or more network interfaces for conveying information. For example, the mobile device may include a wireless network interface (e.g., operable via IEEE 802.11, ETSI GSM, BLUETOOTH, satellite, etc.). As an example, the mobile device may include multiple components, such as a main processor, a memory, a display, a display graphics circuit (e.g., optionally including a touch and gesture circuit), a SIM slot, an audio / video circuit, a motion processing circuit (e.g., an accelerometer, a gyroscope), a wireless LAN circuit, a smart card circuit, a transmitter circuit, a GPS circuit, and a battery. As an example, the mobile device may be configured as a cellular phone, a tablet computer, etc. As an example, the method may be implemented (e.g., in whole or in part) using a mobile device. As an example, the system may include one or more mobile devices.

[0203] As an example, the system may be a distributed environment, such as a so-called "cloud" environment, in which various devices, components, etc. interact for purposes of data storage, communication, computing, etc. As an example, a device or system may include one or more components for communicating information via one or more of the Internet (e.g., where communication is performed via one or more Internet protocols), a cellular network, a satellite network, etc. As an example, a method may be implemented in a distributed environment (e.g., in whole or in part as a cloud-based service).

[0204] As an example, information may be input from a display (e.g., consider a touch screen), output to a display, or both. As an example, information may be output to a projector, a laser device, a printer, etc., so that the information can be viewed. As an example, information may be output stereoscopically or holographically. With respect to printers, consider 2D or 3D printers. As an example, a 3D printer may include one or more substances that can be output to construct a 3D object. For example, data may be provided to a 3D printer to construct a 3D representation of an underground stratum. As an example, layers (e.g., a ground plane, etc.) may be constructed in 3D, geological bodies, etc. may be constructed in 3D. As an example, wellbores, fractures, etc. may be constructed in 3D (e.g., as positive structures, as negative structures, etc.).

[0205] Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications may be made in the example embodiments. It is therefore intended that all such modifications be included within the scope of the present disclosure as defined in the appended claims. In the claims, means-plus-function clauses are intended to cover structures described herein as performing the recited function, and not only structural equivalents, but also equivalent structures. Thus, while a nail and a screw may not be structural equivalents because a nail employs a cylindrical surface to fasten wooden parts together, while a screw employs a helical surface, in the context of fastening wooden parts, a nail and a screw may be equivalent structures.

Claims

1. A method comprising: acquiring data from a borehole imaging tool disposed in a borehole in the earth formation, wherein the borehole includes an electrically insulating oil-based fluid introduced into the borehole as a drilling lubricant; determining an electrical insulating oil-based fluid impedance and a reference formation impedance based on the data via a circuit model including series terms and parallel terms; as well as The location of the fracture in the formation is detected based on a change in electrical current from the tool through the electrically insulating oil-based fluid and into the formation, the change in electrical current being obtained by determining an effective formation impedance based on at least a portion of the data at the location and by comparing the effective formation impedance with the reference formation impedance.

2. The method of claim 1, wherein the borehole imaging tool operates at a frequency in the range of 1 MHz to 100 MHz.

3. The method of claim 1, wherein the electrical insulating oil-based fluid impedance is determined based on a portion of data acquired in a casing section of the wellbore.

4. The method of claim 1, wherein the electrical insulating oil-based fluid impedance is determined based on a portion of data acquired by two sensors disposed at two different distances from a wall of the wellbore.

5. The method of claim 1, wherein the circuit model comprises a first fluid impedance term and a second fluid impedance term, wherein the second fluid impedance term is connected in series with a formation impedance term.

6. The method of claim 1, wherein the circuit model includes one or more tool geometry parameters and spacing parameters.

7. The method of claim 1 , further comprising determining a thickness of the fracture by integrating a difference between the inverse of the effective formation resistivity and the inverse of the reference formation resistivity with respect to a distance along the wellbore, wherein the fracture comprises a portion of the electrically insulating oil-based fluid.

8. The method of claim 1, further comprising determining an orientation of the fracture relative to the wellbore.

9. The method of claim 1, further comprising determining whether the crack is open or closed, wherein determining comprises comparing the crack impedance dispersion to an electrical insulating oil-based fluid impedance dispersion.

10. The method of claim 1, further comprising classifying the fracture as a natural fracture or a drilling-induced fracture.

11. The method of claim 10, further comprising classifying the natural fractures as cemented fractures or fractures that include a portion of the electrical insulating oil-based fluid.

12. The method of claim 1, wherein the wellbore imaging tool comprises a resistivity unit and an ultrasonic unit, wherein the data comprises ultrasonic measurement data, and the method further comprises determining a standoff of the wellbore imaging tool relative to a wall of the wellbore based on the ultrasonic measurement data.

13. The method of claim 1, wherein the borehole imaging tool includes a processor that performs the determining and the detecting, and wherein the borehole imaging tool includes a memory that stores information indicative of the location of the fracture.

14. The method of claim 1, further comprising issuing a control signal to a drilling device performing drilling to extend the wellbore based on the location of the fracture.

15. A system comprising: processor; a memory accessible to the processor; as well as processor-executable instructions stored in the memory, the processor-executable instructions being used to instruct the system to: acquiring data from a borehole imaging tool disposed in a borehole in the earth formation, wherein the borehole includes an electrically insulating oil-based fluid introduced into the borehole as a drilling lubricant; determining an electrical insulating oil-based fluid impedance and a reference formation impedance based on the data via a circuit model including series terms and parallel terms; as well as The location of the fracture in the formation is detected based on a change in electrical current from the tool through the electrically insulating oil-based fluid and into the formation, the change in electrical current being obtained by determining an effective formation impedance based on at least a portion of the data at the location and by comparing the effective formation impedance with the reference formation impedance.

16. The system of claim 15, wherein the processor and the memory are part of the wellbore imaging tool.

17. The system of claim 16, further comprising an electrical imaging unit and an ultrasound imaging unit.

18. One or more non-transitory computer-readable storage media comprising processor-executable instructions for instructing a computing system to: acquiring data from a borehole imaging tool disposed in a borehole in the earth formation, wherein the borehole includes an electrically insulating oil-based fluid introduced into the borehole as a drilling lubricant; determining an electrical insulating oil-based fluid impedance and a reference formation impedance based on the data via a circuit model including series terms and parallel terms; and The location of the fracture in the formation is detected based on a change in electrical current from the tool through the electrically insulating oil-based fluid and into the formation, the change in electrical current being obtained by determining an effective formation impedance based on at least a portion of the data at the location and by comparing the effective formation impedance with the reference formation impedance.

19. The one or more non-transitory computer-readable media of claim 18, wherein the circuit model includes a first fluid impedance term and a second fluid impedance term, wherein the second fluid impedance term is in series with a formation impedance term.

20. The one or more non-transitory computer-readable media of claim 18, wherein the circuit model includes tool geometry parameters and spacing parameters.

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