阅读说明：本技术 使用随钻地震（swd）采集地震数据 (Seismic data acquisition using Seismic While Drilling (SWD) ) 是由 穆斯塔法·纳赛尔·阿尔-阿里 阿布杜拉奇兹·穆罕默德·阿尔穆哈迪 艾玛德·阿布多·阿尔-赫亚力 于 2020-02-24 设计创作，主要内容包括：用于确定钻头位置的技术包括：识别在多组声学接收器处从被动声能源接收的多个声能信号,该被动声能源是井眼钻井系统的一部分；处理多个声能信号；基于处理的多个声学信号确定井眼钻井系统的钻头的位置；基于确定的钻头位置更新钻头的地质导向路径。(Techniques for determining bit position include: 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 a 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; updating the geosteering path of the drill bit based on the determined bit position.)

1. A method of drilling a wellbore, comprising:

operating a seismic while drilling SWD system to form a borehole starting from an earth surface to a subterranean zone at a particular depth below the earth surface, the SWD system comprising a passive acoustic energy source comprising at least a portion of a drill string and an acoustic energy receiver bank located at the earth surface;

recording acoustic signals generated by the passive acoustic energy source using the acoustic energy receiver bank during formation of the borehole;

processing the recorded acoustic signals to predict a subsurface location of the passive acoustic energy source; and

geosteering the passive acoustic energy source to a particular depth below the surface of the earth using the SWD system based on the predicted subsurface location of the passive energy source.

2. The method of claim 1, wherein the passive acoustic energy source comprises a drill bit of the SWD system.

3. The method of claim 1, wherein the acoustic energy receiver group comprises a first group, and recording the acoustic signal generated by the passive acoustic energy source using the acoustic energy receiver group comprises: recording an acoustic signal generated by the passive acoustic energy source between the earth's surface and a first depth using a first set of acoustic energy receivers, the method further comprising:

recording acoustic signals generated by the 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 located on the earth's surface.

4. The method of claim 3, further comprising:

recording an acoustic signal generated by the 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 located on the earth's surface.

5. The method of claim 4, wherein the first depth is 250 meters, the second depth is 500 meters and the third depth is 1000 meters.

6. The method of claim 4, wherein the first set of acoustic energy receivers are spaced apart on the earth's surface in a first geometry, the second set of acoustic energy receivers are spaced apart on the earth's surface in a second geometry, and the third set of acoustic energy receivers are spaced apart on the earth's surface in a third geometry.

7. The method of claim 6, wherein the first geometry covers a first spatial area on the earth's surface, the second geometry covers a second spatial area on the earth's surface larger than the first spatial area, and the third geometry covers a third spatial area on the earth's surface larger than the second spatial area.

8. The method of claim 1, wherein processing the recorded acoustic signals to predict the subsurface location of the passive acoustic energy source comprises:

cross-correlating the recorded acoustic signals from different acoustic receivers in the group of acoustic receivers;

determining a travel time difference image of the recorded acoustic signals from the passive acoustic energy source and from different acoustic receivers in the group of acoustic receivers; and

stacking the travel time difference images.

9. A seismic while drilling SWD system, comprising:

A drilling system comprising a drilling rig, a drill string, and a drill bit, the drilling system configured to form a borehole from a surface to a subterranean zone at a particular depth below the surface, the drilling system comprising a passive acoustic energy source;

an acoustic receiver system comprising a group of acoustic energy receivers located at the earth's surface; and

an acoustic energy processing system configured to perform operations comprising: the method includes recording acoustic signals generated by the passive acoustic energy source during formation of a borehole using the set of acoustic energy receivers, processing the recorded acoustic signals to predict a subsurface location of the passive acoustic energy source, and controlling the drilling system to geosteer the drill bit to a particular depth in the subsurface based on the predicted subsurface location of the passive energy source.

10. The SWD system of claim 9, wherein said passive acoustic energy source comprises a drill bit of said drilling system.

11. The SWD system of claim 9, wherein said group of acoustic energy receivers comprises a first group of acoustic energy receivers configured to receive acoustic signals generated by said passive acoustic energy source between said surface and a first depth, said system further comprising:

A second set of acoustic energy receivers located on the earth's surface and configured to receive acoustic signals generated by the passive acoustic energy source between the first depth and a second depth deeper than the first depth, the acoustic energy processing system configured to perform operations comprising: recording an acoustic signal generated by the passive acoustic energy source during formation of a borehole using the second set of acoustic energy receivers.

12. The SWD system of claim 11, further comprising a third set of acoustic energy receivers located on the earth's surface and configured to receive acoustic signals generated by said passive acoustic energy source between said second depth and a third depth deeper than said second depth, said acoustic energy processing system configured to perform operations comprising: recording an acoustic signal generated by the passive acoustic energy source during formation of a borehole using the third set of acoustic energy receivers.

13. The SWD system of claim 12, wherein said first depth is 250 meters, said second depth is 500 meters and said third depth is 1000 meters.

14. The SWD system of claim 12, wherein said first set of acoustic energy receivers are spaced apart on the earth's surface in a first geometry, said second set of acoustic energy receivers are spaced apart on the earth's surface in a second geometry, and said third set of acoustic energy receivers are spaced apart on the earth's surface in a third geometry.

15. The SWD system of claim 14, wherein said first geometry covers a first spatial area on the earth's surface, said second geometry covers a second spatial area on the earth's surface larger than said first spatial area, and said third geometry covers a third spatial area on the earth's surface larger than said second spatial area.

16. The SWD system of claim 9, wherein the operation of processing the recorded acoustic signals to predict the subsurface location of the passive acoustic energy source comprises:

cross-correlating the recorded acoustic signals from different acoustic receivers in the group of acoustic receivers;

determining a travel time difference image of the recorded acoustic signals from the passive acoustic energy source and from different acoustic receivers in the group of acoustic receivers; and

stacking the travel time difference images.

17. A computer-implemented method for determining a position of a drill bit, comprising:

identifying, using one or more hardware processors in an acoustic energy processing system, 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 using one or more hardware processors in the acoustic energy processing system;

Determining, using one or more hardware processors in the acoustic energy processing system, a bit position of the wellbore drilling system based on the processed plurality of acoustic signals; and

updating, using one or more hardware processors in the acoustic energy processing system, a geosteering path of the drill bit based on the determined drill bit position.

18. The computer-implemented method of claim 17, wherein the passive acoustic energy source comprises at least one of the drill bit or one or more casing collars of the drilling system.

19. The computer-implemented method of claim 17, wherein each of the plurality of sets 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 a surface of the earth.

20. The computer-implemented method of claim 17, further comprising: verifying, using one or more hardware processors in the acoustic energy processing system, a unique geometry for each of the plurality of sets of acoustic receivers.

21. The computer-implemented method of claim 17, wherein the processing comprises:

cross-correlating the recorded acoustic signals from different acoustic receivers of each of the plurality of groups of acoustic receivers;

Determining a travel time difference image of the recorded acoustic signals from the passive acoustic energy source and from different acoustic receivers in the group of acoustic receivers; and

stacking the travel time difference images.

Technical Field

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

During drilling operations, drilling personnel typically rely on prior drilling information, ongoing drilling measurements, and interrelated drilling cuttings to give an indication of the formation being drilled. This approach may result in delays in providing information to the drilling personnel that prevent them from making a quick decision and thus risk. The risk increases even more when these decisions to be made are critical to the safety of the drilling personnel, the equipment and the integrity of the drilling.

Disclosure of Invention

In a general embodiment, a method for drilling a wellbore includes operating a Seismic While Drilling (SWD) system to form a wellbore from a surface to a subterranean zone at a particular depth below the surface. The SWD system includes a passive acoustic energy source comprising at least a portion of a drill string and a bank of acoustic energy receivers located at the surface. The method also includes recording an acoustic signal generated by the passive acoustic energy source with an acoustic energy receiver bank during formation of the wellbore. The method also includes processing the recorded acoustic signals to predict a subsurface location of the passive acoustic energy source. The method also includes geosteering the passive acoustic energy source to a particular depth below the surface of the earth using the SWD system based on the predicted subsurface location of the passive energy source.

In one aspect that may be combined with the example embodiments, the passive acoustic energy source includes a drill bit of a SWD system.

In another aspect that may be combined with any of the preceding aspects, the acoustic energy receiver group includes a first group.

In another aspect that may be combined with any of the preceding aspects, recording the acoustic signal generated by the passive acoustic energy source using an acoustic energy receiver group includes: an acoustic signal generated by a passive acoustic energy source between the earth's surface and a first depth is recorded using a first set of acoustic energy receivers.

Another aspect combinable with any of the preceding aspects further includes: acoustic signals generated by the passive acoustic energy source between the first depth and a second depth deeper than the first depth are recorded using a second set of acoustic energy receivers located on the earth's surface.

Another aspect combinable with any of the preceding aspects further includes: an acoustic signal generated by the passive acoustic energy source between the second depth and a third depth deeper than the second depth is recorded using a third set of acoustic energy receivers located on the earth's surface.

In another aspect that 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.

In another aspect that may be combined with any of the preceding aspects, the first set of acoustic energy receivers are spaced apart on the earth's surface in a first geometry, the second set of acoustic energy receivers are spaced apart on the earth's surface in a second geometry, and the third set of acoustic energy receivers are spaced apart on the earth's surface in a third geometry.

In another aspect that may be combined with any of the preceding aspects, the first geometry covers a first spatial area on the earth's surface, the second geometry covers a second spatial area on the earth's surface that is larger than the first spatial area, and the third geometry covers a third spatial area on the earth's surface that is larger than the second spatial area.

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

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 from the surface to a subterranean zone at a particular depth below the surface. The drilling system includes a passive acoustic energy source; an acoustic receiver system comprising a group of acoustic energy receivers located at the earth's surface; and an acoustic energy processing system configured to perform operations. The operations include: the method includes recording acoustic signals generated by a passive acoustic energy source during formation of a borehole using an acoustic energy receiver bank, processing the recorded acoustic signals to predict a subsurface location of the passive acoustic energy source, and controlling a drilling system to geosteer a drill bit to a particular depth below the subsurface based on the predicted subsurface location of the passive energy source.

In one aspect that may be combined with example embodiments, the passive acoustic energy source includes a drill bit of a drilling system.

In another aspect that 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 earth's surface and a first depth.

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

In another aspect that may be combined with any of the preceding aspects, an acoustic energy processing system is configured to perform operations comprising: a second acoustic energy receiver is used to record the acoustic signal generated by the passive acoustic energy source during formation of the borehole.

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

In another aspect that may be combined with any of the preceding aspects, an acoustic energy processing system is configured to perform operations comprising: the acoustic signal generated by the passive acoustic energy source is recorded during formation of the borehole using a third acoustic energy receiver.

In another aspect that 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.

In another aspect that may be combined with any of the preceding aspects, the first set of acoustic energy receivers are spaced apart on the earth's surface in a first geometry, the second set of acoustic energy receivers are spaced apart on the earth's surface in a second geometry, and the third set of acoustic energy receivers are spaced apart on the earth's surface in a third geometry.

In another aspect that may be combined with any of the preceding aspects, the first geometry covers a first spatial area on the earth's surface, the second geometry covers a second spatial area on the earth's surface that is larger than the first spatial area, and the third geometry covers a third spatial area on the earth's surface that is larger than the second spatial area.

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

In another example embodiment, a computer-implemented method for determining a position of a drill bit includes: 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 is identified using one or more hardware processors in the acoustic energy processing system. The computer-implemented method further comprises: the plurality of acoustic energy signals are processed using one or more hardware processors in the acoustic energy processing system. The computer-implemented method further comprises: determining, using one or more hardware processors in the acoustic energy processing system, a position of a drill bit of the wellbore drilling system based on the processed plurality of acoustic signals. The computer-implemented method further comprises: updating, using one or more hardware processors in the acoustic energy processing system, a geosteering path of the drill bit based on the determined drill bit position.

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

In another aspect that may be combined with any of the preceding aspects, each of the plurality of sets 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 earth's surface.

Another aspect combinable with any of the preceding aspects further includes: a unique geometry for each of a plurality of groups of acoustic receivers is verified using one or more hardware processors in the acoustic energy processing system.

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

Implementations consistent with 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 than conventional SWD systems, which have inherent problems with low signal-to-noise ratios 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. Additionally, 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 focus and image an object of interest with variable depth in an optimal manner during SWD. Moreover, embodiments of the present disclosure may provide a large-scale acquisition that allows recording of near and far energy fields to allow better separation of signal and noise in successive data processing and analysis steps.

The details of one or more implementations of the subject matter described in this disclosure are set forth in the accompanying drawings and the description. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.

Drawings

FIG. 1 illustrates an example workflow of a real-time Seismic While Drilling (SWD) process according to this disclosure.

FIG. 2 is an example of historical data used in the workflow of FIG. 1 according to the present disclosure.

FIG. 3 is an example of well casing data used in the workflow of FIG. 1 according to the present disclosure.

4A-4C illustrate examples of historical drilling information and parameters used in the workflow of FIG. 1 according to the present disclosure.

5A-5D illustrate examples of regional petrophysical data extracted from seismic images used in the workflow of FIG. 1 according to the present disclosure.

FIG. 6 is an example of petrophysical data from sonic logging used in the workflow of FIG. 1 according to the present disclosure.

FIG. 7 illustrates an example process for generating an integrated subsurface model according to this disclosure.

Fig. 8 illustrates an example embodiment of a SWD system according to this disclosure.

9A-9B illustrate example embodiments of seismic sensor arrays according to this disclosure.

FIG. 10 illustrates an example embodiment of a symmetric seismic acquisition geometry according to this disclosure.

11A-11D illustrate example embodiments of a symmetric acquisition geometry centered on a wellhead and targeted at a shallow depth according to the present disclosure.

12A-12B illustrate example first geometry verification steps showing vertical cross-sectional images through forward modeling according to the present disclosure.

Fig. 13A-13B illustrate a first geometry verification step showing horizontal cross-sectional images by forward modeling according to the present disclosure.

Fig. 14 illustrates an example symmetric acquisition geometry centered on a wellhead and targeting a shallow depth according to the present disclosure.

Fig. 15A-15B illustrate example second geometry verification steps showing vertical cross-sectional images through forward modeling according to the present disclosure.

Fig. 16A-16B illustrate a second geometry verification step showing horizontal cross-sectional images by forward modeling according to the present disclosure.

Fig. 17 illustrates an example symmetric acquisition geometry centered on a wellhead and targeting a deeper depth according to the present disclosure.

18A-18B illustrate example third geometry verification steps showing vertical cross-sectional images through forward modeling according to the present disclosure.

Fig. 19A-19B illustrate a third geometry verification step showing horizontal cross-sectional images by forward modeling according to the present disclosure.

FIG. 20 shows an example embodiment of the SWD system of FIG. 8 with possible locations for additional acoustic sensors at the wellsite.

Fig. 21 illustrates example different acquisition geometries based on different depth ranges according to the present disclosure.

FIG. 22 illustrates an example schematic of travel time differences with a pair of two receivers and one downhole passive source according to this disclosure.

FIG. 23 illustrates an example workflow of drill bit positions using cross-correlation and travel time differences according to this disclosure.

FIG. 24 illustrates an example simple layer earth model with identified bit positions according to this disclosure.

FIG. 25 shows an example graph of recorded seismic while drilling according to the present disclosure.

FIG. 26 shows at receiver r according to the present disclosure₁An example graph of cross-correlation is performed using a reference.

FIG. 27 shows at receiver r according to the present disclosure₂An example graph of cross-correlation is performed using a reference.

FIG. 28 shows at receiver r according to the present disclosure₁Example diagrams of travel time difference imaging after cross-correlation using a reference are shown.

FIG. 29 shows at receiver r according to the present disclosure ₂Example diagrams of travel time difference imaging after cross-correlation using a reference are shown.

FIG. 30 illustrates an example diagram of stacked images revealing bit position according to the present disclosure.

Fig. 31 shows an example diagram of a field test acquisition geometry and well location according to the present disclosure.

FIG. 32 illustrates an exemplary graph of raw recorded passive seismic data without any preprocessing applied in accordance with the present disclosure.

FIG. 33 shows an example graph of reconstructed wavefields at different times according to this disclosure.

34A-34B illustrate images of secondary energy sources and positions of drill bits and stacking velocity profiles according to the present disclosure.

FIG. 35 illustrates a graph of time-frequency analysis of passive seismic data recorded and processed according to the present disclosure.

Detailed Description

FIG. 1 illustrates an example workflow 100 for a real-time Seismic While Drilling (SWD) system and process. In some aspects, a real-time SWD system (e.g., shown in fig. 8) provides real-time insights and information to drilling and geosteering personnel so that informed decisions can be made regarding ongoing drilling plans and steering directions. The illustrated workflow 100 includes a preparation process 102, an execution process 108, and a result process 120. In some aspects, the preparation phase 102 precedes the field execution phase 108 to ensure the quality of the collected data and to ensure smooth execution. The execution phase 108 occurs in real-time at the site where data is repeatedly collected, processed, and imaged while the drilling operation is in progress. The result of this workflow 100 is to provide real-time feedback 124 to the drilling engineer regarding the position of the drill bit, to make predictions ahead of the drill bit, etc.

As shown in fig. 1, 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 imaging step 116, and a geometry updating step 118. In a field acquisition step 110, the geometry layout is determined. In a data recording step 112, seismic data is recorded as well as direct and indirect guided recordings. In step 114, the recorded data is processed, for example by cross-correlation, travel time difference (of the sound waves) processing and stacking. In the imaging step 116, migration and velocity update 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 validated. In some aspects, a computing system, such as an acoustic energy processing system, may implement all or part of the execution stage 108.

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

In this example, in the preparation phase 102, the historical data 104 and the experimental design data 106 may be viewed to define a target drilling depth range for seismic data to be recorded while the SWD system is running, for example. For example, the historical data 102 may include existing regional seismic data, planned well paths, historical drilling information about nearby wells (near the planned well paths), and regional petrophysical data. For example, existing regional seismic data may provide an image of the subsurface formations or strata to be drilled. This data typically comes in the form of three-dimensional (3D) volumes that cover a specific surface area and penetrate to a specific depth of the earth. The limits of such data may be represented by surface coordinates and depth (X, Y, Z). Additionally, such images are typically from seismic surveys acquired in the same area as the planned well path area. For example, FIG. 2 shows a cross-sectional image 200 that may have a spatial coverage of tens of kilometers (km) and kilometers in depth (e.g., 0-4km), and other relevant data that may also be used is a topographical map collected during an acquired seismic survey in order to properly reconstruct the seismic data for processing.

In some examples, the planned well path narrows the drill bit search area to a single path and paths around the suggested path. This path can be used to examine which layers in the seismic image the well path will pass through during drilling operations using the SWD system. Such information may also be used to predict a drilling timeline, as different rock strata may 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. Also, a narrowed search area 206 is shown. In this figure, a well 208 is shown, the well 208 representing a well previously drilled into a subterranean zone 212, which yields historical well information 210.

Other useful information that may be used is the well casing plan 300 shown in FIG. 3. FIG. 3 is an example plan 300 illustrating the design and measurement of a well casing that is lowered into a well during drilling to prevent the wall of the well from collapsing into the void created by the well. These casings are also used as safety measures to contain the drilling fluid and protect against sudden pressure increases due to the flow of pressurized fluid from the drilling formation or rock. Figure 3 shows a cross-sectional view of a well casing lowered to a vertical depth of 2 km. These casings are typically joined together (e.g., in a casing string) using relatively short lengths of tubing. These joints may act as amplifiers for acoustic waves propagating in the drilling fluid due to acoustic energy generated by a passive downhole acoustic energy source, such as vibration of the drill bit or drill string of a SWD system. Thus, knowledge of casing design may add information about the location of these casing joints and help, for example, to eliminate their effect on recorded signals or to use them as secondary sources of signals that provide information from adjacent formations.

Historical drilling information for nearby wells (shown as reference 210 in fig. 2) may provide insight into challenges faced in drilling in the same area. Valuable information needed to pre-plan a seismic data acquisition timeline is also provided. This data 210 may include, but is not limited to, measurement data such as drilling ROP, Weight On Bit (WOB), rotational speed of the drill bit in cycles per minute, torque used to drill through rock, and the like. Furthermore, other descriptive data such as drilling project activity over time may add value as they are generally similar to drilling in the same region. In fig. 2, different shading of the historical drilling information 210 indicates different drilling activities that occur. Fig. 4A-4C illustrate examples of measured drilling information and parameters 400. Other useful information may be the type of equipment, as different types of drill bits emit different amounts of sound waves into the solid rock being drilled.

Regional petrophysical data may be derived from subsurface rock properties in volumetric form extracted from existing regional seismic images or in linear form extracted from well logs. For example, fig. 5A-5D illustrate several petrophysical data 500 extracted from a seismic image 502 including density 504, velocity 506, and acoustic impedance 508. FIG. 6 shows petrophysical data from a seismic log 600, which is similar data limited to well locations and along its path, typically used to calibrate petrophysical data extracted from a seismic image.

FIG. 7 illustrates a process 700 for generating an integrated subsurface model 710 based on the execution of the preparation phase 102. 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 properties that will be used in later real-time steps to navigate and guide drilling operations. The integrated model may be created using statistics, mathematics, machine learning, data analysis, and artificial intelligence operations (e.g., interpolation, kriging, curve fitting, correlation, etc.). As shown in fig. 7 and described previously, the historical data 104 includes seismic data 702, well path data 704, well information data 706, and petrophysical data 708.

The workflow 100, and in particular the preparation phase 102, may also include an experiment design substep 106. For example, in some aspects, the collection of historical data in stage 104 may be followed by experimental design 106, where equipment selections are made, the geometry is designed and preplanned for system 800 (shown in fig. 8). Furthermore, modeling studies can be performed to verify the geometry and its feasibility. For example, the experimental design 106 may include a selection of equipment. For example, to achieve the goals of positioning and predicting ahead of the drill bit, equipment must be carefully selected to help ensure that a particular goal is achieved. Such targets include signals emitted by detecting drill bit vibrations and traveling through adjacent earth formations to the surface. These signals may be detected using surface seismic sensors distributed around the monitored well in a particular pattern or geometric design. Such targets also include detecting signals emitted by drill string vibrations into the formation adjacent the surface. Surface sensors may similarly detect these signals. Such targets also include detecting signals that are emitted forward by the drill bit and reflected back to the surface by deeper formations. Surface sensors may similarly detect these signals. Such targets also include detecting signals through the drilling mud or fluid through the borehole to the surface. For example, a riser pressure sensor may detect these signals. Such targets also include detecting drill bit features in the drilling assembly directly above the drill bit. These signals can be detected by downhole sensors mounted in the drill string or in the saver sub right above the drill bit. Such targets also include detecting surface noise generated by various sources at the surface where the drilling operation is taking place. These signals can be detected by high sensitivity surface seismic sensors. Such targets also include appropriate sampling of all detected signals in space and time. This may determine the number of sensors and their dynamic range that will be used in the surface or downhole assembly. Finally, such targets may also include proper focusing of the subsurface signals. This may determine the area coverage of the surface sensor.

To achieve these goals, some devices may be used for recording. For example, thousands of orders of magnitude surface sensor arrays with large spatial coverage may be used to detect all signals traveling up from the subsurface. Turning to fig. 8, the shaded blocks are an example arrangement of such a sensor array. Additionally, surface sensors of the order of hundreds of near noise or vibration sources may be used in drilling operations to record noise and enable subsequent steps to eliminate such noise. For example, FIG. 8 includes an example arrangement of sensor placement locations. Additionally, surface sensors may be used to record the guide trajectory to the surface near the drill string entry point. Alternatively, the guiding trajectory may be recorded at the drill bit itself or slightly upwards of the drill bit itself. Thus, one or more downhole sensors near the drill bit may be used. However, such placement may present difficulties in transmitting the recorded signals to the surface. Another option is to use a riser pressure sensor to record the background noise in the drilling fluid and extract the pilot signal from the background noise. Furthermore, instead of using a conventional geophone sensor array, a high sensitivity sensor may be used. High sensitivity sensors allow a reduction in the number of sensors required to achieve the same goal. Finally, flexible real-time recording equipment, such as wireless systems, may be used.

Fig. 8 shows an example embodiment of an SWD system 800, which SWD system 800 may be used in execution stage 108 to drill a wellbore and collect seismic data from passive seismic sources in SWD system 800 in real-time. As shown, 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 with a drill bit 816 coupled to a drill string 814. Drilling mud is pumped by mud pump 806 from mud tank 808 through drill string 814 to, for example, exit drill bit 816 and move cuttings back to the surface where derrick 802 is located. As shown, geophones 818 (acoustic sensors) are mounted 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.

As discussed, the SWD system 800 includes a plurality of acoustic sensors/sensor arrays. The number of sensors used to acquire seismic data for such experiments may be in the thousands of ranges, with the exception of hundreds of sensors used to acquire noise and guide trajectories that are subsequently used for data processing. These sensors may be conventional geophones, high sensitivity geophones, or any other specialized sensor, depending on the preferred array arrangement and acquisition requirements. In each array, there are many patterns to be used. FIGS. 9A-9B illustrate example embodiments of a seismic sensor array. As an example, fig. 9A shows an example array with a single sensing node, while fig. 9B shows an example with a three-by-three sensor array. Some of the main parameters in designing these patterns are the number of sensors in each array, the way these sensors are connected (in series or in parallel), and the specific coverage of the array. The number of sensors within the array may vary based on the sensitivity of the sensors to signals rather than noise. The greater the number of sensors in the array, the greater the sensitivity of the array to record signals, depending on the manner in which they are connected. The smaller the area coverage of the array, the less averaging or smoothing of the recorded signal.

FIG. 10 illustrates an example embodiment of a seismic acquisition geometry 1000. In this example, thousands of these independent arrays are formed together in a particular pattern to form the acquisition geometry. In fig. 10, each square 1002 equates to a sensor or sensor array, and each square 1004 represents the area of the exclusion zone.

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

The designed sensor array geometry may be iteratively verified using the focused beam approach within execution stage 108 before a decision to switch to the next geometry is made. For example, the following proposed acquisition geometries serve as examples to illustrate their range and flexible nature. Furthermore, they show how the acquisition geometry is designed taking into account the variable depth of the target. The actual geometry used with SWD system 800 is not limited to the three geometry examples disclosed in this disclosure, and may be implemented using air coverage and a different number of geometries based on the target depth requirements. On the other hand, initial field experiments (described later) demonstrated the feasibility of such a large-scale monitoring system for recording earthquakes while drilling. All disclosed geometries share common design aspects, such as being centered on the wellhead location and having a flexible exclusion zone (represented by block 1004 in fig. 10) that can be sized according to the drilling safety requirements of each well. Within this highly active exclusion zone, guide tracks can be recorded at different locations on the well mat, even on the rig itself, to support subsequent data processing and analysis.

11A-11D illustrate an example embodiment of a symmetric acquisition geometry 1100 centered at a well head and targeted at a shallow depth. The geometry 1100 targets a shallow depth of about 250 meters (m). Geometry 1100 is a hybrid combination of two-dimensional (2D) and 3D components centered on a wellhead. The first component is a coverage of 0.3 square kilometers (km)²) To better image the near field energy generated by shallow targets. To support the processing and analysis of the data, the second component consists of two intersecting two-dimensional receiver lines at the wellhead and extending 3 kilometers outward from the center to image the far-field energy produced by shallow targets.

Fig. 12A-12B illustrate geometry verification steps through forward modeling showing vertical cross-sectional images of the geometry 1100. Fig. 13A-13B illustrate geometry verification steps through forward modeling showing horizontal cross-sectional images of the geometry 1100. To validate the geometry 1100, a forward modeling study was conducted to virtually image a target with a depth of 900 feet (ft.), a constant medium velocity of 2000 meters per second (m/s), and a maximum frequency of 200 hertz (Hz). Forward modeling results in fig. 12A-12B and 13A-13B show concentrated energy extinguishment corresponding to a target at 900 feet. This validates the geometry 1100 for imaging shallow targets.

Fig. 14 shows a symmetric acquisition geometry 1400 centered on the well head and targeting a slightly deeper depth. Geometry 1400 targets a deeper depth (in this example) between 250m and 500 m. Geometry 1400 is also a hybrid combination of wellhead-centric 2D and 3D components. The first component is still a lower density square receiver covering a larger airborne range of 1.2 square kilometers to better image the near-field energy generated by slightly deeper targets than geometry 1100. The second assembly, identical to that in geometry 1100, consisting of two intersecting 2D receiver lines at the wellhead and extending 3 kilometers outward from the center, suggests imaging far field energy produced by slightly deeper targets.

Fig. 15A-15B illustrate geometry verification steps through forward modeling showing vertical cross-sectional images of the geometry 1400. Fig. 16A-16B illustrate geometry verification steps through forward modeling showing horizontal cross-sectional images of the geometry 1400. To verify the geometry 1400, a similar forward modeling study was conducted to virtually image a target having a depth of 1800 ft., a constant medium velocity of 2000m/s, and a maximum frequency of 200 Hz. Forward modeling results in fig. 15A-15B and 16A-16B show focused energy extinguishment corresponding to a target at 1800 feet. This validates the geometry 1400 for imaging a slightly deeper target (e.g., relative to geometry 1100).

Fig. 17 shows a symmetric acquisition geometry 1700 centered on the wellhead and targeting a deeper depth. Geometry 1700 targets greater than 500m and deeper depths up to 3000 m. Geometry 1700 is also a hybrid combination of wellhead-centered 2D components. 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 crossing at the wellhead and extending slightly more than 2 kilometers outward from the center to better image the far-field energy produced by deeper targets.

Fig. 18A-18B illustrate geometry verification steps through forward modeling, which shows vertical cross-sectional images of geometry 1700. Fig. 19A-19B illustrate the geometry verification steps through forward modeling, which shows horizontal cross-sectional images of the geometry 1700. To verify the third geometry, a similar forward modeling study was conducted to virtually image a target with a depth of 5000 ft, a constant medium velocity of 2000m/s, and a maximum frequency of 200 Hz. The forward modeling results in fig. 18A-18B and fig. 19A-19B show concentrated energy extinguishment corresponding to a target at 5000 feet. This validates the third geometry (e.g., relative to geometry 1100) for imaging a slightly deeper target.

Fig. 20 shows an example implementation of the SWD system 800 of fig. 8 with possible locations of additional acoustic sensors. As shown in fig. 20, 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 with a drill bit 816 coupled to a drill string 814. Drilling mud is pumped by mud pump 806 from mud tank 808 through drill string 814 to, for example, exit drill bit 816 and move cuttings back to the surface where derrick 802 is located. As shown, geophones 818 (acoustic sensors) are mounted 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.

In operation, and in preparation for seismic data acquisition or collection, the apparatus shown in fig. 20 is brought to the field or rig site to place the designed acquisition geometry or pattern on the earth's surface around the rig 802. These sensors (e.g., geophones 818) record seismic signals transmitted and reflected from the drill bit 816 and drill string 814 through the subsurface formations. The drilling rig and the drilling site are also equipped with sensors to record the pilot signal (bit characteristics) and surface noise due to drilling activity. These signals recorded by the surface sensors are characteristic of formation and bit vibrations. These two features may be separated by cross-correlation or other methods using a pilot signal recorded by a surface sensor near the drill string entry point to the surface. Similarly, drilling activity noise is decoded from the recorded signal.

Fig. 21 shows different acquisition geometries 1000, 1400 and 1700 based on different depth ranges. Once the SWD system 800 is armed, it can remain unchanged at each field deployment. The placement of the surface seismic sensors may be done simultaneously starting with a minimum coverage pattern targeting a shallow borehole depth. After placement of this initial pattern or geometry, recording is started from the beginning of drilling until a particular drilling depth is reached. Beyond this depth, the initial geometry (geometry 1000) may not be able to record the focused signal and may therefore be updated. Geometry 1400 then targets a deeper drilling depth range. The geometry 1400 may also be recorded while drilling through a second drilling depth range, after which it will again record the unfocused signal and will again be updated a second time. Geometry updates occur during drilling and are repeated until a maximum borehole depth is reached. The geometry update may be based on a drilling depth range as illustrated by the simplified data acquisition process (e.g., fig. 21) or may be adaptively changed based on signal focusing. The use of wireless seismic systems, particularly those with radio communication, may provide flexibility in sensor deployment so that such field operations can be performed quickly.

Fig. 22 shows a schematic diagram with a pair of two receivers (2202) located on the surface 2200 and the travel time difference of the downhole passive source 2204 (e.g., the drill bit of the SWD system 800). The use of large scale flexible acquisition geometries for seismic while drilling may allow for more accurate determination of drill bit position using the time-of-flight method. The main advantage of using a large number of receivers is the infinite possibility of using moreThe receivers are combined to verify the same target and improve signal-to-noise ratio. The schematic diagram shown in FIG. 22 illustrates a basic scenario, including a pair of surface receivers 2202, r₁And r₂Drill bit sources 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 bit source 2204 is received by each receiver 2202 at two different times, sharing a common time component and differing by the time difference.

The imaging conditions for locating the position of the drill bit using the travel time differences of a pair of surface receivers are defined by the following equation:

s(x,z)＝∫g(r₁,x,z,t)g(r₂x, z, t + τ) dt formula (1),

where g (r, x, z, t) is the green's function from any receiver r to a particular bit location (x, z) and τ is the travel time difference.

FIG. 23 shows an example workflow 2300 of drill bit positions using cross-correlation and travel time differences. As shown, for example, 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 track, allowing energy to be concentrated on the useful signal rather than noise. Next, in step 2306, a bit position is determined using multiple pairs of receivers and using the references to the imaging conditions set forth previously. This provides for multiple implementations of bit position. Next, in step 2308, the moveout images are stacked together. In step 2310, these implementations pinpoint the bit position.

FIG. 24 shows a simple layer earth model 2400. 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. Additionally, assume that the seismic is recorded using an acquisition geometry that covers the earth's surface at evenly spaced receivers and is centered on the rig. The use of a large number of receivers allows the use of cross-correlations and travel time differences for each receiver pair.

FIG. 25 shows seismic while drilling surface receiver 2500 as recorded by model 2400. Using all surface receivers when recording earthquakes while drillingWill be shown in the surface receiver 2500 of fig. 25, which shows seismic data (from a drill bit as a passive source) recorded in time (on the y-axis) at a distance (on the x-axis) away from the drill rig. FIG. 26 shows the use of a receiver r₁Cross-correlation surface receiver 2600 of reference (shown in schematic diagram of fig. 22). FIG. 27 shows the use of a receiver r₂A cross-correlation surface receiver 2700 of reference (as shown in the schematic of fig. 22). For all combinations of receiver pairs, the reference signal is used in a cross-correlation process resulting in a number of cross-correlation signals.

FIG. 28 shows the use of a receiver r ₁Reference (g) is imaged with the travel time difference after cross-correlation 2800. FIG. 29 shows the use of a receiver r₂Graph 2900 of travel time difference imaging after cross-correlation of the reference at (a). Fig. 30 shows a graph 3000 of stacked images revealing bit position. These cross-correlation signals are then used to image the bit position using the time-difference-of-flight method for each receiver pair.

In some aspects, these images still contain imaging artifacts. The resulting images are then stacked together to generate a more specific image of the drill bit position by eliminating imaging artifacts. The process of using cross-correlation and travel time differences to locate the drill bit would be inaccurate and nearly impossible if a large number of receivers were not used. In the theoretical demonstration above, the bit position is determined in the vertical cross-sectional 2D plane, since the receiver is assumed to be on a 2D line at the surface. The use of 3D acquisition geometry expands the possibilities to position the drill bit in three dimensions.

Similarly, the use of a large number of receivers allows imaging and prediction to be performed before the drill bit. The large number of receivers may 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 bulk waves are typically generated by tube waves in the wellbore caused by drill string motion in the wellbore. Such bulk waves are revealed from low signal-to-noise ratio (S/N) field data using conventional passive seismic imaging methods.

Yet another possible application achieved by using a large number of receivers is seismic logging while drilling. Another possible application achieved by using a large number of receivers placed on the earth's surface around the wellhead is to record a reverse Vertical Seismic Profile (VSP). In a conventional VSP setup, an active seismic source is used to generate seismic signals at different locations at the surface while a set of receivers are lowered into the borehole at different depth levels to record seismic reflections around the borehole. On the other hand, a reverse VSP would use the drill bit as a passive source and the surface receiver as a detector. The number of receivers suggested in SWD recordings exceeds the number of receivers in conventional VSPs, which do not exceed 100 receivers at a time. This allows better recording and detection of seismic signals in noisy environments.

VSP-while-drilling (VSP-WD) is an emerging technology that can reduce drilling risks at lower cost. However, because VSP-WD uses active seismic sources at the surface and receivers in the borehole, drilling operations are slowed and it is difficult to interpret the collected data in real time.

SWD incorporates seismic technology to lower the drill string into the borehole simultaneously during active drilling, during motoring, and while connecting drill pipes. There are two SWD techniques. The first SWD technique is bit SWD, which records the seismic noise generated by the bit actively drilling the well on surface seismic sensors. The second SWD technique is VSP-WD, which records seismic signals generated by seismic receivers in the borehole and surface seismic sources. In both techniques, the number of receivers is limited to a maximum of 100 receivers, and active sources are used on the surface. This in turn results in data being recorded at a lower signal-to-noise ratio and additional time delays in drilling operations due to the intervening nature of these techniques.

In contrast, the present disclosure describes a SWD system in which a large number of receivers (e.g., much greater than 100) with infinite geometry setting 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 a SWD field experiment using a fixed array geometry consisting of one thousand receiver points with a substantially circular shape (e.g., as shown in fig. 17). In this embodiment (and as a field experiment), the well location is 2.6 km from the center of the receiver distribution. Historically, roller cone drill bits have been considered a good passive source of SWD because roller cone drill bits naturally emit noise when breaking rock. However, most drilling operations today use Polycrystalline Diamond Cutter (PDC) bits that shear rock. PDC bits are generally quieter than roller cone bits and are a challenging passive source for surface receivers. To this end, other mechanisms of downhole sources resulting from drill string movement were explored. To locate the seismic source recorded by the geophone, the following passive seismic imaging conditions were used:

I(x)＝∑_tu²(x, t) formula (2)

Where I (x) is the imaging condition at the receiver position (x) and u (x, t) is the receiver wavefield reconstructed by the formula:

wherein D (x)_rω) is the receiver position x_rThe Fourier transformed recorded data of (A) is complex conjugate (G (x)_rX, ω) is a frequency domain green's function. The green's function may approximate the wave equation using finite difference or other numerical methods (e.g., ray-based methods).

The reconstructed wavefield is calculated using equation (3), making it easier to observe seismic waves from the subsurface sources. After the source is located using equation (2), the location of the source is shallower than the true bit depth. However, the position of the source coincides with the position where the speed contrast is maximum. Thus, the received bulk waves come from a secondary source that is converted from tube waves in the borehole. Wave mode conversion occurs at the location of a large velocity contrast exit, or at some discontinuity or density anomaly (e.g., perforations, drill string locks, packers) in the casing or borehole formation. Tube waves in the borehole, on the other hand, are related to movement of the drill string, vibration of the drill bit, and other drilling activities.

By source position x_sAs reference image point, the time of day can be determinedThe m-sequence u (x)_sT) and may apply a time-frequency transform to the time sequence. Once compared to the drilling activity, the time series is determined to be consistent with the drilling activity. By analysis of the reconstructed wavefield at the source position, source imaging and time series, it can be concluded that the recorded seismic waves (mainly bulk waves generated by tube waves) appear to be useful for SWD.

For the verification process of different acquisition geometries, a focused beam approach may be used. The method utilizes migration as a dual focusing process, where the source and receiver fields can be focused separately for a given velocity model. This, in turn, reveals the amplitude accuracy, offset and azimuth coverage, and spatial resolution required for a particular field geometry. This dual focusing approach can be done separately for each specific frequency and each target diffraction point at a given position. In some aspects, the velocity model is the same depth as used for drill bit imaging, and the target point is assumed to be the projection of the wellhead to the target horizon or target depth. In certain 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 such analysis before modifications are made to different target depths. The results of this analysis, obtained in real time, allow the evaluation of current seismic geometries in terms of resolution and amplitude coverage, and the proposition of new acquisition geometries based on varying source depths.

Fig. 31 shows a graph 3100 of field test acquisition geometry 3108 and well location 3106. As previously described, initial field experiments were conducted to record passive seismic while drilling using a fixed geometry consisting of one thousand receiver points having a generally circular shape as shown in fig. 31. In this experiment, the well location was 2.6 kilometers from the center of the receiver in the particular geometry.

FIG. 32 shows a graph 3200 of raw recorded passive seismic data without any preprocessing applied to the field experiment. Graph 3200 includes an x-axis that describes the trajectory of the originally recorded data and a y-axis that describes the time (in seconds) of the original data. Graph 3200 of FIG. 32 shows the raw recorded passive seismic data for 12 seconds without any pre-processing applied.

FIG. 33 shows graphs (a, b, and c) of the reconstructed wavefield at different times for the raw recorded data of FIG. 33. In FIG. 33, sections (a), (b), and (c) show three different time snapshots of seismic waves recorded using the field passive seismic device in FIG. 32. As shown, part (a) shows the wavefield at time (T); (b) the wavefield at T +0.04 seconds is partially shown; (c) the wavefield is shown in part at T +0.08 seconds. From these three reconstructed wavefield snapshots, the seismic sensors that propagated the seismic waves from the borehole to the surface can be inferred.

34A-34B show images of secondary energy sources and graphs of bit position and stacking velocity profiles. For example, fig. 34A shows an image of the secondary energy source and bit position. Here, point 3402 represents the image around the secondary source, point 3404 represents the true position of the drill bit, and point 3406 represents the well path. Fig. 34A shows a stacking speed profile. Here, the horizontal dotted line indicates the pseudo depth (time) position of the secondary energy source.

FIG. 35 illustrates a time-frequency analysis diagram of recorded and processed passive seismic data. For example, a time-frequency analysis is performed on the recorded passive data. The data spans a three hour recording period and shows excellent correlation between time-frequency response and drilling activity. In certain aspects, for example, seismic while drilling techniques may be used to extract a time series of source locations and predict rock properties in real time by analyzing corrections between the time series and the rock properties. For example, the seismic logging while drilling workflow may include the following sequences (in the order described or otherwise). First, a move-out correction is applied to the observation data, for example, by applying a source-receiver distance-dependent time shift to each trajectory. Second, the corrected (or time-shifted) trajectories can be stacked into a single trajectory. In this example, the amplitude values of all traces for each time step may be summed and normalized to provide one hypertrack. Third, time-frequency analysis methods (e.g., short-time Fourier transforms) can be applied to the stacked traces. Time series within each short time window can be decomposed into different frequency components by applying a time-frequency analysis method. Fourth, rock properties can be predicted from the time-spectrum, for example, by applying machine learning techniques such as neural network analysis. The main components required to predict an attribute may include data obtained earlier under similar conditions. Fifth, the drilling program may be adjusted in real time using information including predictive knowledge of the geological formations (e.g., rock hardness, pore pressure, and fractures) around and ahead of the drill bit. Adjustments made to the drilling program may result in optimizations related to drilling time and costs.

Certain features described may be implemented in digital electronic circuitry, or in computer hardware, firmware, software, or in combinations of them. The apparatus may be implemented in a computer program product tangibly embodied in an information carrier, e.g., in a machine-readable storage device for execution by a programmable processor; and method steps can be performed by a programmable processor executing a program of instructions to perform functions of the described implementations by operating on input data and generating output. The described features can be implemented in one or more computer programs that are executable on a programmable system including at least one programmable processor coupled to receive data and instructions from, and to transmit data and instructions to, a data storage system, at least one input device, and at least one output device. A computer program is a set of instructions that can be used, directly or indirectly, in a computer to perform a certain activity or bring about a certain result. The computer program may be written in any form of programming language, including: a compiled or interpreted language, and the computer program can 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.

Suitable processors for the execution of a program of instructions include, by way of example, both general and special purpose microprocessors, and the sole processor or one of multiple processors of any kind of computer. Generally, a 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, or be operatively coupled to communicate with, one or more mass storage devices for storing data files; such devices include magnetic disks (such as internal hard disks and removable disks); magneto-optical disks; and an optical disc. Storage devices suitable for tangibly embodying computer program instructions and data include all forms of non-volatile memory, including by way of example semiconductor memory devices, such as erasable programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM), Solid State Disks (SSD), and flash memory devices; magnetic disks (such as internal hard disks and removable disks); magneto-optical disks; and CD ROM and DVD-ROM disks. The processor and memory may be supplemented by, or incorporated in, ASICs (application-specific integrated circuits).

To provide for interaction with a user, these features can be implemented on a computer having a display device, e.g., a monitor 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 a pointing device, e.g., a mouse or a trackball, by which the user can provide input to the computer. Additionally, such activities may be accomplished via a touch screen flat panel display and other suitable mechanisms.

The features can be implemented in a control system that includes a back-end component (e.g., as a data server), or that includes a middleware component (e.g., an application server or an Internet server), or that includes a front-end component (e.g., a client computer having a graphical user interface or an Internet browser), or any combination of the preceding. 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 a Local Area Network (LAN), a Wide Area Network (WAN), a peer-to-peer network (with ad hoc or static members), a grid computing infrastructure, and the internet.

While this specification contains many specific implementation details, these should not be construed as limitations on the scope that may be claimed, but rather as descriptions of features specific to particular examples. Certain features that are described in this specification in the context of separate embodiments can also be implemented in combination in a single embodiment. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations separately or in suitable subcombinations. Furthermore, although features may be described as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can in some cases be excised from the combination, and the claimed combination may be directed to a subcombination or variation of a subcombination.

Similarly, while operations are depicted in the drawings in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed, to achieve desirable results. In some scenarios, multitasking and parallel processing may be advantageous. Moreover, the separation of various system components in the described implementations 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 in a single software product or packaged into multiple software products.

A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure. For example, the described example operations, methods, or processes may include more steps or fewer steps than those described. Further, the steps in such example operations, methods, or processes may be performed in an order different than that described or illustrated in the figures. Accordingly, other implementations are within the scope of the following claims.