Processes and systems for imaging of rocks around a borehole

Abstract

Methods and systems are disclosed. The methods may include obtaining a sonic data set. The method may define a three-dimensional ("3D") computational grid, wherein the 3D computational grid represents a geological volume. The method may further define at least one computational surface transecting the 3D computational grid. Using the 3D computational grid, the method may further comprise simulating forward-in-time propagation of a 3D source wavefield and simulating backward-in-time of a 3D receiver wavefield and storing a plurality of time snapshots of each wavefield at locations defined by the at least one computational surface. The method may include forming, using the sonic imaging system, a sonic image of the geological volume over each computational surface based on a combination of partial images formed from the snapshots.

Description

PROCESSES AND SYSTEMS FOR IMAGING OF ROCKS AROUND A BOREHOLEBACKGROUND

[0001] Sonic borehole surveying is a tool to reveal the structure of rocks around a borehole. A sonic logging tool includes at least one sonic source and several receivers mounted on an elongated sonde body. During the sonic survey, the tool moves along the borehole. At each measurement depth, the sonic source emits an acoustic signal. Acoustic energy penetrates the surrounding rocks through the borehole well and propagates in the geological medium. Structural features (fractures, interfaces, etc.) reflect part of the energy. Receivers record this scattered wavefield together with the wavefield propagating in the borehole. One purpose of sonic imaging is to create an image of a geologic medium based on a recorded sonic logging signal.

[0002] To determine the image of the geologic medium, including the presence of fractures, a sonic data set may be processed. Processing the sonic data set may include a sequence of steps designed to correct a number of issues, such as near-borehole effects, noise, and irregularities in the acquisition, etc. In another step in processing the sonic data set a velocity model may be determined representing the speed at which sonic waves propagate at various points within subsurface. The sonic data set and the velocity model may be combined using a process called “migration” to form an image of the subsurface. Migrating a data set may take a substantial amount of computational time and memory relative to other processing steps. Typically, the image displays points of high and low reflection amplitude on a color scale or grayscale on a dense two-dimensional (“2D”) or three-dimensional (“3D”) grid of points representing the subsurface around the sonic survey area. Such an image may then be interpreted, together with other information, to determine geological structures surrounding the borehole based on the image of the geological volume that may influence fluid flow within the subsurface.

[0003] An image may be used to determine a hydraulic fracturing plan. Hydraulic fracturing is carried out by pumping fluid into a geologic medium until the geologic medium fractures. Proppant may be injected into the fractures to prop open the fractures after the pumping is completed and the fluid pressure reduced to prevent the fractures from closing due tooverburden pressure. The hydraulic fracturing may be used to increase fluid flow toward a well.SUMMARY

[0004] 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.

[0005] In some aspects, the techniques described herein relate to a method of generating an image of a geological volume around a borehole. The method may include obtaining a sonic data set using a sonic imaging tool. The sonic data set includes, for each of a plurality of sonic imaging tool positions, a plurality of sonic traces wherein each sonic trace is recorded by one of a plurality of sonic receivers azimuthally distributed around an axis of the sonic imaging tool and excited by a sonic source disposed in the sonic imaging tool. Using a sonic imaging system and for each sonic imaging tool position, the method may also include defining a three-dimensional ("3D") computational grid, wherein the 3D computational grid represents the geological volume, defining at least one computational surface transecting the 3D computational grid and sparsely distributed in azimuth around the axis. Using the 3D computational grid, the method also includes simulating forward-in-time propagation of a 3D source wavefield and storing a plurality of time snapshots of the 3D source wavefield at locations defined by the at least one computational surface and simulating, using the plurality of sonic traces, backward-in-time propagation of a 3D receiver wavefield and storing a plurality of time snapshots of the 3D receiver wavefield at locations defined by the at least one computational surface. The method may further include forming a partial image of an intersection of a portion of the geological volume with each computational surface based, at least in part, on the snapshots of the 3D source wavefield, the snapshots of the 3D receiver wavefield, and an imaging condition. The method may still further include forming, using the sonic imaging system, a sonic image of the geological volume over each computational surface based on a combination of the partial images.

[0006] In some aspects, the techniques described herein relate to a system for generating an image of a geological volume around a borehole, including a sonic imaging tool, configuredto obtain a sonic imaging data set, wherein the sonic data set includes, for each of a plurality of sonic imaging tool positions, a plurality of sonic traces each sonic trace recorded by one of a plurality of sonic receivers azimuthally distributed around an axis of the sonic imaging tool and excited by a sonic source disposed in the sonic imaging tool. The system also includes a sonic imaging system, configured to, for each sonic imaging tool position, define the 3D computational grid, wherein the 3D computational grid represents the geological volume. The sonic imaging system may also be configured to define at least one computational surface transecting the 3D computational grid and sparsely distributed in azimuth around the axis. The sonic imaging system may also be configured to, using the 3D computational grid, simulate forward-in-time propagation of a 3D source wavefield and store a plurality of time snapshots of the 3D source wavefield at locations defined by the at least one computational surface. The sonic imaging system may also be configured to, using the 3D computational grid, simulate, using the plurality of sonic traces, backward-in-time propagation of a 3D receiver wavefield and store a plurality of time snapshots of the 3D receiver wavefield at locations defined by the at least one computational surface. The sonic imaging system may also be configured to form a partial image of an intersection of a portion of the geological volume with each computational surface based, at least in part, on the snapshots of the 3D source wavefield, the snapshots of the 3D receiver wavefield, and an imaging condition. The sonic imaging system may also be configured to form a sonic image of the geological volume over each computational surface based on a combination of the partial images.

[0007] Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.

[0008] BRIEF DESCRIPTION OF DRAWINGS

[0009] Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency.

[0010] FIG. 1 illustrates a well environment in accordance with one or more embodiments.

[0011] FIG. 2 shows expected imaging resolution and penetration ranges of various acoustic systems at different frequencies in accordance with one or more embodiments.

[0012] FIG. 3 shows a sonic imaging tool in accordance with one or more embodiments.

[0013] FIG. 4 depicts a sonic imaging tool and radial profiling diagram in accordance with one or more embodiments.

[0014] FIG. 5 shows sonic waveforms (“sonic traces”) in accordance with one or more embodiments.

[0015] FIG. 6 depicts a two-dimensional computational surface within a three-dimensional computational grid in accordance with one or more embodiments.

[0016] FIG. 7 shows a cylindrical coordinate system in accordance with one or more embodiments.

[0017] FIG. 8A depicts a borehole with at least one computational surface intersecting the borehole in accordance with one or more embodiments.

[0018] FIG. 8B depicts a borehole with at least one computational surface intersecting the borehole in accordance with one or more embodiments.

[0019] FIG. 9A-H illustrates sonic traces organized into a gather in accordance with one or more embodiments.

[0020] FIG. 10 shows a flowchart in accordance with one or more embodiments.

[0021] FIG. 11 shows a flowchart in accordance with one or more embodiments.

[0022] FIG. 12 shows a computer system in accordance with one or more embodiments.

[0023] FIG. 13 shows a graphical processing unit in accordance with one or more embodiments.

[0024] FIG. 14 shows an example embodiment of a hydraulic fracturing plan guided by geological structures in accordance with one or more embodiments.DETAILED DESCRIPTION

[0025] In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

[0026] Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application). The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before,” “after,” “single,” and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.

[0027] It is to be understood that the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, reference to “a sonic signal” includes reference to one or more of such signals.

[0028] Terms such as “approximately,” “substantially,” etc., mean that the recited characteristic, parameter, or value need not be achieved exactly, but that deviations or variations, including for example, tolerances, measurement error, measurement accuracy limitations and other factors known to those of skill in the art, may occur in amounts that do not preclude the effect the characteristic was intended to provide.

[0029] It is to be understood that one or more of the steps shown in the flowchart may be omitted, repeated, and / or performed in a different order than the order shown. Accordingly, the scope disclosed herein should not be considered limited to the specific arrangement of steps shown in the flowchart.

[0030] Although multiple dependent claims are not introduced, it would be apparent to one of ordinary skill that the subject matter of the dependent claims of one or more embodiments may be combined with other dependent claims.

[0031] In the following description of FIGs. 1-14, any component described with regard to a figure, in various embodiments disclosed herein, may be equivalent to one or more like- named components described with regard to any other figure. For brevity, descriptions of these components will not be repeated with regard to each figure. Thus, each and every embodiment of the components of each figure is incorporated by reference and assumed to be optionally present within every other figure having one or more like-named components. Additionally, in accordance with various embodiments disclosed herein, any description of the components of a figure is to be interpreted as an optional embodiment which may be implemented in addition to, in conjunction with, or in place of the embodiments described with regard to a corresponding like-named component in any other figure.

[0032] Methods and systems are disclosed for generating an image of a geological volume around a borehole using a low memory three-dimensional (“3D”) reverse time migration (“RTM”) for sonic logging data. In some embodiments, the image (such as a sonic image) of a geologic volume around a borehole may image geologic features around the borehole. One such geologic feature is a fracture, a crack in the rock volume that may influence flow of fluid such as water and oil. Fractures may impede or facilitate fluid flow in certain directions depending on an orientation of the fracture. The image of geologic features and layers may be used to develop a hydraulic fracturing plan among other uses.

[0033] FIG. 1 shows a schematic diagram in accordance with one or more embodiments. FIG. 1 illustrates a well environment (100) that may include a well system (101), a well (102) having a borehole (104) extending into a formation (106). The borehole (104) having a central axis (105) may include a bored hole that extends from a surface of the earth (116) into a target zone of the formation (106), such as a reservoir (not shown). The formation (106) may include various formation characteristics of interest, such as formation porosity, formation permeability, resistivity, water saturation, and free water level (FWL). Porosity may indicate how much void space exists in a particular rock within an area of interest in the formation (106), where oil, gas or water may be trapped. Permeability may indicate the ability of liquids and gases to flow through the rock within the area of interest. Resistivity may indicate how strongly rock or fluid within the formation (106) opposes the flow of electrical current. For example, resistivity may be indicative of the porosity of the formation (106) and the presence of hydrocarbons. More specifically, resistivity may be relatively lowfor a formation that has high porosity and a large amount of water, and resistivity may be relatively high for a formation that has low porosity or includes a large quantity of hydrocarbons. Water saturation may indicate the fraction of water in a given pore space.

[0034] Keeping with FIG. 1, the well environment (100) may include a drilling system (110), a logging system (112), and a control system (144). The drilling system (110) may include a drill string, drill bit or a mud circulation system for use in boring the borehole (104) into the formation (106). The control system (144) may include hardware or software for managing drilling operations or maintenance operations. For example, the control system (144) may include one or more programmable logic controllers (PLCs) that include hardware or software with functionality to control one or more processes performed by the drilling system (110). Specifically, a programmable logic controller may control valve states, fluid levels, pipe pressures, warning alarms, or pressure releases throughout a drilling rig. In particular, a programmable logic controller may be a ruggedized computer system with functionality to withstand vibrations, extreme temperatures (for example, ~ 575° C), wet conditions, or dusty conditions, for example, around a drilling rig. Without loss of generality, the term “control system” may refer to a drilling operation control system that is used to operate and control the equipment, a drilling data acquisition and monitoring system that is used to acquire drilling process and equipment data and to monitor the operation of the drilling process, or a drilling interpretation software system that is used to analyze and understand drilling events and progress.

[0035] The logging system (112) may include one or more logging tools (113), such as a nuclear magnetic resonance (NMR) logging tool or a sonic logging tool, for use in generating well logs (140) of the formation (106). For example, a logging tool may be lowered into the borehole (104) to acquire measurements as the tool traverses a depth interval (130) (for example, targeted reservoir section) of the borehole (104). The plot of the logging measurements versus depth may be referred to as a “log” or “well log”. Well logs (140) may provide depth measurements of the well (102) that describe such reservoir characteristics as formation porosity, formation transit time, formation permeability, resistivity, water saturation, and the like. The resulting logging measurements may be stored or processed or both, for example, by the control system (144), to generate corresponding well logs (140) forthe well (102). A well log may include, for example, recorded sonic waveforms versus true vertical depth (TVD) across the depth interval (130) of the borehole (104).

[0036] Multiple types of logging techniques are available for determining various reservoir characteristics, and a particular form of logging may be selected and used based on the logging conditions and the type of desired measurements. For example, sonic logging measures an interval transit time of the formation. Thus, sonic logs may measure one or more velocities of sonic compressional and / or shear waves through the formation. In so doing, sonic logs may be used alone, or in combination with other logs, to determine both porosity and permeability as well as the types of fluids present in the pore spaces. For determining permeability, another type of logging may be used that is called spontaneous potential (SP) logging. SP logging may determine the permeabilities of rocks in the formation (106) by measuring the amount of electrical current generated between a fluid (142) such as a drilling fluid produced by the drilling system (110) and formation water that is present in pore spaces of the reservoir rock. Porous sandstones with high permeabilities may generate more electricity than impermeable shales. Thus, SP logs may be used to identify sandstones from shales.

[0037] To determine travel times in the formation (106), various types of logging techniques may be used. For example, the logging system (112) may measure the speed that acoustic waves travel through rocks in the formation (106). This type of logging may generate compressional and / or shear wave sonic logs, which are also called sonic logs and acoustic logs. In general, sound waves may travel faster through shales than through sandstones because shales generally have greater density than sandstones. Likewise, density logging may also determine porosity measurements by directly measuring the density of the rocks in the formation (106). In addition, neutron logging may determine porosity measurements by assuming that the reservoir pore spaces within the formation (106) are filled with either water or oil and then measuring the amount of hydrogen atoms (that is, neutrons) in the pores. Furthermore, the logging system (112) may determine geological data for the well (102) by measuring corresponding well logs (140) for the well (102).

[0038] Turning now to FIG. 2, FIG. 2 shows expected imaging resolution and penetration ranges of various imaging systems in accordance with one or more embodiments. Sonic imaging systems are useful for imaging a geologic volume around the borehole (104), forexample, imaging a geologic volume with a source signal wavelength up to 1 meter (“m”) to achieve a vertical resolution between 1 centimeter (“cm”) to 1 m depending on various conditions such as the rock characteristics. The range and resolution of sonic logging tools is able to resolve fractures.[0039J FIG. 3 shows a sonic imaging tool (200) in accordance with one or more embodiments. This sonic imaging tool design is one of many possible sonic imaging tool designs and is not intended to be limiting on the scope of the invention. The sonic imaging tool (200) includes a sonic source (215) and a plurality of sonic receivers (210). The sonic source (215) may be a dipole or a monopole but not limited to this. One of the plurality of sonic receivers (210) may be a dipole receiver. The sonic source (215) and the plurality of sonic receivers (210) are operatively disposed in the sonic imaging tool (200), which may be a steel pipe. The plurality of sonic receivers (210) may be azimuthally distributed around a tool axis (205) of the sonic imaging tool (200) and include one or more principal axes (211). Each of the principal axes may be aligned, for example, with one of the plurality of receivers and its principal recording orientation. In some embodiments, the principal axes (211) may be oriented relative to the tool axis (205) such as perpendicular relative to the tool axis (205). The plurality of sonic receivers (210) detects and record pressure fluctuations of a fluid (142) filling the borehole caused by incident sonic waves. Although eight sonic receivers are shown in FIG. 3, in some embodiments there may be a greater or lesser number of sonic receivers. The sonic imaging tool (200) may include an isolation joint (207). The isolation joint (207) is disposed within the sonic imaging tool (200) and positioned between the sonic source (215) and the plurality of sonic receivers (210). The isolation joint (207) mitigates noise cross-contamination of the sonic source (215) and the plurality of sonic receivers (210) along the sonic imaging tool (200). One or more source activation locations (also known as firing / excitation location) (317) are locations at which the sonic source (215) generates sound.

[0040] Referring now to FIG. 4, the sonic imaging tool (200) is configured to obtain a sonic imaging data set, in accordance with one or more embodiments. FIG. 4 shows a schematic image of the sonic slowness of the formation, a geometry of a sonic source and sonic receiver array, and the ray paths followed by sonic energy between the source and receivers, in accordance with one or more embodiments. FIG. 4 shows a borehole (104), the seismicsource (215), the plurality of sonic receivers (210), and a radial profile through the formation (106). In some embodiments the plurality of sonic receivers (210) forms an evenly spaced array as depicted in FIG. 4. In other embodiments (not shown) the plurality of sonic receivers (210) may be unevenly spaced. Although 13 sonic receivers are shown in FIG. 4, in some embodiments there may be a greater or lesser number of sonic receivers. In FIG. 4, the Y axis of the figure depicts the distance from the central axis (105), wherein the top edge at 0 refers to the central axis. The X axis of the figure depicts the distance along the borehole (104). The plurality of sonic receivers (210) is each spaced at a unique distance from the sonic source (215).

[0041] The top of FIG. 4, Y=0, represents the central axis (105). The sonic imaging tool (200) is depicted as being disposed along the central axis (105). Below the sonic imaging tool (200), the first layer represents the fluid (142) filling the borehole (104), and the second layer below the fluid (142) represents the formation (106). The shade of the formation (106) represents a slowness (inverse of velocity) of sonic wave propagation, wherein the darker the shade of the background, the slower the velocity. The slowness may be the slowness of compressional waves generated by a monopole source. The grayscale (360) at the bottom of FIG. 4 indicates value of the slowness. The slowness may vary axially along the borehole (104), i.e., along the X axis of FIG. 4 and the slowness may vary radially perpendicular, i.e., along the Y axis of FIG. 4.

[0042] In accordance with one or more embodiments, a pulse of sonic energy may be generated by the sonic source (215) and may penetrate into the formation (106) and be received by each of the plurality of sonic receivers (210). FIG. 4 further shows a plurality of ray paths (330) from the sonic source (215) to the plurality of sonic receivers (210), that indicate the path followed by the pulse of sonic energy. The plurality of sonic receivers (210) records the sonic waves illustrated by the plurality of ray paths (330). For example, the increment of axial distance may be 6 inches (15 cm). Moving the sonic imaging tool (200) causes the sonic source (215) and the plurality of sonic receivers (210) to move in unison, such that the unique distance between the sonic source (215) and each of the plurality of sonic receivers (210) remains unchanged, while the sonic source (215) moves from one source activation location (317) to the next. The sonic source (215) may be activated, and the resulting sonic waves recorded at each source activation location (317) after eachincremental move along the central axis (105). The recorded sonic waves at each activation location may be combined to form a sonic data set.

[0043] The sonic imaging tool (200) is moved along a borehole, such as the borehole (104) in FIG. 1. FIG. 5 shows an example embodiment of the sonic data set (404) having one or more portions. As the sonic imaging tool (200) is activated at each activation location (317), a plurality of sonic waveforms is recorded by the plurality of sonic receivers (210). The horizontal axis (450) represents borehole depth, and the vertical axis (460) represents recording time after the activation of the sonic source (215) within the borehole ( 104). Each column of the sonic data set (404) represents one of the plurality of sonic waveforms (with darker shades representing positive amplitudes of the pressure fluctuation generated by a sonic wave, and lighter shades representing negative amplitudes).

[0044] For each of a plurality of sonic imaging tool positions, the sonic data set (404) comprises a plurality of sonic traces each corresponding to a unique combination of one of the plurality of sonic receivers (210) and one of the source activation locations (317) in the borehole (104). Each of the plurality of sonic traces is recorded by one of the plurality of sonic receivers (210) azimuthally distributed around a tool axis (205) of the sonic imaging tool and excited by the sonic source (215) disposed in the sonic imaging tool (200). Each portion of the sonic data set (404) represents the plurality of sonic traces all recorded by one of the plurality of sonic receivers (210) at a fixed unique distance from the sonic source (215).

[0045] FIG. 6 illustrates a 3D computational grid (500) and a 2D computational surface (510), in accordance with one or more embodiments. The 3D computational grid (500) provides a digital representation of a portion of the formation surrounding the borehole and may include one or more grid cells. One or more grid cells may digitally store one or more geologic variables such as velocity, temperature, porosity, and the like without limit. For example, one or more geologic variables may be from the well logs measured from the one or more logging tools (113), calculated from the well logs, predicted values of the sonic wavefield, or combination thereof. The one or more grid cells may be irregularly sized, congruent or a combination thereof.

[0046] The at least one computational surface (510) may have an arbitrary orientation in relation to the borehole (104). In accordance with one or more embodiments, the at least one computational surface (510) may be a two-dimensional (“2D”) plane but when the central axis is not straight of at least a portion, the at least one computational surface may be curved. A curved computational surface is often termed a “curtain.” The at least one computational surface (510) may include a surface grid having grid lines. The surface grid spacing may be equidistant between grid lines but is not limited to this. Further, although illustrated as a single computational surface (510), the at least one computational surface (510) may be implemented as multiple computational surfaces (510). In the exemplary embodiment shown in FIG. 6, the at least one computational surface (510) may intersect the tool axis (205). The plurality of sonic receivers ( 10) may be azimuthally distributed around the tool axis (205). The activation location (317) may be positioned along the tool axis (205).

[0047] Referring now to FIG. 7, the 3D computational grid (500) includes a coordinate system (620) such as a Cartesian coordinate system or a cylindrical coordinate system. The coordinate system (620) may include one or more spatial dimensions. In accordance with one or more embodiments with one or more coordinate axes (660), a cylindrical coordinate system may have the coordinate axis (660) that coincides with the central axis (105) of the borehole (104) or the tool axis (205). Any point and / or grid cell around the coordinate axis (660) can be located by the one or more spatial dimensions such as a radial distance (“r”) (normal from the coordinate axis (660)) (630), a borehole angle (“0”) (640), and a borehole depth (“Z”) (650). In other embodiments, the area of interest of the formation (106) may be defined based on the Cartesian coordinate system and the one or more spatial dimensions with one or more coordinate axes (660) denoted, for example, x, y, and z in FIG. 6.

[0048] FIG. 8A illustrates an example embodiment of the at least one computational surface (510) containing the borehole (104) in accordance with one or more embodiments. In other embodiments, the at least one computational surface may contain, for example, the borehole axis and the vertical, the borehole axis and the horizontal, the borehole axis and a vector at a fixed angle, e.g. 45 degrees to the vertical. In other embodiments, the at least one computational surface may be oriented to which the borehole is orthogonal. In other embodiments, the at least one computational surface is defined by fixed external coordinate system such as a north-south direction and the vertical. The at least one computationalsurface (510) may be sparsely distributed in azimuth around the coordinate axis. In some embodiments, the at least one computational surface (510) may be oriented aligned with one of the coordinate axes (660). In other embodiments, the at least one computational surface may be oriented aligned with one of the one or more principal axes (211) of one of the plurality of sonic receivers (210). The alignment of the at least one computational surface (510) with the principal axis of one of the plurality of sonic receivers may improve the imaging of the geologic volume as the signal-to-noise ratio in this alignment would be higher relative to other orientations.

[0049] In an example embodiment, FIG. 8B illustrates a curtain (520) that transects the 3D computational grid (500) and that represents a vertical computational surface relative to the surface of the earth (116) that follows lateral deviations of the central axis (105). In accordance with one or more embodiments, the curtain may include surface grid lines that are, for example, distributed equidistantly along the surface.

[0050] These described orientations and shapes should not be considered limiting as it should be apparent to one skilled in the art that the orientation and the shape of the at least computational surface could be selected from any number of orientations and shapes that are possible in a computational space.

[0051] A number of ways of arranging the sonic data set (404) are possible. FIG. 9A-H illustrates some of these methods of arrangement. FIG. 9 A illustrates the spatial geometry of a common-source gather and common-source gather sonic traces (804) shown in FIG. 9B. In FIG. 9A, the horizontal axis represents location in a horizontal plane of the sonic source (215) and the plurality of sonic receivers (210). The vertical axis represents depth below the surface of the earth (116). Rays emanating from the sonic source (215), reflection from a geologic feature (812) and propagating as reflected sonic waves (816) indicate the path of sonic waves schematically. The sonic waves may reflect when from the geologic feature (812) at one or more reflection points (872) and may be recorded by the plurality of sonic receivers (210).

[0052] This common-source gathers correspond to the physical acquisition of the sonic data set (404) with the sonic waves generated by a single activation of the sonic source (215) being recorded by the plurality of sonic receivers (210). FIG. 9B depicts the recorded sonicdata. In FIG.9B, the horizontal axis indicates the spatial location of the plurality of sonic receivers (210) and the vertical axis indicates time, specifically recording time elapsed after a reference time, such as the time of activation of the sonic source (215). However, from the perspective of processing the sonic data set common-source gathers suffer from the fact that the one or more reflection points (872) on the geologic feature (812) vary from one of the plurality of sonic receivers (210) to another and the time at which the reflected energy (874) is recorded on each one of the plurality of sonic traces (876) varies from one sonic trace to another. The sonic data set (404) includes the plurality of sonic traces (876) in accordance with one or more embodiments.

[0053] Recording of the sonic data set (404) frequently may be reorganized into commonreceiver gathers, such as the geometry of common-receiver gather in FIG. 9C and commonreceiver gather sonic traces (824) shown in FIG. 9D. A common-receiver gather in shown in FIG. 9D shows the data recorded by one of the plurality of sonic receivers (210) from one of the source activation locations (317). However, from the perspective of processing the common-receiver gathers suffer from shortcomings similar to those of common-source gathers.

[0054] A common-offset gather presents data collected when location of the sonic source (215) and location of one of the plurality of sonic receivers are at a constant separation (or “offset”) from one another. The geometry of a common-offset gather is displayed schematically in FIG. 9E and the recorded common-offset sonic traces (834) shown in FIG. 9F. In common-offset gathers while the time at which the reflected energy (874) is recorded on each receiver sonic trace is constant, the one or more reflection points (872) on the geologic feature (812) still varies from one of the plurality of sonic receivers (210) to another. Note, the portions of the seismic traces associated with the radiated seismic waves emitted from the sonic source may be referred to as a “source wavefield” (880). Further, the portions of the seismic traces associated with the reflected seismic waves may be referred to as a “receiver wavefield” (885).

[0055] Common-source and common-receiver gathers are typically used as basic quality assessment tools in field acquisition. Common-offset gathers typically used for basic quality control because they display an approximation to the geological structure over a vertical slice through the subsurface.

[0056] Finally, FIG. 9G and FIG. 9H illustrate the geometry and recorded data for a commonmidpoint gather respectively. A common-midpoint gather displays the plurality of commonmidpoint sonic traces (854) recorded by one of more sonic source and sonic receiver pairs arrange with a single (“common”) midpoint but varying offset. In many cases commonmidpoint gathers are preferred because each sonic trace shares (approximately) the same reflection point (872) on the geologic feature (812). Consequently, each sonic trace in the common-midpoint gather contains information about the same point. However, because of the varying offset between sonic source and sonic receiver pairs the time at which the reflected energy (874) is recorded on each receiver sonic trace varies. Correctly, combining the plurality of sonic traces (876) requires estimating the variation in the time at which the reflected energy (874) is received with offset, i.e., estimating a traveltime operator, and correcting for it in processing.

[0057] FIG. 10 illustrates a workflow in accordance with one or more embodiments. The workflow includes steps of acquiring remote sensing data, processing the remote sensing data, forming one or more geologic models, optionally simulating the flow of fluids, including hydrocarbons, though the one or more geological models, the planning of boreholes including their surface position, trajectories, and targets, and the drilling of those boreholes. Although the steps in flowchart using the workflow are shown in sequential order, it will be apparent to one of ordinary skill in the art that some steps may be conducted in parallel, in a different order than shown, or may be omitted without departing form the scope of the invention.

[0058] For example, the flowchart may begin with the use of a sonic acquisition system (902) to acquire the sonic data set (404) over the geologic volume. The sonic acquisition system may include the sonic imaging tool (200) which is described in more detail in the context of FIG. 3 and FIG. 4, and an example of the sonic data set (404) is shown in FIG. 5. Other remote sensing data sets may also be collected at this stage to characterize the geologic volume. For example, resistivity, transient electromagnetic, and / or gravitation surveys may be collected.

[0059] The sonic data set (404) contains sonic recordings that are influenced by the geological structure of the geologic volume. However, the sonic data set (404) also contains a wide variety of noise and distortion and does not in its unprocessed “raw” form display significantuseful information about the geologic volume. Consequently, the sonic data set (404) is typically processed to remove or attenuate noise and to correctly locate geologic features (812) that reflect sonic waves (“sonic reflectors”) in 2D or 3D space within a portion of a geologic volume.

[0060] To determine geologic features (812) such as earth structure, including the presence of fractures and geologic layers, the sonic data set (404) must be processed. Processing the sonic data set (404) may include a sequence of steps designed to correct for near-surface effects, attenuate noise, compensate for irregularities in the sonic survey geometry, calculate a sonic velocity model, image reflectors in the subterranean and calculate a plurality of sonic attributes to characterize the subterranean region of interest to determine a drilling target. Each of these steps may be accompanied by one or more quality control steps. Steps in processing sonic data may include migration such as reverse time migration (“RTM”).

[0061] It will be appreciated by one of ordinary skill in the art that the sonic data set (404) is extremely large, typically occupying Gigabytes in size, (corresponding to between 2 billion data samples) and cannot, with current technology, be manipulated or “processed” without the assistance of a purpose configured sonic processing system (906). The sonic data set (404) is coarsely sampled with respect to azimuth. The sonic data set (404) is coarsely sampled due to limited number of sonic receiver’s and principal recording orientations. The present disclosure permits imaging geologic features (812) to 2D computational surfaces (510) in order to reduce computational time and computer memory usage. The imaging may be confined to imaging along principal azimuths aligned with the sonic source and receiver pair’s principal recording orientations but are not limited to this.

[0062] In one or more embodiments, the sonic processing system (906) may include a computer system that is the same as or similar to that of computer (1102) described below in FIG. 12 and the accompanying description. However, the sonic processing system (906) may be configured with appropriate sonic processing software and augmented with a number of purpose specific elements, such as high-speed buses connecting computer processing units (“CPUs”). Further the CPUs of a sonic processing system may be connected to a plurality of graphical processing units (“GPUs”) that perform many of the computationally intensive operations on the sonic data set (404), banks of high-speed tape, or hard-drive, readers to read the data from storage, high-speed tape, or hard-drive writers to output finalor intermediate results, and high-speed communication buses to connect these elements. One of the plurality of GPUs may be the same or similar to that of GPU (1200) described below in FIG. 13 and the accompanying description. Those skilled in the art will appreciate that while embodiments disclosed herein are discussed with respect to the simulation of sonic propagation done with respect to GPUs’ acceleration capabilities, in one or more embodiments, the instant disclosure also includes simulation of sonic propagation done solely on CPUs.

[0063] Once the sonic wavefield is obtained in any domain, the sonic wavefield may be processed using a sonic processing system (906), which is discussed in reference to FIG. 10. Sonic processing may be a series of processing steps that ultimately produce a sonic data set (404) with a higher signal-to-noise ratio than the original sonic dataset as well as immediately useful information that may be used to characterize the formation (106) and locate geologic features (812) within the formation (106). Sonic processing may include methods of migration, stacking, filtering, etc.

[0064] In particular, migration is the process by which sonic events within the sonic wavefield are mapped to a spatial image of sonic reflectors, such as geological bed boundaries or geologic fractures. While it may be obvious that events in the records sonic signals recorded at later times have been generated further from the source and receivers (just as echoes from a distant arrive at a later time) forming a more focused spatial image of reflectors, particularly in cases where the velocity of propagation of the sonic waves varies spatially, requires a more detailed simulation of the propagation of the sonic signals to and from the reflectors. Sonic events may need to be relocated in the image because the recorded positions of the sonic events, which correspond to reflected sonic waves from geologic features (812) within the formation (106), may not correspond to the spatially-relative positions of the geologic features (812) within the image. Migration is a process to re-position the sonic events in the image to better represent the spatial positioning of the geologic features (812) within the formation (106).

[0065] Reverse time migration (RTM), one method of migration, may be applied to the sonic data before or after stacking. As such, RTM may migrate the sonic events within the plurality of sonic traces (876) organized into a gather separately from the plurality of sonic traces organized into another gather. To migrate the sonic events within the plurality of sonic tracesorganized into a gather, a 3D source wavefield (880) and a 3D receiver wavefield (885) may be determined for selected times, such as every millisecond, over a time interval where t - [0,f mo J • The time interval may be the same length over which each of the plurality of sonic traces (876) were collected. The 3D source wavefield (880) may be associated with a portion of the plurality of sonic traces (876) that recorded sonic waves radiating ward from the sonic source (215). Further, the 3D receiver wavefield (885) may be associated with the portion of the plurality of sonic traces (876) that recorded sonic waves radiating after, for example, reflecting at a geologic feature (812).

[0066] In accordance with one or more embodiments, the simulation of sonic propagation for both the 3D source and the 3D receiver wavefields (880, 885) may involve the simulation of sonic propagation in an elastic medium. The simulation of sonic wave propagation assumes sonic waves induce elastic deformation in the formation (106) and along a path of propagation. Those skilled in the art will appreciate that while embodiments disclosed herein are discussed with respect to the simulation of sonic propagation in an elastic medium, in one or more embodiments, the instant disclosure may include simulation of sonic propagation in an acoustic medium approximating the elastic medium. Although simulation in such an acoustic approximation is less completely than the simulation in the corresponding elastic medium it may be significantly computationally less expensive as fluid pressure fluctuation is the only computational wavefield required for acoustic approximations rather than three component of displacement and six independent stress tensor components for the corresponding elastic medium.

[0067] Further, those skilled in the art will appreciate that while embodiments disclosed herein are discussed with respect to wavefields being derived with a solid formulation, in one or more embodiments, the method may extend to coupled solid-fluid settings where measurements are taken inside a fluid-filled borehole (104). In that case, measured data are pressure. Still, a purely solid formulation (3) is described in accordance with embodiments herein because it dramatically simplifies the formulation.

[0068] Numerical solutions of the wave equation may be used to carry out the simulation of sonic propagation of both the 3D source and the 3D receiver wavefields (880, 885) since analog solutions are untenable with most computer systems and time constraints. In accordance with one or more embodiments, spectral-elements based methods (hereafter“spectral-elements”) (1140) of numerical solutions may be used for the simulation of sonic propagation. Spectral-elements (1140) simulation uses piecewise polynomials that may be parameterized for digital computation with a digital device such as the computer system that is the same as or similar to that of computer (1102) described below in FIG. 12 and the accompanying description. Those skilled in the art will appreciate that while embodiments disclosed herein are discussed with respect to simulation using spectral-elements (1140), in one or more embodiments, the instant disclosure may also include simulation with numerical solutions using finite differences, finite elements, and the like.10069] In accordance with one or more embodiments, the present disclosure relates to a sonic imaging system (907). The sonic imaging system (907) may include a computer (1102), such as the computer (1102) described below in FIG. 12 and the accompanying description. In accordance with one or more embodiments, the sonic imaging system (907) may be configured to, for each sonic imaging tool position, define a 3D computational grid (500), wherein the 3D computational grid (500) represents the geological volume, for example, a geologic volume around the borehole (104). The sonic imaging system (907) may also be configured to, for each sonic imaging tool position, define at least one computational surface (510) transecting the 3D computational grid (500) sparsely distributed in azimuth around the tool axis (205) of the sonic imaging tool (200).

[0070] In some embodiments, an imaging condition may include the 3D source and the 3D receiver wavefields (880, 885) for each selected time multiplied together and displayed as a sonic image (908) using the sonic imaging system (907). However, the imaging condition other than or in addition to multiplication may alternatively be used such as zero-lag cross correlation. Zero-lag cross correlation and other mathematical operations performed at this step in RTM may rely on the idea that the location of a sonic event exists where the first arrival of the 3D source wavefield (880) is time coincident with the 3D receiver wavefield (885). RTM may be repeated for any, but not necessarily all, of the gathers among the sonic data set (404) to determine additional sonic slices or one sonic slice per gather. The concatenation of the sonic slices may be referred to as a pre-stacked migrated sonic image.

[0071] In accordance with one or more embodiments, zero-lag cross correlation may take the form of computing the following integral,where T is the duration of sonic records, u(x,t) is a simulated wavefield, q(x,t) is a simulated adjoint wavefield, i.e., the sonic wavefield recorded by the receivers back-propagated in time, R and S are transformation operators for u(x,t), and q(x,t), respectively. The notation designates the product between the two wavefields. The exact meaning of those mathematical definitions depends on the used mathematical models and desired kind of images. In some embodiments, zero-lag cross correlation defines that u(x,f) represent displacement of elastic solid (for example, the 3D source wavefield (880) propagating in the elastic medium), q(x,t) is the adjoint displacement (for example, the 3D receiver wavefield (885) reverse propagating in the elastic medium), (•,•) is a vector dot product, S and R are time derivatives of u(x,t), and q x,t'), respectively. During numerical computations the time is discrete: each time instant is given by tn= n , where T is the time step. Thus, the integral in equation (1) may be approximated with a finite sum,

[0072] To do the cross-correlation, a user needs to multiply the 3D source and the 3D receiver wavefields (880, 885) at a selected time instant to form a selected time 3D wavefield snapshot. The forward and adjoint snapshots are simulated in opposite order: the forward- in-time wavefield is computed from initial conditions forward in time, for example, the 3D source wavefield (880), whereas the adjoint wavefield is calculated from the end condition backward-in-time, for example, the 3D receiver wavefield (885). A plurality of snapshots is formed by storing each selected time 3D wavefield snapshot at locations defined by the at least one computational surface (510).

[0073] FIG. 11 illustrates a method for generating an image of a geological volume around a borehole (hereafter “imaging method”) (1000). The imaging method (1000) allows for imaging a geologic volume around the borehole (104) incorporating steps to reduce memory usage. Further, one or more steps in FIG. 11 may be performed by one or more components as described in FlGs. 1 - 10 (e.g., the sonic imaging system (907)). While the various steps in FIG. 11 are presented and described sequentially, one of ordinary skill in the art will appreciate that some or all of the steps may be executed in different orders, may be combined,or omitted, and some or all of the steps may be executed in parallel. Furthermore, the steps may be performed actively or passively.

[0074] In step 1002, the sonic data set (404) is obtained using the sonic imaging tool (200) in accordance with one or more embodiments. The sonic data set (404) comprises, for each of the plurality of sonic imaging tool positions, the plurality of sonic traces (876) wherein each sonic trace (876) is recorded by one of the plurality of sonic receivers (210) azimuthally distributed around the tool axis (205) of the sonic imaging tool (200) and excited by the sonic source (215) disposed in the sonic imaging tool (200). The sonic data set (404) may be processed to filter or remove near-borehole effects, noise, and irregularities in the acquisition, etc.

[0075] In step 1004, the sonic imaging system (907) defines the 3D computational grid (500). The 3D computational grid (500) may represent the geological volume around the borehole (104). The 3D computational grid (500) may have grid spacing defined by the user. The grid spacing may be constrained by sonic acquisition parameters such as the incremental distance between activation locations and sonic receiver spacing. The grid spacing may be determined, using acquisition parameters, to minimize data aliasing. The sonic data set (404) may be discretized and sampled into the 3D computational grid (500) as the 3D receiver wavefield (885).

[0076] In step 1006, the sonic imaging system (907) defines the at least one computational surface (510) transecting the 3D computational grid (500). One of the at least one computational surface (510) may be a 2D plane. One of the at least one computational surface (510) may include a surface grid. The surface grid may have surface grid spacing that is the same or similar to grid spacing of the 3D computational grid (500).

[0077] In step 1008, using the 3D computational grid (500), the 3D source wavefield (880) may be simulated at all selected times chronologically forward- in-time by solving a one-way or two-way wave equation that uses the sonic velocity model, a gather, and boundary conditions, which may be based on the ground motion at the surface of the earth (116) at t - 0. Each simulation of the 3D source wavefield (880) may be stored, using the sonic imaging system (907), as a time snapshot of the 3D source wavefield (880) in location defined by the at least one computational surface (510). A plurality of time snapshots of the 3D sourcewavefield (880) includes each simulated 3D source wavefield (880) for all selected times chronologically. If a two-way wave equation is used, the 3D source wavefield and the 3D receiver wavefield (880, 885) may both be determined but the 3D receiver wavefield (885) may be ignored as it may be considered negligible.

[0078] In step 1010, using the 3D computational grid (500), the 3D receiver wavefield (885) may simulate, using the plurality of sonic traces (876), sonic propagation for all selected times chronologically backward-in-time by solving a two-way wave equation that uses the sonic velocity model, the gather reversed in time, and boundary conditions, which may be based on the ground motion at t > tmax. Each simulation of the 3D receiver wavefield (885) may be stored, using the sonic imaging system (907), as a time snapshot of the 3D receiver wavefield (885) in location defined by the at least one computational surface (510). A plurality of time snapshots of the 3D receiver wavefield (885) includes each simulated 3D receiver wavefield (885) for all selected times chronologically.

[0079] Consequently, in step 1012, the sonic imaging system (907) is used to form a partial image of an intersection of a portion of the geological volume with each computational surface (510) based, at least in part, on the snapshots of the 3D source wavefield (880), the snapshots of the 3D receiver wavefield (885), and an imaging condition such as zero-lag cross correlation.

[0080] Further, in step 1014, using the sonic imaging system (907), the sonic image (908) of the geological volume over each computational surface (510) based on a combination of the partial images is formed. The partial images may be combined using addition or similar mathematical operations, such as weighted sums.

[0081] The result of processing the sonic data set (404) with the sonic processing system (906) is the sonic image (908) in accordance with one or more embodiments. The sonic image (908) is a 2D or 3D image of the points within the subsurface that generate a distinctive sonic response. For example, the sonic image (908) may display the points at which sonic energy is reflected, or scattered, within the geologic volume. Other sonic characteristics or “attributes” of the subsurface may be displayed as the sonic image (908). For example, the strength of conversion of energy from one type of sonic wave to another, or the strength of absorption of sonic energy, or the velocity of sonic propagation may be displayed as afunction of subsurface position in the sonic image (908). The examples of sonic attributes given above are purely illustrative, and a person of ordinary skill in the art will appreciate that anyone of dozens of other attributes may be displayed as the sonic image (908) and the examples described should not be interpreted as limiting the scope of the invention in any way.

[0082] A sonic interpretation workstation (910) is primarily used by geoscientists, petrophysicists, and exploration teams in the oil and gas industry for analyzing sonic data to understand subsurface geological structures. Sonic interpreters, such as petrophysicists, use the sonic interpretation workstation (910) to visualize sonic data, including 2D and 3D sonic volumes, cross-sections, time slices, and attribute maps. These visualizations provide insights into subsurface structures, faults, and potential hydrocarbon reservoirs. Additional data may be used within the sonic interpretation workstation (910) to facilitate the interpretation of the sonic data set (404). Such additional data may include well logs (140) acquired from previously drilled wells and acquired either while-drilling or via wireline conveyed logging tools (113) after drilling. Such data may also include non-sonic remote sensing data sets such as resistivity, transient electromagnetic, and / or gravitational surveys but are not limited to this.

[0083] Interpreters may pick and interpret key geological horizons within the sonic data set (404) to identify stratigraphic layers, boundaries, and structural features. Horizon interpretation tools and workflows allow for the accurate extraction of geological information from sonic volumes. For example, a sonic interpretation workstation (910) enables interpreters to identify and interpret subsurface faults that may impact hydrocarbon reservoirs. Fault interpretation tools and visualization techniques help in understanding fault geometry, connectivity, and spatial relationships. Sonic attributes, such as amplitude, frequency, and gradient, provide additional information about subsurface properties and can be analyzed using various algorithms and statistical methods. Attribute analysis tools in the workstation aid in defining reservoir characteristics, identifying anomalies, and highlighting potential hydrocarbon traps.

[0084] In accordance with one or more embodiments, interpreters may use the sonic interpretation workstation (910) to build the one or more geologic models (912) by integrating sonic data with well-log data, geological knowledge, and other geophysicalinformation. The one or more geologic models (912) help in estimating reservoir properties, optimizing well locations, and predicting hydrocarbon distribution. Interpreters may analyze and characterize the formation by integrating different data sources, including the sonic data set (404), well logs (140), production data, and sonic inversion results. Workstations provide tools for reservoir property estimation, quantitative analysis, and reservoir performance evaluation.

[0085] In accordance with one or more embodiments, reservoir engineers may use a reservoir simulator (914) to develop fluid flow and production scenarios (916) by integrating production well data, the one or more geologic models (912), and well logs (140) such as sonic, porosity, density, resistivity, and the like. The fluid flow and production scenarios (916) may be used to estimate potential production from a well (102). The fluid flow and production scenarios (916) may be integrated with the one or more geologic models (912) to develop a hydraulic fracturing plan (920), guided by the geologic structures, using a hydraulic fracturing planning system (918). The hydraulic fracturing plan (920) may be used to estimate any production boost from using hydraulic fracturing around the well (102). The hydraulic fracturing plan (920) may be implemented by a hydraulic fracturing system (1300) as described below in FIG. 14 and the accompanying description.|0086] In accordance with one or more embodiments, the sonic interpretation workstation (910) will typically be configured with appropriate sonic interpretation software and reservoir simulation software. The sonic interpretation workstation (910) may be augmented with a number of purpose specific elements, such as high-capacity tape drives or hard drives connected through high-speed buses to computer processing units (“CPUs”). Further the CPUs of a sonic processing system will typically be connected to a plurality of graphical processing units (“GPUs”) that perform many of the computationally intensive operations on the sonic data set (404), banks of high-speed tape, or hard-drive, readers to read the data from storage, high-speed tape, or hard-drive writers to output final or intermediate results, and high-speed communication buses to connect these elements. One of the plurality of GPUs may be the same or similar to that of GPU (1200) described below in FIG. 13 and the accompanying description.

[0087] As described above, in the oil and gas industry many systems (such as drilling systems, well systems, hydraulic fracturing systems, reservoir simulations systems, data acquisitionsystems, data processing systems, etc. ) and techniques (such as Artificial Intelligence, Machine Learning, Deep Learning, modeling, inversion, imaging, etc. ) may rely, at least in part, on processes that may be conducted on one of the plurality of GPU (1200), such as those that implement the Thomas Algorithm to solve tridiagonal systems. In order to make computations using data sets and models that can vary widely in size and complexity it may be desirable to ensure that a GPU architecture, data layout, pre-conditioning and memory access are optimally managed.

[0088] FIG. 12 illustrates a computer system (1102) in accordance with one or more embodiments. As mentioned, the computer system (1102) (herein also “computer”) may be specifically configured for sonic processing and denoted the “sonic processing system.” Alternatively, the computer (1102) may be specifically configured for sonic interpretation and denoted as the “sonic interpretation workstation” (910). The sonic processing system (906), the sonic interpretation workstation (910), the reservoir simulator (914), the hydraulic fracturing planning system (918), or a generic computer (1102) may store and be used by the hydraulic fracturing system (1300). While the generic term computer (1102) may be used to describe each of the parts of a computer (1102) in the following paragraphs, the terms sonic processing system or sonic interpretation workstation (910) may replace the term computer (1102) without departing from the scope of the disclosure.

[0089] The computer (1102) is intended to depict any computing device such as a server, desktop computer, laptop / notebook computer, wireless data port, smart phone, personal data assistant (PDA), tablet computing device, one or more processors within these devices, or any other suitable processing device, including both physical or virtual instances (or both) of the computing device. Additionally, the computer (1102) may include an input device, such as a keypad, keyboard, touch screen, or other device that can accept user information, and an output device that displays information, including digital data, visual or audio information (or a combination of both), or a graphical user interface. Specifically, a sonic interpretation workstation may include a robust graphics card for the detailed rendering of the sonic image (908) such that the sonic image (908) may be displayed and manipulated in a virtual reality system using 3D goggles, a mouse, or a wand to identify geologic features (812) within the formation (106).

[0090] The computer (1102) can serve in a role as a client, network component, server, database, or any other component (or a combination of roles) of a computer system (1102) as required for sonic processing and sonic interpretation. The illustrated computer system (1102) is communicably coupled with a network (1130). For example, a sonic processing system and a sonic interpretation workstation may be communicably coupled using the network (1130). In some implementations, one or more components of each computer system (1102) may be configured to operate within environments, including cloud- computing-based, local, global, or other environment (or a combination of environments).

[0091] At a high level, the computer system (1102) is an electronic computing device operable to receive, transmit, process, store, and / or manage data and information associated with sonic processing and sonic interpretation. According to some implementations, the computer system (1102) may also include or be communicably coupled with an application server, e- mail server, web server, caching server, streaming data server, business intelligence (BI) server, or other server (or a combination of servers).]0092] Because sonic processing and sonic interpretation may not be sequential, the computer system (1102) can receive requests over the network (1130) from other computer systems (1102) or another client application and respond to the received requests by processing the requests appropriately. In addition, requests may also be sent to the computer system (1102) from internal users (for example, from a command console or by other appropriate access method), external or third-parties, other automated applications, as well as any other appropriate entities, individuals, systems, or computer systems (1102).

[0093] Each of the components of the computer system (1102) can communicate using a system bus (1103). In some implementations, any, or all of the components of each computer system (1102), both hardware or software (or a combination of hardware and software), may interface with each other or the interface 1104 (or a combination of both) over the system bus (1103) using an application programming interface (API) 1112 or a service layer (1113) (or a combination of the API (1112) and service layer (1113). The API (1112) may include specifications for routines, data structures, and object classes. The API (1112) may be either computer-language independent or dependent and refer to a complete interface, a single function, or even a set of APIs. The service layer (1113) provides software services to each computer system (1102) or other components (whether or not illustrated) that arecommunicably coupled to each computer system (1102). The functionality of each computer system (1102) may be accessible for all service consumers using this service layer (1113). Software services, such as those provided by the service layer (1113), provide reusable, defined business functionalities through a defined interface. For example, the interface may be software written in JAVA, C++, or other suitable language providing data in extensible markup language (XML) format or another suitable format. While illustrated as an integrated component of each computer system (1102), alternative implementations may illustrate the API (1112) or the service layer (1113) as stand-alone components in relation to other components of each computer system (1102) or other components (whether or not illustrated) that are communicably coupled to each computer system (1102). Moreover, any or all parts of the API (1112) or the service layer (1113) may be implemented as child or sub-modules of another software module, enterprise application, or hardware module without departing from the scope of this disclosure.

[0094] The computer system (1102) includes an interface (1104). Although illustrated as a single interface (1104) in FIG. 12, two or more interfaces (1104) may be used according to particular needs, desires, or particular implementations of each computer system (1102). The interface (1104) is used by each computer system (1102) for communicating with other systems in a distributed environment that are connected to the network (1130). Generally, the interface (1104) includes logic encoded in software or hardware (or a combination of software and hardware) and operable to communicate with the network (1130). More specifically, the interface (1104) may include software supporting one or more communication protocols associated with communications such that the network (1130) or interface’s hardware is operable to communicate physical signals within and outside of the illustrated computer (1102).

[0095] The computer system (1102) includes at least one computer processor (1105). Generally, a computer processor (1105) executes any instructions, algorithms, methods, functions, processes, flows, and procedures as described above. A computer processor (1105) may be a central processing unit (CPU) and / or a graphics processing unit (GPU). The sonic wavefield may be tens to hundreds of terabytes or even petabytes in size. To efficiently process the sonic wavefield to determine the sonic image (908), a sonic processing system may consist of an array of CPUs with one or more subarrays of GPUs attached to each CPU.Further, tape readers or high-capacity hard-drives may be connected to the CPUs using wideband system buses (1103).

[0096] The computer system (1102) also includes a memory (1106) that stores data and software for the computer system (1102) or other components (or a combination of both) that can be connected to the network (1130). For example, the memory (1106) may store the hydraulic fracturing planning system (918) in the form of dedicated software. Although illustrated as a single memory (1106) in FIG. 9, two or more memories may be used according to particular needs, desires, or particular implementations of the computer system (1102) and the described functionality. While memory (1106) is illustrated as an integral component of each computer system (1102), in alternative implementations, memory (1106) can be external to each computer system (1102). The memory (1106) may be used to store the sonic image (908) as bits.

[0097] The application (1107) is an algorithmic software engine providing functionality according to particular needs, desires, or particular implementations of the computer system (1102), particularly with respect to functionality described in this disclosure. For example, application (1107) can serve as one or more components, modules, applications, etc. Further, although illustrated as a single application (1107), the application (1107) may be implemented as multiple applications (1107) on each computer system (1102). In addition, although illustrated as integral to each computer system (1102), in alternative implementations, the application (1107) can be external to each computer system (1102).

[0098] There may be any number of computers (1102) associated with, or external to, a sonic processing system and a sonic interpretation workstation, where each computer system (1102) communicates over the network (1130). Further, the term “client,” “user,” and other appropriate terminology may be used interchangeably as appropriate without departing from the scope of this disclosure. Moreover, this disclosure contemplates that many users may use the computer system (1102), or that one user may use multiple computer systems (1102).

[0099] FIG. 13 illustrates an exemplary GPU schematic. Graphics Processing Units (GPUs) (1200) may be designed to handle specialized computations. GPUs may handle parallel computations much faster than CPUs. A GPU may be made of multiple processing units (1210) each including processing cores (1202) and a variety of other components such asschedulers (1212), dispatch units (1213), memory caches such as L2 cache (1203), shared memory cache (1204), read-only cache (1205), and instruction cache (1211), and other components such as tex units (1215). The parallelization of computations may be implemented in such a way that a kernel executes a set of computations on data arranged in grids which may be subdivided into blocks and further subdivided into threads. Each thread may complete the assigned computations on a subset of the data set on its own GPU processing core (1202). After the computations of each thread are completed, they may be combined back into blocks and then into grids and the completed data set is reassembled after the end of all the computations.

[0100] Continuing with FIG. 13, each element of the computation may be assigned to a memory level. A thread may have a dedicated local memory which cannot be accessed by other threads. Blocks may be assigned to a shared memory (1204). Finally, grids may be assigned to global memory (1206) on the CPU. Memory may also be accessed by the GPU on a host device or network (1130).

[0101] The organization and arrangement in memory on a processing unit or on the GPU device memory or even the host memory may influence the efficiency with which computations are completed. The GPU device may include one or more memory controllers (1201) to facilitate the transfer of data to and from memory such as global memory (1206), constant memory (1207) and texture memory (1208). One or more GPUs (1200) may be utilized. Each GPU (1200) may include an interconnect network (1216) to facilitate the organization and parallelization of computations between each GPU (1200).

[0102] In one embodiment a data layout may be implemented that arranges linear data in GPU memory in a way that maximizes cache (e.g., shared memory) use and minimizes access to the GPU global memory (1206). Implementing the data layout may accelerate problem solving compared to standard layouts used in most existing implementations for achieving the same objective.In accordance with one or more embodiments, the computer system (1102) may be used to implement data compression methods (1135) to the sonic image (908). Data compression methods (1135), such as lossless and lossy, may include encoding the sonic image (908) reducing the number of bits needed to store the sonic image (908) than beforebeing compressed. Lossless data compression may include lossless algorithms that reduce the number of bits by eliminating unnecessary or statistically redundant bits by exploiting statistical redundancy. Lossy data compression may include lossy algorithms reducing the number of bits by eliminating unnecessary or unimportant bits by using transform coding such as discrete transform coding. Using data compression methods (1135), the sonic image (908) may be stored using less GPU memory than before data compression.

[0103] Turning now to FIG. 14, FIG. 14 shows the hydraulic fracturing system (1300) undergoing a hydraulic fracturing operation in accordance with one or more embodiments. The hydraulic fracturing system (1300) may be implementing the hydraulic fracturing plan (920). The particular hydraulic fracturing operation and hydraulic fracturing system (1300) shown is for illustration purposes only. The scope of this disclosure is intended to encompass any type of hydraulic fracturing system (1300) and hydraulic fracturing operation. In general, a hydraulic fracturing operation includes two separate operations: a perforation operation and a pumping operation. As such, FIG. 14 shows a hydraulic fracturing operation occurring on a first well (1302) and a second well (1304). The first well (1302) is undergoing the perforation operation and the second well (1304) is undergoing the pumping operation.

[0104] The first well (1302) and the second well (1304) are horizontal wells meaning that each well includes a vertical section and a lateral section. The lateral section is a section of the well that is drilled at least eighty degrees from vertical. The first well (1302) is capped by a first frac tree (1306) and the second well (1304) is capped by a second frac tree (1308). A frac tree (1306, 1308) is similar to a Christmas / production tree but is specifically installed for the hydraulic fracturing operation. Frac trees (1306, 1308) tend to have larger bores and higher-pressure ratings than a Christmas / production tree would have. Further, hydraulic fracturing operations require abrasive materials being pumped into the well at high pressures, so the frac tree (1306, 1308) is designed to handle a higher rate of erosion.

[0105] In accordance with one or more embodiments, a wireline is configured to maneuver wireline tools such as a perforation gun in a well. The wireline is configured to transmit messages from the wireline tools to a wireline truck (1322). The wireline truck includes a wireline spool (1320) that is configured to manipulate the length of the wireline (1312). In accordance with one or more embodiments, the perforating operation includes installing a wireline blow out preventer (BOP) (1310) onto the first frac tree (1306). A wireline BOP(1310) is similar to a drilling BOP; however, a wireline BOP (1310) has seals designed to close around (or shear) wireline (1312) rather than drill pipe. A lubricator (1314) is connected to the opposite end of the wireline BOP (1310). A lubricator (1314) is a long, high-pressure pipe used to equalize between downhole pressure and atmosphere pressure in order to run downhole tools, such as a perforating gun (1316), into the well.

[0106] When the perforating gun (1316) reaches a predetermined depth, a message is sent along the wireline ( 1312) to set the frac plug (1318). After the frac plug (1318) is set, another message is sent through the wireline (1312) to detonate the explosives, as shown in FIG. 14. The explosives create perforations in the casing (1326) and in the surrounding formation. There may be more than one set of explosives on a singular perforation gun (1316), each detonated by a distinct message. Multiple sets of explosives are used to perforate different depths along the casing (1326) for a singular stage. Further, the frac plug (1318) may be set separately from the perforation operation without departing from the scope of the disclosure herein.

[0107] As explained above, FIG. 14 shows the second well (1304) undergoing the pumping operation after the fourth stage perforating operation has already been performed and perforations are left behind in the casing (1326) and the surrounding formation. A pumping operation includes pumping a frac fluid (1328) into the perforations in order to propagate the perforations and create artificial fractures (1342) in the surrounding formation. The frac fluid (1328) often comprises a certain percentage of water, proppant, and chemicals.

[0108] FIG. 14 also shows chemical storage containers (1330), water storage containers (1332), and proppant storage containers (1334) located on the hydraulic fracturing system (1300). Frac lines (1336) and transport belts (not pictured) transport the chemicals, proppant, and water from the storage containers (1330, 1332, 1334) into a frac blender (1338). The frac blender (1338) blends the water, chemicals, and proppant to become the frac fluid (1328). The frac fluid (1328) is transported to one or more frac pumps, often pump trucks (1340), to be pumped through the second frac tree (1308) into the second well (1304). The frac fluid (1328) is transported from the pump truck (1340) to the second frac tree (1308) using a plurality of frac lines (1336). The fluid pressure propagates and creates the artificial fractures (1342) while the proppant props open the artificial fractures (1342) once the pressure is released.

[0109] Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.

Claims

CLAIMSWhat is claimed is:

1. A method of generating an image of a geological volume around a borehole, comprising: obtaining, using a sonic imaging tool, a sonic data set, wherein the sonic data set comprises, for each of a plurality of sonic imaging tool positions, a plurality of sonic traces wherein each sonic trace is recorded by one of a plurality of sonic receivers azimuthally distributed around an axis of the sonic imaging tool and excited by a sonic source disposed in the sonic imaging tool; for each sonic imaging tool position, using a sonic imaging system: defining a three-dimensional (“3D”) computational grid, wherein the 3D computational grid represents the geological volume, defining at least one computational surface transecting the 3D computational grid and sparsely distributed in azimuth around the axis, and using the 3D computational grid: simulating forward-in-time propagation of a 3D source wavefield and storing a plurality of time snapshots of the 3D source wavefield at locations defined by the at least one computational surface; simulating, using the plurality of sonic traces, backward-in-time propagation of a 3D receiver wavefield and storing a plurality of time snapshots of the 3D receiver wavefield at locations defined by the at least one computational surface; and forming a partial image of an intersection of a portion of the geological volume with each computational surface based, at least in part, on the snapshots of the 3D source wavefield, the snapshots of the 3D receiver wavefield, an imaging condition; and forming, using the sonic imaging system, a sonic image of the geological volume over each computational surface based on a combination of the partial images.

2. The method of claim 1, wherein the sonic imaging system comprises a plurality of graphical processing units.

3. The method of claim 1, wherein at least one of the simulating forward- in-time and simulating backward-in-time comprises simulating sonic propagation in an elastic medium.4 The method of claim 1, wherein at least one of the simulating forward- in-time and simulating backward-in-time comprises performing a spectral-element simulation.5 The method of claim 1, wherein the 3D computational grid comprises a cylindrical coordinate grid.6 The method of claim 1 , wherein the imaging condition comprises a zero-lag cross-correlation.7 The method of claim 1, further comprising interpreting geological structures surrounding the borehole based on the image of the geological volume.8 The method of claim 7, further comprising: designing a hydraulic fracturing plan guided by the geological structures, and performing, using a hydraulic fracturing system, hydraulic fracturing of the borehole guided by the hydraulic fracturing plan.9 The method of claim 1, wherein the plurality of sonic receivers detects and record pressure fluctuations of a fluid filling the borehole caused by incident sonic waves.10 The method of claim 1 , wherein the at least one computational surface is a two-dimensional (“2D”) plane.11 A system for generating an image of a geological volume around a borehole, comprising: a sonic imaging tool, configured to obtain a sonic imaging data set, wherein the sonic data set comprises, for each of a plurality of sonic imaging tool positions, a plurality of sonic traces each sonic trace recorded by one of a plurality of sonic receivers azimuthally distributed around an axis of the sonic imaging tool and excited by a sonic source disposed in the sonic imaging tool; anda sonic imaging system, configured to, for each sonic imaging tool position: define a three-dimensional (“3D”) computational grid, wherein the 3D computational grid represents the geological volume, define at least one computational surface transecting the 3D computational grid and sparsely distributed in azimuth around the axis, and using the 3D computational grid: simulate forward-in-time propagation of a 3D source wavefield and storing a plurality of time snapshots of the 3D source wavefield at locations defined by the at least one computational surface; simulate, using the plurality of sonic traces, backward-in-time propagation of a 3D receiver wavefield and storing a plurality of time snapshots of the 3D receiver wavefield at locations defined by the at least one computational surface; and form a partial image of an intersection of a portion of the geological volume with each computational surface based, at least in part, on the snapshots of the 3D source wavefield, the snapshots of the 3D receiver wavefield, an imaging condition, and form a sonic image of the geological volume over each computational surface based on a combination of the partial images.

12. The system of claim 11, wherein the sonic imaging system comprises a plurality of graphical processing units.

13. The system of claim 11, wherein at least one of the simulating forward- in-time and simulating backward-in-time comprises simulating sonic propagation in an elastic medium.

14. The system of claim 11, wherein at least one of the simulating forward-in-time and simulating backward-in-time comprises performing a spectral-element simulation.

15. The system of claim 11, wherein 3D computational grid comprises a cylindrical coordinate grid.

16. The system of claim 11, wherein the imaging condition comprises a zero-lag cross-correlation.

17. The system of claim 11, further comprising interpreting geological structures surrounding the borehole based on the image of the geological volume.

18. The system of claim 17, further comprising: a hydraulic fracturing planning system, configured to design a hydraulic fracturing plan guided by the geological structures; and a hydraulic fracturing system, configured to perform hydraulic fracturing of the borehole guided by the hydraulic fracturing plan.

19. The system of claim 11, wherein the at least one computational surface is a two-dimensional (“2D”) plane.

20. The system of claim 11, wherein the sonic receivers detect and record pressure fluctuations of a fluid filling the borehole caused by incident sonic waves.