Acquiring seismic data using seismic while drilling (SWD)

Abstract

A technique for determining a drill bit position includes identifying a plurality of acoustic energy signals received at a plurality of sets of acoustic receivers from a passive acoustic energy source that is part of a wellbore drilling system; processing the plurality of acoustic energy signals; determining a position of a drill bit of the wellbore drilling system based on the processed plurality of acoustic signals; and updating a geosteering path of the drill bit based on the determined drill bit position.

Description

[0001] Priority claim

[0002] This application claims priority to U.S. Patent Application No. 16 / 284,803, filed on February 25, 2019, the entire contents of which are incorporated herein by reference. Technical Field

[0003] The present disclosure relates to systems and methods for acquiring seismic data, and more particularly, to acquiring seismic data using seismic while drilling (SWD) systems and methods. Background Art

[0004] During drilling operations, drillers typically rely on prior drilling information, ongoing drilling measurements, and interrelated drill cuttings to give an indication of the formation being drilled. This approach can create delays in providing information to drillers, preventing them from making prompt decisions and therefore creating risk. The risk is increased even more when the decisions to be made are critical to the safety of the drillers, the equipment, and the integrity of the well. Summary of the invention

[0005] In a general embodiment, a method for drilling a wellbore includes operating a seismic while drilling (SWD) system to form a wellbore starting from the surface to a subsurface region at a specific depth below the surface. The SWD system includes a passive acoustic energy source and an acoustic energy receiver set located at the surface, the passive acoustic energy source including at least a portion of a drill string. The method also includes recording an acoustic signal generated by the passive acoustic energy source with the acoustic energy receiver set during the formation of the wellbore. The method also includes processing the recorded acoustic signal to predict a subsurface location of the passive acoustic energy source. The method also includes geosteering the passive acoustic energy source to a specific depth below the surface using the SWD system based on the predicted subsurface location of the passive acoustic energy source.

[0006] In one aspect that may be combined with an example embodiment, a passive acoustic energy source includes a drill bit of a SWD system.

[0007] In another aspect which may be combined with any of the preceding aspects, the set of acoustic energy receivers comprises a first set.

[0008] In another aspect that may be combined with any of the preceding aspects, recording acoustic signals generated by a passive acoustic energy source using a set of acoustic energy receivers includes recording acoustic signals generated by a passive acoustic energy source between the surface and a first depth using a first set of acoustic energy receivers.

[0009] Another aspect that may be combined with any of the preceding aspects also includes recording acoustic signals generated by a passive acoustic energy source between the first depth and a second depth deeper than the first depth using a second set of acoustic energy receivers, the second set of acoustic energy receivers being located on the surface.

[0010] Another aspect that may be combined with any of the preceding aspects also includes recording acoustic signals generated by a passive acoustic energy source between the second depth and a third depth deeper than the second depth using a third set of acoustic energy receivers, the third set of acoustic energy receivers being located on the surface.

[0011] In another aspect which may be combined with any of the preceding aspects, the first depth is 250 meters, the second depth is 500 meters and the third depth is 1000 meters.

[0012] In another aspect that may be combined with any of the preceding aspects, a first group of acoustic energy receivers are spaced apart on the surface in a first geometric configuration, a second group of acoustic energy receivers are spaced apart on the surface in a second geometric configuration, and a third group of acoustic energy receivers are spaced apart on the surface in a third geometric configuration.

[0013] In another aspect that may be combined with any of the preceding aspects, a first geometric structure covers a first spatial region on the surface, a second geometric structure covers a second spatial region on the surface that is larger than the first spatial region, and a third geometric structure covers a third spatial region on the surface that is larger than the second spatial region.

[0014] In another aspect that may be combined with any of the preceding aspects, processing the recorded acoustic signals to predict the underground location of a passive acoustic energy source includes: cross-correlating the recorded acoustic signals from different acoustic receivers in the acoustic receiver group; determining travel-time difference images of the recorded acoustic signals from the passive acoustic energy source and the different acoustic receivers in the acoustic receiver group; and stacking the travel-time difference images.

[0015] In another example embodiment, a seismic while drilling (SWD) system includes a drilling system including a drill rig, a drill string, and a drill bit. The drilling system is configured to form a wellbore starting from the surface to a subsurface region at a specific depth below the surface. The drilling system includes a passive acoustic energy source; an acoustic receiver system including an acoustic energy receiver array located at the surface; and an acoustic energy processing system configured to perform operations. The operations include recording acoustic signals generated by the passive acoustic energy source using the acoustic energy receiver array during the formation of the wellbore, processing the recorded acoustic signals to predict a subsurface location of the passive acoustic energy source, and controlling the drilling system to geo-steer the drill bit to a specific depth below the surface based on the predicted subsurface location of the passive acoustic energy source.

[0016] In one aspect that may be combined with an example embodiment, a passive acoustic energy source includes a drill bit of a drilling system.

[0017] In another aspect which may be combined with any of the preceding aspects, the set of acoustic energy receivers includes a first set of acoustic energy receivers configured to receive acoustic signals generated by a passive acoustic energy source between the surface and a first depth.

[0018] Another aspect that may be combined with any of the preceding aspects also includes a second set of acoustic energy receivers located on the surface and configured to receive acoustic signals generated by a passive acoustic energy source between the first depth and a second depth deeper than the first depth.

[0019] In another aspect that may be combined with any of the preceding aspects, an acoustic energy processing system is configured to perform operations including recording an acoustic signal generated by a passive acoustic energy source using a second acoustic energy receiver during wellbore formation.

[0020] Another aspect that may be combined with any of the preceding aspects also includes a third set of acoustic energy receivers located on the surface and configured to receive acoustic signals generated by a passive acoustic energy source between the second depth and a third depth deeper than the second depth.

[0021] In another aspect that may be combined with any of the preceding aspects, the acoustic energy processing system is configured to perform operations including recording acoustic signals generated by a passive acoustic energy source using a third acoustic energy receiver during wellbore formation.

[0022] In another aspect which may be combined with any of the preceding aspects, the first depth is 250 meters, the second depth is 500 meters and the third depth is 1000 meters.

[0023] In another aspect that may be combined with any of the preceding aspects, a first group of acoustic energy receivers are spaced apart on the surface in a first geometric configuration, a second group of acoustic energy receivers are spaced apart on the surface in a second geometric configuration, and a third group of acoustic energy receivers are spaced apart on the surface in a third geometric configuration.

[0024] In another aspect that may be combined with any of the preceding aspects, a first geometric structure covers a first spatial region on the surface, a second geometric structure covers a second spatial region on the surface that is larger than the first spatial region, and a third geometric structure covers a third spatial region on the surface that is larger than the second spatial region.

[0025] In another aspect that may be combined with any of the preceding aspects, the operation of processing the recorded acoustic signals to predict the underground location of a passive acoustic energy source includes: cross-correlating the recorded acoustic signals from different acoustic receivers in the acoustic receiver group; determining travel-time difference images of the recorded acoustic signals from the passive acoustic energy source and the different acoustic receivers in the acoustic receiver group; and stacking the travel-time difference images.

[0026] In another example embodiment, a computer-implemented method for determining a drill bit position includes: using one or more hardware processors in an acoustic energy processing system to identify a plurality of acoustic energy signals received at a plurality of groups of acoustic receivers from a passive acoustic energy source that is part of a borehole drilling system. The computer-implemented method also includes: using one or more hardware processors in the acoustic energy processing system to process the plurality of acoustic energy signals. The computer-implemented method also includes: using one or more hardware processors in the acoustic energy processing system to determine a position of a drill bit of the borehole drilling system based on the processed plurality of acoustic signals. The computer-implemented method also includes: using one or more hardware processors in the acoustic energy processing system to update a geosteering path of the drill bit based on the determined drill bit position.

[0027] In one aspect that may be combined with an example embodiment, the passive acoustic energy source includes at least one of a drill bit or one or more casing collars of a drilling system.

[0028] In another aspect which may be combined with any of the preceding aspects, each of the plurality of groups of acoustic receivers covers a unique spatial region and is configured to detect at least a portion of the plurality of acoustic energy signals at a unique depth range below the surface.

[0029] Another aspect that may be combined with any of the preceding aspects also includes verifying a unique geometry of each of the plurality of groups of acoustic receivers using one or more hardware processors in the acoustic energy processing system.

[0030] In another aspect that may be combined with any of the preceding aspects, processing includes: cross-correlating recorded acoustic signals from different acoustic receivers in each of a plurality of acoustic receiver groups; determining travel-time difference images of recorded acoustic signals from a passive acoustic energy source and from different acoustic receivers in the acoustic receiver groups; and stacking the travel-time difference images.

[0031] Embodiments according to the present disclosure may include one or more of the following features. For example, embodiments according to the present disclosure may provide a better signal-to-noise ratio compared to conventional SWD systems, which have inherent problems of low signal-to-noise ratio due to the small number of receivers used in recording and the large amount of noise generated when performing drilling operations. As another example, embodiments of the present disclosure may better detect available seismic signals while drilling. In addition, embodiments of the present disclosure may provide a large-scale, flexible, and adaptive real-time seismic while drilling system. As another example, embodiments of the present disclosure may provide a verification method for acquiring parameters to optimally focus and image a target of interest with a variable depth during SWD. Moreover, embodiments of the present disclosure may provide large-scale acquisitions that allow recording of near and far energy fields to allow better separation of signals and noise in continuous data processing and analysis steps.

[0032] Details of one or more implementations of the subject matter described in this disclosure are set forth in the drawings and the description. Other features, aspects, and advantages of the subject matter described will become apparent from the description, drawings, and claims. BRIEF DESCRIPTION OF THE DRAWINGS

[0033] Figure 1 An example workflow of a real-time seismic while drilling (SWD) process according to the present disclosure is shown.

[0034] Figure 2 According to the present disclosure Figure 1 An example of using historical data in a workflow.

[0035] Figure 3 According to the present disclosure Figure 1 An example of well casing data used in the workflow.

[0036] Figure 4A-4C It is shown that according to the present disclosure Figure 1 Example of historical drilling information and parameters used in the workflow.

[0037] Figure 5A-5D It shows that according to the present disclosure Figure 1 An example of a workflow used to extract regional petrophysical data from seismic images.

[0038] Figure 6 According to the present disclosure Figure 1 Example of using sonic logging petrophysical data in a workflow.

[0039] Figure 7 An example process for generating an integrated subsurface model according to the present disclosure is shown.

[0040] Figure 8 An example implementation of a SWD system according to the present disclosure is shown.

[0041] Figure 9A-9B An example implementation of a seismic sensor array according to the present disclosure is shown.

[0042] Fig.10 An example implementation of a symmetric seismic acquisition geometry according to the present disclosure is shown.

[0043] Figures 11A-11D An example implementation of a symmetrical collection geometry centered at the wellhead and targeting shallow depths according to the present disclosure is shown.

[0044] Figure 12A-12B An example first geometry verification step showing a vertical cross-sectional image by forward modeling according to the present disclosure is shown.

[0045] Figure 13A-13B A first geometry verification step showing a horizontal cross-sectional image by forward modeling according to the present disclosure is shown.

[0046] Fig.14 An example symmetrical acquisition geometry centered on the wellhead and targeting shallow depths according to the present disclosure is shown.

[0047] Figure 15A-15B An example second geometry verification step showing a vertical cross-sectional image by forward modeling according to the present disclosure is shown.

[0048] Figure 16A-16B A second geometry verification step showing a horizontal cross-sectional image by forward modeling according to the present disclosure is shown.

[0049] Fig.17 An example symmetrical acquisition geometry centered on the wellhead and targeting greater depths in accordance with the present disclosure is shown.

[0050] Figure 18A-18B An example third geometry verification step showing a vertical cross-sectional image by forward modeling according to the present disclosure is shown.

[0051] Figure 19A-19B A third geometry verification step showing a horizontal cross-sectional image by forward modeling according to the present disclosure is shown.

[0052] Fig. 20 Shows Figure 8 An example implementation of a SWD system with possible locations for additional acoustic sensors at a wellsite.

[0053] Fig.21 Example different acquisition geometries based on different depth ranges according to the present disclosure are shown.

[0054] Fig. 22 An example schematic diagram of travel time difference with a pair of two receivers and a downhole passive source according to the present disclosure is shown.

[0055] Fig.23 An example workflow for drill bit location using cross-correlation and travel time differences according to the present disclosure is shown.

[0056] Fig.24 An example simple layer earth model with an identified drill head location in accordance with the present disclosure is shown.

[0057] Fig.25 An example graph of recorded seismic while drilling in accordance with the present disclosure is shown.

[0058] Fig.26An example diagram of cross-correlation using a reference at receiver r1 according to the present disclosure is shown.

[0059] Fig. 27 An example diagram of cross-correlation using a reference at receiver r2 according to the present disclosure is shown.

[0060] Fig.28 An example diagram of travel-time difference imaging after cross-correlation using a reference at receiver r1 according to the present disclosure is shown.

[0061] Fig.29 An example diagram of travel-time difference imaging after cross-correlation using a reference at receiver r2 according to the present disclosure is shown.

[0062] Fig.30 An example diagram of a stacked image revealing a drill bit position according to the present disclosure is shown.

[0063] Fig.31 An example diagram of field test acquisition geometry and well locations according to the present disclosure is shown.

[0064] Fig.32 An example graph of raw recorded passive seismic data without any pre-processing applied in accordance with the present disclosure is shown.

[0065] Fig.33 Example graphs of reconstructed wavefields at different times according to the present disclosure are shown.

[0066] Figure 34A-Figure 34B An image of a secondary energy source and a plot of the position of a drill bit and stack velocity curves according to the present disclosure are shown.

[0067] Fig.35 Graph showing time-frequency analysis of passive seismic data recorded and processed in accordance with the present disclosure. DETAILED DESCRIPTION

[0068] Figure 1 An example workflow 100 for a real-time seismic while drilling (SWD) system and process is shown. In some aspects, a real-time SWD system (e.g., Figure 8) provides real-time insights and information to drilling and geosteering personnel so that they can make informed decisions about ongoing drilling plans and steering directions. The workflow 100 shown includes a preparation process 102, an execution process 108, and a result process 120. In some aspects, the preparation stage 102 precedes the on-site execution stage 108 to ensure the quality of the collected data and to ensure smooth execution. The execution stage 108 occurs in real time on-site, where data is repeatedly collected, processed, and imaged while the drilling operation is ongoing. The result of this workflow 100 is to provide real-time feedback 124 to the drilling engineer about the drill bit position, thereby making predictions before the drill bit, etc.

[0069] like Figure 1 As shown, the execution phase 108 includes the following sub-steps of the workflow 100, including: a field acquisition step 110, a data recording step 112, a data processing step 114, and an imaging step 116, and a geometry update step 118. In the field acquisition step 110, the geometry layout is determined. In the data recording step 112, seismic data and direct and indirect guidance records are recorded. In step 114, the recorded data is processed, for example, by cross-correlation, travel time difference processing (of acoustic waves), and stacking. In the imaging step 116, migration and velocity updates are performed. Finally, in the geometry update 118, the determined geometry (e.g., the geometry of the relationship between the passive acoustic source and the acoustic sensor) is verified. In some aspects, a computing system such as an acoustic energy processing system can implement all or part of the execution phase 108.

[0070] In this example, the results phase 120 includes two sub-phases. For example, as shown, the global rock physics model generated by the workflow 100 is updated in sub-phase 122. This sub-phase 122 can include updating existing velocity and seismic images. In addition, real-time feedback (e.g., about the drill bit position) is provided to the drilling engineer for geosteering. In addition, the predicted path ahead of the drill bit is provided to the drilling engineer.

[0071] In this example, in the preparation phase 102, for example, historical data 104 and experimental design data 106 may be reviewed to define a target drilling depth range for seismic data to be recorded when the SWD system is operated. For example, the historical data 102 may include existing regional seismic data, a planned well path, historical drilling information about nearby wells (near the planned well path), and regional petrophysical data. For example, existing regional seismic data may provide an image of the subsurface formation or formations to be drilled. This data typically comes in the form of a three-dimensional (3D) volume that covers a specific surface area and penetrates to a specific depth in the earth. The limits of such data may be represented by surface coordinates and depth (X, Y, Z). In addition, such images typically come from a seismic survey acquired in the same area as the planned well path area. For example, Figure 2 A cross-sectional image 200 is shown with possible spatial coverage of tens of kilometers (km) and kilometers in depth (eg, 0-4 km). Other related data that may be used is topographic maps collected during the acquired seismic survey in order to properly reconstruct the seismic data for processing.

[0072] In some examples, the planned well path narrows the drill bit search area to a single path and paths around the proposed path. The path can be used to check which layers in the seismic image the well path will pass through during drilling operations using the SWD system. Such information can also be used to predict the drilling timeline because different rock layers require different times to drill through due to their different hardness and physical properties. In other words, the rate of penetration (ROP) of the drill bit through each formation is calculated or estimated as part of the planned well path. The cross-sectional image 200 shows a vertical well path 204 from a planned well 202. In addition, a narrowed search area 206 is shown. In the figure, a well 208 is shown, which represents a well previously drilled into an underground layer 212, which generates historical drilling information 210.

[0073] Other useful information that can be used is Figure 3 The well casing plan 300 is shown in FIG. Figure 3 is an example plan 300 showing the design and measurement of well casings which are lowered into the well during drilling to prevent the well walls from collapsing into the void created by drilling. These casings also serve as safety measures to contain drilling fluids and protect against sudden increases in pressure due to the escape of pressurized fluids from the drilled formation or rock. Figure 3A cross-section of a well showing the well casing descending to a vertical depth of 2 km is shown. These casings are often connected together (e.g., in a casing string) using short pipes. These joints can act as amplifiers of acoustic waves propagating in the drilling fluid due to acoustic energy generated by passive downhole acoustic energy sources (e.g., drill bit or drill string vibrations of a SWD system). Therefore, knowledge of the casing design can add information about the location of these casing joints and help, for example, to eliminate their effects on the recorded signal or use them as secondary signal sources that provide information from adjacent formations.

[0074] Historical drilling information of nearby wells (in Figure 2 210) can provide insights into the challenges faced in drilling wells in the same area. It also provides valuable information needed to pre-plan the seismic data acquisition timeline. The data 210 can include, but is not limited to, measurements such as drilling ROP, weight on bit (WOB), drill bit rotation speed in cycles per minute, torque used to drill through rock, etc. Additionally, other descriptive data such as drilling project activities over time can add value because they are often similar to wells drilled in the same area. Figure 2 , different shading of the historical drilling information 210 represents different drilling activities that occurred. Figure 4A-4C An example of measured drilling information and parameters 400 is shown. Since different types of drill bits emit different amounts of sound waves into the solid rock being drilled, other useful information may be the type of equipment.

[0075] Regional petrophysical data can be derived from subsurface rock properties in volumetric form extracted from existing regional seismic images or in linear form from well logs. Figure 5A-5D Several petrophysical data 500 including density 504, velocity 506, and acoustic impedance 508 extracted from a seismic image 502 are shown. Figure 6 Petrophysical data from a seismic log 600 is shown, which is similar data localized to the well location and along its path, and is commonly used to calibrate petrophysical data extracted from seismic images.

[0076] Figure 7 A process 700 for generating an integrated subsurface model 710 based on the execution of the preparation phase 102 is shown. For example, all or some of the previously described historical data 104 may be used to create an integrated model of the subsurface layers and their characteristics, which will be used to navigate and guide drilling operations in a later real-time step. The integrated model may be created using statistical, mathematical, machine learning, data analysis, and artificial intelligence operations (e.g., interpolation, kriging, curve fitting, correlation, etc.). Figure 7As shown and previously described, the historical data 104 includes seismic data 702 , well path data 704 , drilling information data 706 , and petrophysical data 708 .

[0077] Workflow 100, and in particular preparation phase 102, may also include a design of experiments sub-step 106. For example, in some aspects, the collection of historical data in phase 104 may be followed by design of experiments 106, in which equipment selection is made, and the system 800 (e.g., Figure 8 ) design and pre-planning of the geometry. In addition, modeling studies can be performed to verify the geometry and its feasibility. For example, the experimental design 106 may include the selection of equipment. For example, in order to achieve the goal of positioning and prediction before the drill bit, the equipment must be carefully selected to help ensure that specific goals are achieved. Such goals include signals emitted by detecting the vibration of the drill bit and passing through adjacent formations to the ground. These signals can be detected using surface seismic sensors with specific patterns or geometric designs distributed around the monitored well. Such goals also include detecting signals emitted by the vibration of the drill string into the formations adjacent to the ground. The surface sensors can similarly detect these signals. Such goals also include detecting signals emitted forward by the drill bit and reflected back to the ground by deeper formations. The surface sensors can similarly detect these signals. Such goals also include detecting signals that pass through the drilling mud or fluid through the borehole to the ground. For example, a riser pressure sensor can detect these signals. Such goals also include detecting drill bit features in the drilling assembly just above the drill bit. Downhole sensors installed in the protection sub or drill string right above the drill bit can detect these signals. Such objectives also include the detection of ground noise generated by various sources in the ground where drilling operations are taking place. Highly sensitive ground seismic sensors can detect these signals. Such objectives also include the appropriate sampling of all detected signals in space and time. This may determine the number of sensors and their dynamic range, which will be used in the surface or downhole components. Finally, such objectives may also include the appropriate focusing of the subsurface signals. This may determine the area coverage of the surface sensors.

[0078] To achieve these goals, some equipment may be used for recording. For example, an array of surface sensors on the order of thousands with large spatial coverage could be used to detect all signals coming upward from the subsurface. Figure 8 , the shaded block is an example setup of such a sensor array. Additionally, hundreds of surface sensors near noise or vibration sources can be used in drilling operations to record the noise and enable subsequent steps to remove this noise. For example, Figure 8An example setup of sensor placement locations is included. In addition, surface sensors can be used to record the guidance trajectory near the drill string entry point to the ground. Alternatively, the guidance trajectory can be recorded at the drill bit itself or slightly upward from the drill bit itself. Therefore, one or more downhole sensors close to the drill bit can be used. However, this placement may cause difficulties in transmitting the recorded signal to the surface. Another option is to use a riser pressure sensor to record the background noise in the drilling fluid and extract the guidance signal from the background noise. In addition, high sensitivity sensors can be used instead of using traditional seismic detector sensor arrays. High sensitivity sensors allow for a reduction in the number of sensors required to achieve the same goal. Finally, flexible real-time recording equipment, such as wireless systems, can be used.

[0079] Figure 8 An example implementation of a SWD system 800 is shown, which can be used in the execution phase 108 to drill a wellbore and collect seismic data from a passive seismic source in the SWD system 800 in real time. As shown, the SWD system 800 includes a drilling derrick 802 that operates to drive a rotary table 810 with a motor 804 to form a wellbore 812 using a drill bit 816 coupled to a drill string 814. Drilling mud is pumped from a mud tank 808 through the drill string 814 by a mud pump 806 to, for example, leave the drill bit 816 and move drill cuttings back to the surface where the derrick 802 is located. As shown, a seismic detector 818 (acoustic sensor) is installed on the surface to receive acoustic signals from the drill bit 816 and other components of the system 800. Such signals include direct signals 820 emitted from the casing joint, direct signals 822 emitted from the drill bit 816, and reflected signals 824 emitted from the drill bit 816.

[0080] As discussed, the SWD system 800 includes multiple acoustic sensors / sensor arrays. The number of sensors used to collect seismic data for such experiments can be in the thousands, in addition to hundreds of sensors used to collect noise and guide tracks that are subsequently used for data processing. These sensors can be traditional seismic detectors, high sensitivity seismic detectors, or any other special sensors, depending on the preferred array arrangement and acquisition requirements. In each array, there are many patterns to be used. Figure 9A-9B An example implementation of a seismic sensor array is shown. As an example, Fig. 9A An example array with a single sensing node is shown, while Fig. 9BAn example with a three by three sensor array is shown. Some of the main parameters for designing these patterns are the number of sensors in each array, how those sensors are connected (in series or in parallel), and the particular coverage of the array. The number of sensors within an array can vary based on the sensitivity of the sensors to signal rather than noise. The greater the number of sensors within an array, the more sensitive the array will be in recording signals, depending on how they are connected. The smaller the area coverage of the array, the less averaging or smoothing will be done on the recorded signals.

[0081] Fig.10 An example implementation of a seismic acquisition geometry 1000 is shown. In this example, thousands of these individual arrays are formed together in a particular pattern to form the acquisition geometry. Fig.10 In FIG. 1 , each square 1002 is equivalent to a sensor or a sensor array, and each square 1004 represents the area of ​​a restricted area.

[0082] The main parameters used to form the acquisition geometry are: specific sampling, which is the spacing between the centers of the sensor array; maximum area coverage, which is the size of the geometric pattern; and target depth. Together, these parameters control the focusing of the signal at a certain target depth. Geometric patterns with small area coverage or a small area range are only best suited for shallow target depths. The larger the area coverage of the geometry, the deeper the target depth that the geometry can be used to focus. To ensure that the correct data is focused on the target within a specific target depth, a distance of twice the surface area coverage distance may be required. Multiple of these large-scale geometries are designed to record seismic data emitted from different target depth ranges. Together, these multiple large-scale geometries form a flexible and adaptable acquisition system.

[0083] The designed sensor array geometry can be repeatedly verified using the focused beam method within the execution stage 108 before making a decision to switch to the next geometry. For example, the acquisition geometries suggested below serve as examples to illustrate their range and flexible nature. In addition, they show how the acquisition geometry can be designed taking into account the variable depth of the target. The actual geometries used with the SWD system 800 are not limited to the three geometry examples disclosed in the present disclosure and can be implemented using aerial coverage and different numbers of geometries based on the target depth requirements. On the other hand, initial field experiments (described later) demonstrate the feasibility of such a large-scale monitoring system for recording while drilling seismic. All disclosed geometries share common design aspects, such as being centered at the wellhead location and having flexible keep-out zones (defined by the wellbore) that can be sized according to the drilling safety requirements for each well. Fig.10 Within this highly active restricted area, at various locations on the well pad and even on the drilling rig itself, guidance trajectories may be recorded to support subsequent data processing and analysis.

[0084] Figures 11A-11D An example implementation of a symmetrical acquisition geometry 1100 centered on the wellhead and targeting shallow depths is shown. The geometry 1100 targets a shallow depth of approximately 250 meters (m). The geometry 1100 is a hybrid combination of two-dimensional (2D) and 3D components centered on the wellhead. The first component is a 3D component covering 0.3 square kilometers (km 2 ) to better image the near-field energy generated by shallow targets. To support data processing and analysis, the second component consists of two intersecting 2D receiver lines at the wellhead and extending 3 km outward from the center to image the far-field energy generated by shallow targets.

[0085] Figure 12A-12B The geometry verification step through forward modeling is shown, which shows a vertical cross-sectional image of the geometry 1100 . Figure 13A-13B The geometry validation step by forward modeling is shown, which shows a horizontal cross-sectional image of the geometry 1100. To validate the geometry 1100, a forward modeling study was performed to virtually image a target at a depth of 900 feet (ft.) with a constant medium velocity of 2000 meters / second (m / s) and a maximum frequency of 200 Hertz (Hz). Figure 12A-12B and Figure 13A-13B The forward modeling results in show a concentrated energy extinguishment corresponding to a target at 900 ft. This validates the geometry 1100 for imaging shallow targets.

[0086] Fig.14 A symmetrical acquisition geometry 1400 is shown, centered on the wellhead and targeting slightly deeper depths. Geometry 1400 targets deeper depths between 250m and 500m (in this example). Geometry 1400 is also a hybrid combination of 2D and 3D components centered on the wellhead. Compared to geometry 1100, the first component is still a lower density of square receivers covering a larger aerial range of 1.2 square kilometers to better image the near-field energy generated by the slightly deeper target. The second component is the same as in geometry 1100, consisting of two intersecting 2D receiver lines at the wellhead and extending 3 kilometers outward from the center, suggesting imaging of the far-field energy generated by the slightly deeper target.

[0087] Figure 15A-15B The geometry verification step through forward modeling is shown, which shows a vertical cross-sectional image of the geometry 1400 . Figure 16A-16BThe geometry validation step by forward modeling is shown, which shows a horizontal cross-sectional image of the geometry 1400. To validate the geometry 1400, a similar forward modeling study was performed to virtually image a target at a depth of 1800 ft., a constant median velocity of 2000 m / s, and a maximum frequency of 200 Hz. Figure 15A-15B and Figure 16A-16B The forward modeling results in show concentrated energy extinguishment corresponding to a target at 1800 ft. This validates geometry 1400 (eg, relative to geometry 1100) for imaging slightly deeper targets.

[0088] Fig.17 A symmetrical acquisition geometry 1700 is shown that is centered at the wellhead and targets deeper depths. Geometry 1700 targets deeper depths of more than 500 m and up to 3000 m. Geometry 1700 is also a hybrid combination of 2D components centered at the wellhead. Compared to geometries 1100 and 1400, the main components of this geometry 1700 consist of two thick 2D lines and multiple (e.g., 7 in this example) receiver lines, each of which crosses at the wellhead and extends outward from the center for slightly more than 2 kilometers to better image the far-field energy generated by the deeper targets.

[0089] Figure 18A-18B The geometry verification step through forward modeling is shown, which shows a vertical cross-sectional image of the geometry 1700. Figure 19A-19B The geometry validation step by forward modeling is shown, which shows a horizontal cross-sectional image of the geometry 1700. To validate the third geometry, a similar forward modeling study was performed to virtually image a target at a depth of 5000 ft., a constant median velocity of 2000 m / s, and a maximum frequency of 200 Hz. Figure 18A-18B and Figure 19A-19B The forward modeling results in show concentrated energy extinguishment corresponding to a target at 5000 ft. This validates the third geometry (eg, relative to geometry 1100) for imaging slightly deeper targets.

[0090] Fig. 20 Shows Figure 8 An example implementation of a SWD system 800 with possible locations for additional acoustic sensors. Fig. 20As shown, the SWD system 800 includes a drilling derrick 802 that operates to drive a rotary table 810 with a motor 804 to form a wellbore 812 using a drill bit 816 coupled to a drill string 814. Drilling mud is pumped from a mud tank 808 through the drill string 814 by a mud pump 806 to, for example, exit the drill bit 816 and move drill cuttings back to the surface where the derrick 802 is located. As shown, a seismic detector 818 (acoustic sensor) is installed on the surface to receive acoustic signals from the drill bit 816 and other components of the system 800. Such signals include direct signals 820 emitted from the casing joint, direct signals 822 emitted from the drill bit 816, and reflected signals 824 emitted from the drill bit 816.

[0091] During execution and in preparation for seismic data acquisition or collection, Fig. 20 The equipment shown is brought to the field or rig site to arrange the designed acquisition geometry or pattern on the surface around the drilling rig 802. These sensors (e.g., seismic detectors 818) record seismic signals transmitted and reflected from the drill bit 816 and drill string 814 through the underground formations. The drilling rig and drilling site are also equipped with sensors to record the guidance signal (drill bit signature) and surface noise caused by drilling activities. These signals recorded by the surface sensors carry the characteristics of the formation and drill bit vibrations. These two characteristics can be separated by cross-correlation or other methods using the guidance signal recorded by the surface sensors near the drill string entry point on the ground. Similarly, the drilling activity noise is decoded from the recorded signal.

[0092] Fig.21 Different acquisition geometries 1000, 1400, and 1700 based on different depth ranges are shown. Once the SWD system 800 is equipped, it can remain unchanged for each field deployment. The layout of the surface seismic sensors can be performed simultaneously starting with a minimum coverage pattern that targets shallow drilling depths. After this initial pattern or geometry is placed, recording begins from the start of drilling until a specific drilling depth is reached. Beyond this depth, this initial geometry (geometry 1000) may not be able to record a focused signal and therefore may be updated. Geometry 1400 then targets a deeper drilling depth range. Geometry 1400 can also be recorded while drilling through a second drilling depth range, after which it will again record unfocused signals and will again be updated a second time. Geometry updates occur during drilling and are repeated until the maximum drilling depth is reached. Geometry updates can be based on drilling depth ranges (such as those described in the simplified data acquisition process). Fig.21 ) or can be adaptively changed based on signal focus. The use of wireless seismic systems, especially those with radio communications, can provide flexibility in sensor deployment, enabling such field operations to be performed rapidly.

[0093] Fig. 22 A schematic diagram of travel time difference with a pair of two receivers (2202) located on the surface 2200 and a downhole passive source 2204 (e.g., the drill bit of the SWD system 800) is shown. Using large-scale flexible acquisition geometry for seismic while drilling can allow the drill bit position to be determined more accurately using the travel time difference method. The main advantage of using a large number of receivers is that there is an unlimited possibility to use multiple receiver combinations to verify the same target and improve the signal-to-noise ratio. Fig. 22 The schematic diagram shown illustrates a basic case, including a pair of surface receivers 2202, r1 and r2, and a drill head source 2204, S, located at (x, z) along the well path, where x is the surface projection of S and z is the depth of S. The energy emitted by the drill head source 2204 is received by each receiver 2202 at two different times, sharing a common travel time component and differing by a travel time difference.

[0094] The imaging condition for locating the drill head position using the travel time difference of a pair of surface receivers is defined by the following formula:

[0095] s(x,z)=∫g(r1,x,z,t)g(r2,x,z,t+τ)dt Formula (1),

[0096] where g(r, x, z, t) is the Green's function from any receiver r to a specific drill head location (x, z), and τ is the travel time difference.

[0097] Fig.23 An example workflow 2300 for drill bit location using cross-correlation and travel time difference is shown. As shown, for example, the workflow 2300 includes a first step 2302 in which seismic data is passively recorded. Next, in step 2304, the recorded data is then cross-correlated with a reference or guide trajectory, allowing the energy to be focused on the useful signal rather than the noise. Next, in step 2306, the drill bit location is determined using multiple pairs of receivers and a reference using the previously stated imaging conditions. This provides multiple implementations of the drill bit location. Next, in step 2308, the travel time difference images are stacked together. In step 2310, these implementations pinpoint the drill bit location.

[0098] Fig.24 A simple layer earth model 2400 is shown. For example, to demonstrate the concept of using a large-scale acquisition geometry, a simple layer 2D earth model 2400 is used and a vertical well trajectory is assumed. In addition, it is assumed that seismic is recorded using an acquisition geometry that covers the surface at evenly spaced receivers and is centered on the drilling rig. The use of a large number of receivers allows the use of cross-correlation and travel time differences for each receiver pair.

[0099] Fig.25Surface receivers 2500 are shown for recording while drilling seismic using model 2400. When recording while drilling seismic, the drill bit recorded signal using all surface receivers will be as follows Fig.25 25 is shown as a surface receiver 2500, which shows seismic data (from the drill bit as a passive source) recorded at a distance away from the drilling rig (on the x-axis) in time (on the y-axis). Fig.26 shows the use of a reference at receiver r1 (such as Fig. 22 A cross-correlated surface receiver 2600 is shown in the schematic diagram of FIG. Fig. 27 shows the use of a reference at receiver r2 (such as Fig. 22 2700. For all combinations of receiver pairs, the reference signal is used in a cross-correlation process resulting in many cross-correlated signals.

[0100] Fig.28 Graph 2800 showing travel-time difference imaging after cross-correlation using a reference at receiver r1. Fig.29 Graph 2900 shows travel-time difference imaging after cross-correlation using a reference at receiver r2. Fig.30 A graph 3000 of stacked images revealing the drill head location is shown. These cross-correlated signals are then used to image the drill head location using the travel time difference method for each receiver pair.

[0101] In some respects, these images still contain imaging artifacts. The resulting images are then stacked together to produce a more definitive image of the drill head location by eliminating the imaging artifacts. Without the use of a large number of receivers, the process of locating the drill head using cross-correlation and travel time differences would be inaccurate and nearly impossible. In the theoretical demonstration above, the drill head location was determined in a vertical cross-sectional 2D plane because the receivers were assumed to be on a 2D line at the surface. The use of 3D acquisition geometry expands the possibilities of locating the drill head in three dimensions.

[0102] Similarly, the use of a large number of receivers allows for imaging and prediction ahead of the drill bit. A large number of receivers can also allow for better sampling and recording of different seismic waves. In particular, a new type of body wave can now be recorded during the drilling process. These body waves are typically generated by tube waves in the wellbore, which are caused by the movement of the drill string in the wellbore. Such body waves are revealed from low signal-to-noise (S / N) field data using traditional passive seismic imaging methods.

[0103] Yet another possible application enabled by the use of a large number of receivers is seismic logging while drilling. Another possible application enabled by the use of a large number of receivers placed on the surface around the wellhead is recording reverse vertical seismic profiles (VSP). In a conventional VSP setup, an active seismic source is used to generate seismic signals at different locations on the surface, while a set of receivers are lowered into the wellbore at different depth levels to record seismic reflections around the wellbore. On the other hand, reverse VSP will use the drill bit as a passive source and surface receivers as detectors. The number of receivers suggested in SWD recording exceeds the number of receivers in conventional VSP, which does not exceed 100 receivers at a time. This allows for better recording and detection of seismic signals in noisy environments.

[0104] VSP while drilling (VSP-WD) is an emerging technology that can reduce drilling risks at a lower cost. However, because VSP-WD uses active seismic sources at the surface and receivers inside the wellbore, it slows down drilling operations and makes it difficult to interpret the collected data in real time.

[0105] SWD incorporates seismic technology while lowering the drill string into the borehole during active drilling, during maneuvering, and when connecting drill pipe. There are two SWD techniques. The first SWD technique is drill bit SWD, which records the seismic noise generated by the drill bit of active drilling at surface seismic sensors. The second SWD technique is VSP-WD, which records the seismic signals generated by seismic receivers within the borehole and by surface seismic sources. In both techniques, the number of receivers is limited to a maximum of 100 receivers, and active sources are used at the surface. This in turn results in the recording of data with a lower signal-to-noise ratio and additional time delays in drilling operations due to the interventional nature of these techniques.

[0106] In contrast, the present disclosure describes a SWD system in which a large number of receivers (e.g., much greater than 100) with unlimited geometry setup options are implemented without using active seismic sources and without interrupting drilling operations. In the present disclosure, in an example embodiment, the concept is demonstrated using SWD field experiments using a fixed array geometry consisting of a thousand receiver points having a generally circular shape (e.g., as Fig.17). In this implementation (and as a field experiment), the well location was 2.6 km from the center of the receiver distribution. Historically, roller cone drill bits have been considered good passive sources for SWD because they naturally make noise when breaking rock. However, most drilling operations today use polycrystalline diamond cutter (PDC) drill bits that shear rock. PDC drill bits are generally quieter than roller cone drill bits and are challenging passive sources for surface receivers. To this end, other mechanisms of downhole sources generated by drill string motion were explored. To locate the source of the seismic waves recorded by the seismic detectors, the following passive seismic imaging conditions were used:

[0107] I(x)=∑ t u 2 (x, t) Formula (2)

[0108] where I(x) is the imaging condition at the receiver location (x) and u(x, t) is the receiver wavefield reconstructed by:

[0109]

[0110] Where D(x r , ω) is the receiver position x r The recorded data after Fourier transformation at the location, * is the complex conjugate, G(x r , x, ω) is the frequency domain Green's function. The Green's function can be used to approximate the wave equation using finite differences or other numerical methods (e.g., ray-based methods).

[0111] The reconstructed wavefield is calculated using formula (3), which makes it easier to observe seismic waves from underground sources. After locating the source using formula (2), the location of the located source is shallower than the true drill bit depth. However, the location of the source coincides with the location of the maximum velocity contrast. Therefore, the received body waves come from a secondary source that is converted from tube waves in the wellbore. Wave mode conversion occurs at the location where the larger velocity contrast exits, or at certain discontinuities or density anomalies in the casing or wellbore formation (e.g., perforations, drill string locks, packers). On the other hand, tube waves in the wellbore are related to the movement of the drill string, vibration of the drill bit, and other drilling activities.

[0112] With the source position x s As a reference image point, the time series u(x s , t) and a time-frequency transform can be applied to the time series. Once compared to the drilling activity, it is determined that the time series is consistent with the drilling activity. Through the analysis of the reconstructed wavefield at the source location, source imaging and time series, it can be concluded that the recorded seismic waves (mainly body waves generated by tube waves) appear to be useful for SWD.

[0113] For the validation process of different acquisition geometries, a focused beam approach can be used. This approach utilizes migration as a dual focusing process where the source and receiver fields can be focused individually for a given velocity model. This, in turn, reveals the amplitude accuracy, offset and azimuthal coverage, and spatial resolution required for a particular field geometry. This dual focusing approach can be done individually for each target diffraction point at each specific frequency and given location. In some aspects, the same velocity model as used for depth at the bit imaging, and the target point is assumed to be the projection of the wellhead to the target horizon or target depth. In some aspects, the source is always a single point associated with the drill bit position, and the receiver array is on a fixed layout that undergoes this analysis before being modified for different target depths. The results of this analysis, obtained in real time, allow the current seismic geometry to be evaluated in terms of resolution and amplitude coverage, and new acquisition geometries to be proposed based on the changing source depth.

[0114] Fig.31 A diagram 3100 showing the field test acquisition geometry 3108 and well locations 3106 is shown. As previously described, using Fig.31 The fixed geometry shown consists of one thousand receiver points with a roughly circular shape for initial field experiments to record passive seismic while drilling. In this experiment, the well location is 2.6 kilometers away from the center of the receivers in the specific geometry.

[0115] Fig.32 Graph 3200 of raw recorded passive seismic data without any pre-processing applied to a field experiment is shown. Graph 3200 includes an x-axis depicting the trajectory of the raw recorded data and a y-axis depicting the time (in seconds) of the raw data. Fig.32 Graph 3200 shows 12 seconds of raw recorded passive seismic data without any preprocessing applied.

[0116] Fig.33 Shows Fig.33 The original recorded data reconstructs the wave field at different times (a, b and c). Fig.33 In the figure, parts (a), (b) and (c) show the use of Fig.32 Three different time snapshots of seismic waves recorded by the on-site passive seismic device in. As shown in the figure, part (a) shows the wave field at time (T); part (b) shows the wave field at T+0.04 seconds; and part (c) shows the wave field at T+0.08 seconds. From these three reconstructed wave field snapshots, it can be inferred that the seismic waves propagated from the wellbore to the seismic sensors on the surface.

[0117] Figure 34A-Figure 34B A graph showing secondary energy and drill bit position and stack velocity curves. For example, Fig.34AAn image of a secondary energy source and drill bit location is shown. Here, point 3402 represents the image around the secondary source, point 3404 represents the true location of the drill bit, and point 3406 represents the well path. Fig.34A A stack velocity curve is shown. Here, the horizontal dashed line represents the pseudo depth (time) position of the secondary energy source.

[0118] Fig.35 A time-frequency analysis diagram of recorded and processed passive seismic data is shown. For example, a time-frequency analysis is performed on the recorded passive data. The data spans a three-hour recording period and shows an excellent correlation between the time-frequency response and the drilling activity. In some aspects, for example, seismic logging while drilling technology can be used to extract a time series of source locations and predict rock properties in real time by analyzing the correction between the time series and rock properties. For example, a seismic logging while drilling workflow may include the following sequence (in the order described or in other orders). First, a shift-out correction is applied to the observed data, for example, by applying a source-receiver distance-related time shift to each trajectory. Second, the corrected (or time-shifted) trajectories may be stacked into a single trajectory. In this example, the amplitude values ​​of all trajectories for each time step may be added and normalized to provide a super trajectory. Third, a time-frequency analysis method (such as a short-time Fourier transform) may be applied to the stacked trajectories. Applying a time-frequency analysis method may decompose the time series within each short time window into different frequency components. Fourth, for example, by applying machine learning techniques such as neural network analysis, rock properties may be predicted from the time-frequency spectrum. The main components required to predict the attributes may include data obtained earlier under similar conditions. Fifth, the drilling program can be adjusted in real time using information including predicted knowledge of the geological formations around and in front of the drill bit (e.g., rock hardness, pore pressure, and fractures). Adjustments made to the drilling program can result in optimizations related to drilling time and cost.

[0119] The specific features described may be implemented in digital electronic circuits, or in computer hardware, firmware, software, or a combination thereof. The apparatus may be implemented in a computer program product tangibly embodied in an information carrier (e.g., in a machine-readable storage device executed by a programmable processor); and the method steps may be performed by a programmable processor executing a program of instructions to perform the functions described by operating on input data and producing output. The described features may be implemented in one or more computer programs executable on a programmable system, wherein the programmable system includes at least one programmable processor, at least one input device, and at least one output device, the programmable processor being coupled to receive data and instructions from a data storage system and to send data and instructions to it. A computer program is a set of instructions that can be used directly or indirectly in a computer to perform an activity or produce a result. A computer program may be written in any form of programming language, including compiled or interpreted languages, and may be deployed in any form, including as a stand-alone program or as a module, component, subroutine, or other unit suitable for use in a computing environment.

[0120] For example, suitable processors for executing instruction programs include general and special purpose microprocessors and single processors or one of multiple processors of any kind of computer. Typically, the processor will receive instructions and data from a read-only memory or a random access memory or both. The essential elements of a computer are a processor for executing instructions and one or more memories for storing instructions and data. Typically, a computer will also include one or more mass storage devices for storing data files, or be operably coupled to communicate with one or more mass storage devices; such devices include disks (such as internal hard disks and removable disks); magneto-optical disks; and optical disks. Storage devices suitable for tangibly embodying computer program instructions and data include all forms of non-volatile memory, for example, semiconductor memory devices including such as erasable programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM), solid-state hard disks (SSD), and flash memory devices; disks (such as internal hard disks and removable disks); magneto-optical disks; and CD ROM and DVD-ROM disks. The processor and memory can be supplemented by or incorporated into an ASIC (application-specific integrated circuit).

[0121] To provide interaction with a user, these features may be implemented on a computer having a display device, such as a CRT (cathode ray tube) or LCD (liquid crystal display) or LED (light emitting diode) monitor for displaying information to the user, and a keyboard and pointing device, such as a mouse or trackball through which the user can provide input to the computer. Additionally, such activities may be implemented via a touch screen flat panel display and other appropriate mechanisms.

[0122] These features can be implemented in a control system that includes a back-end component (e.g., a data server), or in a control system that includes a middleware component (e.g., an application server or an Internet server), or in a control system that includes a front-end component (e.g., a client computer with a graphical user interface or an Internet browser), or any combination of the above. The components of the system can be connected by any form or medium of digital data communication (e.g., a communication network). Examples of communication networks include local area networks (LANs), wide area networks (WANs), peer-to-peer networks (with ad hoc or static members), grid computing infrastructures, and the Internet.

[0123] Although this specification contains many specific implementation details, these details should not be interpreted as limitations on the scope that can be claimed, but rather as descriptions of features that are peculiar to specific examples. In a single embodiment, certain features described in the context of a separate embodiment in this specification may also be implemented in combination. On the contrary, the different features described in a single implementation context may also be implemented separately in multiple implementations, or in appropriate sub-combinations. In addition, although features may be described as working in certain combinations and even initially claimed as such, one or more features from the claimed combination may be deleted from the combination in some cases, and the claimed combination may be directed to a sub-combination or a variant of a sub-combination.

[0124] Similarly, although operations are depicted in a particular order in the accompanying drawings, this should not be understood as requiring that the operations be performed in the particular order shown or in a sequential order, or that all of the operations shown be performed to achieve a desired result. In some contexts, multitasking and parallel processing may be advantageous. In addition, the separation of various system components in the implementations described should not be understood as requiring such separation in all implementations, and it should be understood that the described program components and systems can generally be integrated into a single software product or packaged into multiple software products.

[0125] A number of implementations have been described. However, it should be understood that various modifications may be made without departing from the spirit and scope of the present disclosure. For example, the example operations, methods, or processes described may include more steps or fewer steps than described. In addition, the steps in such example operations, methods, or processes may be performed in an order different from that described or shown in the figures. Therefore, other implementations are within the scope of the appended claims.

Claims

1. A method for drilling a wellbore, comprising: A seismic while drilling (SWD) system is operated to form a wellbore from the surface of the earth to a subsurface zone at a specific depth below the surface of the earth, the SWD system comprising a passive acoustic energy source and a plurality of acoustic energy receivers located at the surface of the earth, the passive acoustic energy source comprising at least a portion of a drill string, the plurality of acoustic energy receivers comprising: a first set of acoustic receivers positioned on the surface in a first geometric arrangement, wherein the first geometric arrangement includes a first square ring centered at a wellhead of the wellbore, which includes the first set of acoustic receivers and a first square exclusion zone within the first square ring that excludes the first set of acoustic receivers, a second set of acoustic energy receivers positioned on the surface in a second geometric arrangement different from the first geometric arrangement, wherein the second geometric arrangement includes a second square ring centered at the wellhead of the wellbore and including the second set of acoustic energy receivers and a second square exclusion zone within the second square ring, the second square exclusion zone excluding the second set of acoustic energy receivers and including an area surrounding the first square ring and the first square exclusion zone, and a third set of acoustic energy receivers positioned on the surface in a third geometric arrangement different from the first geometric arrangement and the second geometric arrangement, wherein the third geometric arrangement includes a cross centered at a wellhead of the wellbore that includes the third set of acoustic energy receivers; During the wellbore formation, recording acoustic signals generated by the passive acoustic energy source using the plurality of acoustic energy receivers, the recording comprising: recording, with a first set of acoustic receivers, a first set of acoustic signals generated by a passive acoustic energy source between the surface and a first depth, recording, with a second set of acoustic receivers, a second set of acoustic signals generated by a passive acoustic energy source between the first depth and a second depth greater than the first depth, and recording, with a third set of acoustic receivers, a third set of acoustic signals generated by a passive acoustic energy source between the second depth and a third depth; processing the recorded acoustic signals to predict the subsurface location of the passive acoustic energy source; and Based on the predicted subsurface location of a passive acoustic energy source, the SWD system is used to geo-steer the passive acoustic energy source to a specific depth below the earth's surface.

2. The method according to claim 1, wherein: The passive acoustic energy source includes at least a portion of a drill string and a drill bit of the SWD system, and the recorded acoustic signals include direct acoustic signals from the passive acoustic energy source and reflected acoustic signals from the passive acoustic energy source.

3. The method according to claim 1, wherein: The third depth is deeper than the second depth.

4. The method according to claim 3, wherein: The first depth is 250 meters, the second depth is 500 meters and the third depth is 1000 meters.

5. The method according to claim 1, wherein: The first geometric arrangement covers a first spatial area on the surface, the second geometric arrangement covers a second spatial area on the surface that is larger than the first spatial area, and the third geometric arrangement covers a third spatial area on the surface that is larger than the second spatial area.

6. The method according to claim 1, wherein: Processing the recorded acoustic signals to predict the subsurface location of the passive acoustic energy source includes: cross-correlating recorded acoustic signals from different ones of the plurality of acoustic energy receivers; determining a travel-time difference image of recorded acoustic signals from the passive acoustic energy source and from different ones of the plurality of acoustic energy receivers; and The travel time difference images are stacked.

7. The method according to claim 2, wherein: The third depth is deeper than the second depth.

8. The method according to claim 7, wherein: The first depth is 250 meters, the second depth is 500 meters, and the third depth is 1000 meters.

9. The method according to claim 8, further comprising: The unique geometric arrangement of each of the plurality of groups of acoustic energy receivers is verified using one or more hardware processors of the acoustic energy processing system.

10. The method according to claim 9, wherein: Processing includes: cross-correlating recorded acoustic signals from different acoustic energy receivers in each of the plurality of groups of acoustic energy receivers; determining a travel-time difference image of the recorded acoustic signals from the passive acoustic energy source and different acoustic energy receivers in the set of acoustic energy receivers; and The travel time difference images are stacked.

11. A seismic while drilling (SWD) system comprising: a drilling system including a drilling rig, a drill string, and a drill bit, the drilling system being configured to form a wellbore starting from the surface of the earth to a subsurface region at a particular depth below the surface of the earth, the drilling system including a passive acoustic energy source; An acoustic energy receiver system includes a plurality of acoustic energy receivers located on the surface of the earth, wherein the plurality of acoustic energy receivers include: a first set of acoustic receivers positioned on the surface in a first geometric arrangement, wherein the first geometric arrangement includes a first square ring centered at a wellhead of the wellbore, which includes the first set of acoustic receivers and a first square exclusion zone within the first square ring that excludes the first set of acoustic receivers, a second set of acoustic energy receivers positioned on the surface in a second geometric arrangement different from the first geometric arrangement, wherein the second geometric arrangement includes a second square ring centered at the wellhead of the wellbore and including the second set of acoustic energy receivers and a second square exclusion zone within the second square ring, the second square exclusion zone excluding the second set of acoustic energy receivers and including an area surrounding the first square ring and the first square exclusion zone, and a third set of acoustic energy receivers positioned on the surface in a third geometric arrangement different from the first geometric arrangement and the second geometric arrangement, wherein the third geometric arrangement includes a cross centered at the wellhead of the wellbore including the third set of acoustic energy receivers; and An acoustic energy processing system is configured to perform operations comprising: recording acoustic signals generated by the passive acoustic energy source using the plurality of acoustic energy receivers during wellbore formation, the recording comprising: recording, with a first set of acoustic receivers, a first set of acoustic signals generated by a passive acoustic energy source between the surface and a first depth, recording, with a second set of acoustic receivers, a second set of acoustic signals generated by a passive acoustic energy source between the first depth and a second depth greater than the first depth, and recording, with a third set of acoustic receivers, a third set of acoustic signals generated by a passive acoustic energy source between the second depth and a third depth; processing the recorded acoustic signals to predict the subsurface location of the passive acoustic energy source, and The drilling system is controlled to geo-steer the drill head to a specific depth below the earth's surface based on the predicted subsurface location of the passive acoustic energy source.

12. The SWD system of claim 11, wherein: The passive acoustic energy source includes at least a portion of a drill string and a drill bit of the drilling system, and the recorded acoustic signals include direct acoustic signals from the passive acoustic energy source and reflected acoustic signals from the passive acoustic energy source.

13. The SWD system of claim 11, wherein: The third depth is deeper than the second depth.

14. The SWD system of claim 13, wherein: The first depth is 250 meters, the second depth is 500 meters and the third depth is 1000 meters.

15. The SWD system of claim 11, wherein: The first geometric arrangement covers a first spatial area on the surface, the second geometric arrangement covers a second spatial area on the surface that is larger than the first spatial area, and the third geometric arrangement covers a third spatial area on the surface that is larger than the second spatial area.

16. The SWD system of claim 11, wherein: The operations of processing the recorded acoustic signals to predict the subsurface location of the passive acoustic energy source include: cross-correlating recorded acoustic signals from different ones of the plurality of acoustic energy receivers; determining a travel-time difference image of recorded acoustic signals from the passive acoustic energy source and from different ones of the plurality of acoustic energy receivers; and The travel time difference images are stacked.

17. The SWD system of claim 12, wherein: The first geometric arrangement covers a first spatial area on the surface, the second geometric arrangement covers a second spatial area on the surface that is larger than the first spatial area, and the third geometric arrangement covers a third spatial area on the surface that is larger than the second spatial area.

18. The SWD system of claim 17, wherein: The operations of processing the recorded acoustic signals to predict the subsurface location of the passive acoustic energy source include: cross-correlating recorded acoustic signals from different ones of the plurality of acoustic energy receivers; determining a travel-time difference image of recorded acoustic signals from the passive acoustic energy source and different ones of the plurality of acoustic energy receivers; and The travel time difference images are stacked.

19. The SWD system of claim 18, wherein: The third depth is deeper than the second depth.

20. A computer-implemented method for determining a drill bit position, comprising: identifying, using one or more hardware processors in an acoustic energy processing system, a plurality of acoustic energy signals received from a passive acoustic energy source at a plurality of groups of acoustic energy receivers that are part of a wellbore drilling system, wherein each group of the plurality of groups of acoustic energy receivers covers a unique spatial region and is configured to detect at least a portion of the plurality of acoustic energy signals at a unique depth range below the earth's surface, the plurality of groups of acoustic energy receivers comprising: a first set of acoustic receivers positioned on the surface in a first geometric arrangement, wherein the first geometric arrangement includes a first square ring centered at a wellhead of the wellbore drilling system, which includes the first set of acoustic receivers and a first square exclusion zone within the first square ring that excludes the first set of acoustic receivers, a second set of acoustic receivers positioned on the surface in a second geometric arrangement different from the first geometric arrangement, wherein the second geometric arrangement includes a second square ring centered on the wellhead, which includes the second set of acoustic receivers and a second square exclusion zone within the second square ring, the second square exclusion zone excluding the second set of acoustic receivers and including an area surrounding the first square ring and the first square exclusion zone, and a third set of acoustic energy receivers positioned on the surface in a third geometric arrangement different from the first geometric arrangement and the second geometric arrangement, wherein the third geometric arrangement includes a cross centered at the wellhead and including the third set of acoustic energy receivers; and Processing the plurality of acoustic energy signals using one or more hardware processors in the acoustic energy processing system, the processing comprising: processing a first set of acoustic signals recorded by a first set of acoustic receivers and generated by a passive acoustic energy source between the surface and a first depth, processing a second set of acoustic signals generated by a passive acoustic energy source between the first depth and a second depth greater than the first depth recorded by a second set of acoustic energy receivers, and processing a third set of acoustic signals generated by a passive acoustic energy source between the second depth and a third depth deeper than the second depth recorded by a third set of acoustic energy receivers; determining a drill bit position of the wellbore drilling system based on the processed plurality of acoustic signals using one or more hardware processors in the acoustic energy processing system; and A geosteering path of the drill bit is updated based on the determined drill bit position using one or more hardware processors in the acoustic energy processing system.

21. The computer-implemented method of claim 20, wherein: The passive acoustic energy source includes at least one of the drill bit or one or more casing collars of the drilling system.

22. The computer-implemented method of claim 20, further comprising: The unique geometric arrangement of each of the plurality of groups of acoustic energy receivers is verified using one or more hardware processors in the acoustic energy processing system.

23. The computer-implemented method of claim 20, wherein: The processing includes: cross-correlating recorded acoustic signals from different acoustic energy receivers of each of the plurality of groups of acoustic energy receivers; determining a travel-time difference image of recorded acoustic signals from the passive acoustic energy source and from different acoustic energy receivers in the set of acoustic energy receivers; and The travel time difference images are stacked.

Images