• 专利附录
  • 专利说明
  • 权利要求
  • 类似技术
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    • 专利摘要:
    The present disclosure relates to systems and methods for correcting deviation and dispersion effects on deviated well logging measurements, by implementing: a) defining Thomsen parameters for each depth of measurement of the logging using least one or more of the components of the formation, one or more of the predetermined constraints of the formation, one or more predetermined thresholds of the formation type and Thomsen maximum parameters for the formation; b) the calculation of the dispersion, VSH90, VSH0, VP0, VP90, VSVθ, and the new Thomsen parameters by correcting the DTS and the DTC for the deviation and the dispersion using the parameters of Thomsen, a nonlinear solver and a computer processor; and c) the graphical representation of the actual log measurements and calculated dispersion, VSH90, VSH0, VP0, VP90, VSVθ, of the new Thomsen parameters on respective separate graphs.
    公开号:FR3038338A1
    申请号:FR1654855
    申请日:2016-05-30
    公开日:2017-01-06
    发明作者:Mehdi Eftekhari Far；John Andrew Quirein；Chris Marland；Natasa Mekic
    申请人:Halliburton Energy Services Inc；
    IPC主号:
    专利说明:

    FIELD OF DISCLOSURE
    The present disclosure generally relates to systems and methods for correcting deviation and dispersion effects on acoustic logging measurements of deviated wells in stratified formations. More particularly, the present disclosure relates to the simultaneous correction of deviation and scattering effects on acoustic well log measurements deviated in stratified formations and the validation of corrected acoustic log measurements using rock physics correlation graphs.
    CONTEXT
    In stratified rocks such as shale, compression and shear waves propagate at different velocities in different directions. Therefore, when wells are drilled at an angle other than 0 or 90 ° from lamination or bed (ie deviated wells), the velocities measured along the wells are different velocities parallel or perpendicular to the bed or stratification. In Figure 1, a deviated well dug at an angle Θ through a laminate medium is illustrated. What is really measured in this illustration is the speed along the angle (VO). The same situation exists when a vertical or horizontal well is dug in a falling layer with stratification. In both cases, the velocity angle (V0) is measured and in order to obtain a vertical velocity (V0) or a horizontal velocity (V90) if the well is almost horizontal, a correction of the deviation or anisotropy is necessary. Since acoustic logging measurements are used in many other applications, eg, geomechanics, hydraulic fracturing, well bore seismology, and wellbore stability, such corrections are crucial.
    [0003] There is a limited number of published techniques for the correction of the deviation; however, such techniques are not often used in the drilling field. But also, such techniques, if used, may require advanced drilling suites such as dipole acoustics compared to monopoly acoustics which is less expensive. And, some of these techniques are interval-based methods, which means that they assume that each interval (lithological layer) has constant anisotropic parameters, which is not the case in real earth. Some of these techniques also assume that a group of speeds is measured rather than the preferred phase speeds. Nevertheless, such techniques do not correct the scattering effects on acoustic logging measurements of deviated wells in stratified formations.
    In order to validate the corrected acoustic log measurements, conventional techniques may require acoustic logging measurements from the vertical and near vertical wells that are close to the locations of the deviated well for which the correction is applied. Even assuming that acoustic log measurements from nearby wells are available, the validation process for acoustic logging measurements can be expensive. Conventional techniques are thus not often practiced in the field of drilling and mechanical properties that are interpreted from acoustic logging measurements can be imprecise.
    BRIEF DESCRIPTION OF THE FIGURES
    The present disclosure is described below with reference to the accompanying drawings in which similar elements are referenced with like numbers, and among which: Figure 1 illustrates a deflected well in a laminate medium.
    FIG. 2A is a graph illustrating an example of a graph of a Thomsen parameter (Epsilon) as a function of the sum of the volume of the clay and the kerogen (%).
    FIG. 2B is a graph illustrating an example of a graph of a Thomsen (Gamma) parameter as a function of the sum of the volume of the clay and the kerogen (%).
    FIG. 3A is a graph illustrating an exemplary graph of the original acoustic log measurements of: the acoustic compression velocity (Vp) divided by the acoustic shear velocity (Vs) as a function of the compression slowness (DTC) ).
    Fig. 3B is a graph illustrating an example of a corrected acoustic log measurement graph from FIG. 3A.
    Figure 4 is a flowchart illustrating an embodiment of a method for implementing the present disclosure during optimization for Vp and Vs simultaneously.
    FIG. 5 is a flowchart illustrating an embodiment of a method for implementing the present disclosure during optimization for Vsh and using Vsh to optimize for Vp and Vsv. [0013] FIG. simulated acoustic logs for deviation and for comparing real and measured velocity values of properties / parameters with values for the same velocity of properties / parameters in a deviated well which have been corrected according to the method illustrated in FIG. 11.
    FIG. 7 illustrates simulated acoustic logs for deviation and for comparing real and measured velocity values of properties / parameters with values for the same speed of properties / parameters in a deviated well which have been corrected according to FIG. method illustrated in FIG. 11.
    FIG. 8 illustrates simulated acoustic logs for deviation and for comparing real and measured velocity values of properties / parameters with values for the same speed of properties / parameters in a deviated well which have been corrected according to FIG. method illustrated in FIG. 11.
    FIG. 9 illustrates simulated acoustic logs for the deviation and for comparing the real and measured values of the velocity of the properties / parameters with values for the same velocity of the properties / parameters in a deviated well which have been corrected according to FIG. method illustrated in FIG. 11.
    Figure 10 is a flowchart illustrating an embodiment of a computer system for implementing the present disclosure.
    FIGS. 11A-11B show a flowchart illustrating an embodiment of a method for implementing the present disclosure during optimization for Vp and Vs simultaneously or during optimization for Vsh and using Vsh to optimize for Vp and Vsv.
    DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
    The present disclosure overcomes one or more deficiencies in the prior art by providing systems and methods for simultaneous correction of deviation and dispersion effects on acoustic logging measurements of deviated wells in stratified formations and validation of logs. corrected acoustic measurements using correlation graphs of rock physics.
    In one embodiment, the present disclosure includes a method for correcting deviation and dispersion effects on deviated well acoustic log measurements, which comprises: a) defining Thomsen parameters for each depth measuring logging using at least one or more of the formation components, one or more of the predetermined formation constraints, one or more of the predetermined formation type thresholds and the maximum Thomsen parameters for the formation; b) the dispersion calculation, Vsroo, Vsho, Vpo, Vp9o, Vsve, and Thomsen's new parameters by correcting the DTS and the DTC for the deviation and dispersion using the parameters of Thomsen, a non-linear solver and a computer processor; and c) the graphical representation of the actual measurement logs, and the calculated dispersion, Vsh9o, Vsho, Vpo, Vp9o, Vsve, the new Thomsen parameters on respective separate graphs.
    In another embodiment, the present disclosure includes a non-transient program support device that tangibly supports computer-executed instructions for correcting deviation and dispersion effects on well acoustic measurement logging. deviated, the instructions being executable to implement: a) defining Thomsen parameters for each measurement logging depth using at least one or more of the formation components, one or more predetermined training constraints, one or more predetermined thresholds training type and maximum Thomsen parameters for training; b) dispersion calculation, Vsh9o, Vsho, Vpo, Vp9o, Vsve, and new Thomsen parameters by correcting the DTS and DTC for the deviation and dispersion using the Thomsen parameters, and a non-linear solver; and c) the graphical representation of the actual logging and calculated dispersion measurements, Vsh9o, Vsho, Vpo, Vp9o, Vsve, the new Thomsen parameters on respective separate graphs.
    In yet another embodiment, the present disclosure includes a non-transient program support device that tangibly supports computer-executed instructions for correcting deviation and dispersion effects on acoustic logging measurements. deviated wells, the instructions being executable to implement: a) the definition of the Thomsen parameters for each depth of the measurement log using at least one or more of the formation components, one or more of the predetermined constraints of the formation, a or more of the predetermined training type thresholds and the maximum Thomsen parameters for training in which the one or more predetermined training constraints and one or more predetermined training type thresholds are identified for each measurement of real logging; b) the dispersion calculation, Vsroo, Vsho, Vpo, Vp9o, Vsve, and new Thomsen parameters by correcting DTS and DTC for deviation and dispersion using Thomsen parameters, and a non-linear solver ; and c) the graphical representation of the actual logging measurements and the calculated dispersion, Vsroo, Vsho, Vpo, Vp9o, Vsve, of new Thomsen parameters on respective separate graphs.
    In one or more of the aforementioned embodiments, one or more predetermined constraints of the formation and one or more predetermined thresholds of the formation type may be identified for each actual logging measurement.
    One or more of the aforementioned embodiments may also include the graphical representation of one or more predetermined lines of velocity trend and a predetermined line of rock type on each graph.
    In one or more of the above embodiments, one or more components of the formation may be determined by interpreting actual log measurements from one or more wells in the formation.
    In one or more of the aforementioned embodiments, one or more predetermined constraints of the formation and one or more predetermined thresholds of the formation may be identified for each actual logging measurement based on the lithology for each logging measurement and one type of logging measurement.
    In one or more of the aforementioned embodiments, the maximum parameters of Thomsen can be identified for training by interpreting geophysical data from the formation.
    One or more of the aforementioned embodiments may also comprise: d) selecting at least one different interpretation technique and one or more new real logging measurements; and e) repeating the steps a) - d) using the at least one of the different interpretation technique and the one or more real logging measurements until the calculated dispersion, Vsh9o, Vsho, Vpo, Vp9o, Vsve, and the new Thomsen parameters are validated.
    In one or more of the aforementioned embodiments, the validation of the calculated dispersion, Vsroo, Vsho, Vpo, Vp9o, Vsve, and the new parameters of Thomsen can be based on a comparison of each graph.
    In one or more of the aforementioned embodiments, the validation of the calculated dispersion, Vsh9o, Vsho, Vpo, Vp9o, Vsve, and the new parameters of Thomsen can be based on a comparison of the real logging measurements and the dispersion. calculated, Vsh9o, Vsho, Vpo, Vp9o, Vsve, and the new parameters of Thomsen.
    In one or more of the aforementioned embodiments, one or more predetermined lines of velocity trend may comprise a Brie correlation graph line and a Castagna correlation graph line.
    The subject of the present disclosure is described with specificity, however, the description itself is not intended to limit the scope of the disclosure. The object of the present disclosure can therefore be realized in other ways, to include different structures, steps and / or combinations of steps similar to those described herein, in combination with other present or future technologies. Furthermore, even though the term "step" may be used herein to describe various elements of the methods used, the term should not be construed as implying any particular order among or among the various steps described herein, except in the case of explicit limit imposed by the description related to a particular order. While this disclosure may apply to the oil and gas industry, it is not limited to it and may also apply to other industrial sectors (eg, water well drilling) to obtain similar results.
    The methods described herein demonstrate that the effects of dependence on the direction of wave velocities in rocks, call anisotropy or deviation, and the dispersion on acoustic log measurements for deviated wells in stratified formations, during or after drilling (logging while drilling (LWD) or cable) can be corrected simultaneously. The following description of the correction procedure is also illustrated by the methods in FIGS. 4-5, which are consolidated in FIGs. 11A-11B.
    In a stratified medium, which is sometimes called vertically transverse isotropy (VTI), there are a number of wave types that can be measured with acoustic / sonic logs. The most important wave types are Vsh, Vsv (shear wave velocities with horizontal and vertical polarizations, respectively), and Vp (the compression wave velocity). For shear waves, in addition to the correction of the deviation, there are sometimes scattering effects in the LWD measurements which also need to be corrected. Depending on the tools that measure acoustic velocities in rock formations, frequently only one type of shear wave is measured. Thus, the correction procedure disclosed here will work with only one or both shears (Vsh is usually faster than Vsv) · Thus, Vsv can be reconstructed from the Vsh sound logging measurements along the borehole.
    The equations for the compression and shear waves in the VTI medium, which comprise the Thomsen parameters ε, γ and δ, are:
    (1) (2) (3) where Θ represents the angle of wave propagation (the angle between the wellbore and the stratification), d (in equation (1)) is the dispersion, a is the same as Vp (0) and β is the same as Vs (0). The parameters of Thomsen ε, γ and δ are defined in terms of matrix components of hardness Cÿ as shown by the equations (4-6).
    (4) (5) (6)
    The components Cÿ in the medium VTI can be expressed with different wavelengths expressed by the equations (7-9):
    (V) (8) (9) [0036] A nonlinear solver can be used to find a set of optimal values for vertical and horizontal velocities to minimize the difference between the measured VO and the modeled VO obtained with the equations (1 and 3). In other words, the solver disturbs the values of the Thomsen parameters and the velocities Vp (0) and Vs (0) until it finds a minimum in the difference between the modeled and the measured data. In doing so, a number of constraints are imposed using the parameters of Thomsen. The use of Thomsen's parameters is practical because they are dimensionless numbers less than 1, which govern the relationships between velocities in different directions. The constraints are therefore imposed in terms of Thomsen parameters but leaving the speeds as variables. Stratification and anisotropy are common in shale formations. Shale formations tend to have higher gamma ray readings in well logs. Therefore, the constraints for the Thomsen parameters are graduated with gamma ray data. This means that intervals with higher gamma ray values will have larger Thomsen parameters (more anisotropic) and vice versa. The constraints for the Thomsen parameters are graduated by defining the "clean" and "shale" gamma ray readings. Equations (10-12) can be used to scale constraints for Thomsen parameters. Maximum values for Thomsen parameters should be selected based on core measurements or a combination of vertical, horizontal, and 45 ° velocity measurements for the same well or surrounding wells.
    (10) (11) (12) The scaling (ie, constraint definition) of the constraints for Thomsen parameters can be defined more precisely using more relevant parameters such as the volume of the clay, the volume of the shale and / or the kerogen content. FIG. 2A, is a graph illustrating an example graph of a Thomsen parameter (Epsilon) as a function of the sum of the volume of clay and kerogen (%). Figure 2B is a graph illustrating an example of a graph of a Thomsen (Gamma) parameter as a function of the sum of the volume of clay and kerogen (%). Figures 2A-2B thus illustrate the relationships between the anisotropies of the P wave (Epsilon) and the S wave (Gamma) with the volume of clay and kerogen. These parameters require further well log measurements or interpretations such as spectral gamma ray logs or interpreted kerogen volume. Therefore, equations (ΙΟΙ 2) are assumed to be for situations in which gamma ray logging information is available. If additional data is available, however, equations (ΙΟΙ 2) can be modified as shown by equations (13-14):
    where equations (10-12) can be modified as a function of the Thomsen parameters in equations (15):
    More complex nonlinear equations can also be used. A correction is made for each measurement (ie, data point) separately. Which means that there is no calculation of the average of the properties or the obtaining of a representative value for the speeds for the entirety of the interval. The correction is performed for Vp and Vsh first to obtain the vertical (Vsv), horizontal (Vsh) and 45 ° (V45) velocities and thus the Thomsen parameters. Then, using equation (2), Vsv (Θ) can be calculated as if it were measured along a borehole. If Vsv (Θ) is also acquired using modified tools such as a dipole acoustic, the correction must be performed for all 3 types of velocity waves, either simultaneously or separately.
    If a correlation graph, for example, of Vp versus Vs is made, the acoustic logging measurements for certain types of rock must fall by the predefined lines which represent reported trends. Well-known correlation graphs of rock physics (eg, Castagna, Mudrock and Brie) can thus be used to validate the results of speed correction. It should be noted that these correlation graphs can be reconstructed according to the location of the well, in order to obtain a more accurate representation of rock physics in this area. After speed correction, the acoustic logging measurements in the correlation graphs should be shifted close to the predefined lines that represent the reported trends. If, after correction, the acoustic logging measurements are still not consistent with such trends, the ranges (max max, Ymax, omex, GR proper, GRist) can be modified before repeating the correction procedure.
    FIG. 3A is a graph illustrating an example of a graph of the original acoustic log measurements of the compression acoustic velocity (Vp) divided by the acoustic shear velocity (Vs) as a function of the slowness of compression (DTC). ). The original acoustic log measurements from some shales must fall next to a predefined shale line that represents reported shale trends. In Figure 3A, the original acoustic log measurements must fall next to the middle shale line, but this is not the case. Instead, they fall beside a line of Brie and distant from the Castagna line, which represents the reported trends of rock physics. In Figure 3B, a graph illustrates an example of a graph of corrected acoustic log measurements from FIG. 3A. In Figure 3B, the corrected acoustic logging measurements are close to the middle shale line. Figures 3A-3B demonstrate how the rock physics correlation graphs can be used to validate the correction of the velocity deviation. It should be noted that there are no imposed constraints, which are based on Brie or Castagna trend lines during the correction as these will bias the correction results.
    Referring now to Figures 11A-11B, a flowchart illustrates another embodiment of a method 1100 for implementing the present disclosure during optimization for Vp and Vs simultaneously or when optimization for Vsh and using Vsh to optimize Vp and Vsv.
    In step 1102, the formation components (eg, mineralogy, organic carbon, kerogen) are identified by interpreting the logging measurements for one or more wells in the formation using techniques well known in the art. field for training evaluation.
    In step 1104, the predetermined constraints of the formation (eg, logging range ranges) and formation type thresholds (eg, minimum / maximum gamma ray logging reading) are identified for each logging measure of step 1102 based on the lithology for each logging measurement and logging measurement type.
    At step 1105, the Thomsen maximum parameters are determined for the formation by interpreting geophysical data (eg, core data, vertical seismic profiling data, surface seismic data) from the formation using the equations (10-12) or (13-15) and techniques well known in the art for evaluating training.
    In step 1106, the Thomsen parameters for each logging depth of measurement are defined using at least one of the components of the formation identified in step 1102, the predetermined constraints of the formation and the thresholds. of training type identified in step 1104, the maximum Thomsen parameters determined for training at step 1105 and equations (10-12) or (13-15). In equations (10-12), for example, the formation component is the shale and the predetermined constraints of the formation and the formation type thresholds are gamma ray or clay volume measurements.
    In step 1108, the dispersion, Vsroo, Vsho, Vpo, Vp9o, Vsve and the new parameters of Thomsen are calculated by correcting the DTS (Vs) and the DTC (Vp) for the deviation and the dispersion using the Thomsen parameters defined in step 1106 and a nonlinear solver as described herein for correcting Vs and Vp.
    In step 1110, the actual log measurements at step 1102 and the dispersion, Vsh9o, Vsho, Vpo, Vp9o, Vsve and the new Thomsen parameters calculated at step 1108 can be reported on graphs. separate with a Brie correlation graph line, a Castagna correlation graph line and a predetermined rock type line as described with reference to FIGS. 3A-3B.
    In step 1112, the method 1100 determines whether the dispersion, Vsh9o, Vsho, Vpo, Vp9o, Vsve and the new parameters of Thomsen calculated in step 1108 are valid based on a comparison of the graphics of the step 1110 and a separate comparison of the actual logging measurements of step 1102 and the calculated (corrected) logging measurements of step 1108. It can be concluded that any of the comparisons demonstrate that the compared results are within a predetermined margin of error. If the dispersion, Vsh9o, Vsho, Vpo, Vp9o, Vsve and the new Thomsen parameters calculated in step 1108 are valid, then the process 1100 ends. Otherwise, method 1100 proceeds to step 1114.
    In step 1114, at least one of a different interpretation technique of new real logging measurements is selected and the method 1100 returns to step 1102. [0050] By way of example, Published ultrasonic data were used with equations (1-3) to model (simulate) the velocity at the deflection angles shown in the first simulated acoustic log of FIGs. 6-9. Modeled velocities (Vp (theta), Vsv (theta), Vsh (theta)) were used to determine the accuracy of corrected vertical and horizontal velocities. In doing so, an estimate of Thomsen's parameters was assumed. In FIGs. 6-7, a random noise was added to the actual values of the Thomsen parameters and the noisy values were used as the actual acoustic log data. In FIGs. 8-9, the same type of test for data from four different shale formations was used. The Thomsen parameters were averaged for each shale formation and averaged values were used as actual acoustic log data. The noisy values for the Thomsen parameter γ are assumed values illustrated by dotted curves and dotted curves illustrate the measured values. Solid curves illustrate calculated (corrected) values. For velocities, the dashed curves illustrate the actual and measured values and the solid curves illustrate the calculated (corrected) values.
    The present disclosure may be implemented through a computer executable instruction program, such as program modules, generally referred to as software applications or application programs executed by a computer. The software may include, for example, subroutines, programs, objects, components, and data structures that perform particular tasks or implement particular abstract data types. The software forms an interface to allow a computer to react based on an input source. DecisionSpace®, which is a commercial software application marketed by Landmark Graphics Corporation, can be used as an interface application to implement the present disclosure. The software may also cooperate with other code segments to initiate a variety of tasks in response to the received data in association with the source of the received data. The software can be stored and / or transported on a variety of memories such as a CD-ROM, a magnetic disk, a bubble memory and a semiconductor memory (eg various types of RAM or ROM). In addition, the software and its results can be transmitted on a variety of carrier media such as an optical fiber, a wire and / or across any network of a variety of networks, such as the Internet.
    In addition, those skilled in the art will appreciate that this disclosure can be practiced with a variety of computer system configurations, including portable devices, multiprocessor systems, and user-programmable or microprocessor-based electronic devices. minicomputers, mainframes, etc. Any number of computer systems and computer networks are acceptable for use with the present disclosure. Disclosure may be practiced in distributed computing environments in which tasks are performed by remote controlled devices that are connected through a telecommunication network. In a distributed computing environment, the program modules can be on both a local and remote computer storage medium, including memory storage devices. The present disclosure may therefore be implemented in connection with various hardware, software or a combination thereof in a computer system or other processing system.
    [0053] Referring now to FIG. 10, a flowchart illustrates an embodiment of a system for implementing the present disclosure in a computer. The system includes a computer unit, sometimes called a computer system, which contains a memory, application programs, a client interface, a video interface and a central unit. The computer unit represents only one example of an appropriate computing environment, and is not intended to suggest any limitation with respect to the scope of use or the functionality of the disclosure.
    The memory primarily stores the application programs, which may also be described as program modules containing computer executable instructions, executed by the computer unit to implement the present disclosure described herein and illustrated in FIGS. -9, 11A-11B. Thus, the memory comprises an acoustic log correction module, which activates the steps 1105-1114 described with reference to FIGS. 11A-11B. The acoustic logging correction module may incorporate features from the other application programs illustrated in FIG. In particular, DecisionSpace® software can be used as an interface application to perform steps 1102-1104 in FIGs. 11A-11B. Although DecisionSpace® can be used as an interface application, other interface applications can be used instead, or the acoustic logging correction module can be used as a stand-alone application.
    Although the computer unit appears to have a generalized memory, the computer unit typically includes a number of media readable by the computer. By way of example, and without limitation, computer readable media may include computer recording media and telecommunication media. The computer system memory may include computer storage media in the form of volatile and / or nonvolatile memory, such as a read-only memory (ROM) or random access memory (RAM). A basic input / output system (BIOS) containing the basic routines for transferring information between the elements in the computer unit, for example during startup, is usually stored in read-only memory. The RAM generally contains data and / or program modules that are immediately accessible to and / or executed by a central processing unit. By way of example, and without limitation, the computer unit includes an operating system, application programs, other program modules, and program data.
    The components illustrated in the memory may also be included in the removable / non-removable, volatile / non-volatile computer storage medium, or they may be implemented in the computer unit through an application program interface (" API ") or a computer cloud, which may be on a separate computer unit connected through a computer system or network. By way of example only, a hard disk can be read from a non-volatile, non-removable magnetic medium or recorded therefrom, a non-volatile, removable magnetic disk, and an optical hard disk can be read from, or recorded from, a removable, nonvolatile optical disk, such as a CD-ROM or other optical medium. Other removable / non-removable, volatile / non-volatile computer storage media that may be used in an exemplary operating environment may include, without limitation, magnetic tape cassettes, flash memory cards, digital versatile discs, digital video tapes, semiconductor RAMs, semiconductor ROMs, etc. The disks and their associated associated computer storage media permit the storage of computer readable instructions, data structures, program modules and other data for the computer unit.
    A customer can enter commands and information in the computer unit through the client interface, which can correspond to input devices such as a keyboard and a pointing device, generally called a mouse, a ball command or touchpad. The input devices may include a microphone, a joystick, a satellite dish, a scanner, and so on. These devices and other input devices are often connected to the central unit through the client interface which is coupled to a bus system, but they can be connected by other interfaces and bus structures, such as a parallel port or a USB bus.
    A screen or other type of display device may be connected to the system bus through an interface, such as a video interface. A graphical user interface (GUI) can also be used with the video interface to receive instructions from the client interface and to transmit these instructions to the plant unit. In addition to the display, the computers may also include other peripheral output devices such as speakers and a printer, which may be connected through a peripheral output interface.
    [0059] Even though several other internal components of the computer unit are not illustrated, it will be understood by ordinary experts that such components and their interconnection are well known.
    Although the present disclosure has been described in connection with the presently preferred embodiments, it will be understood by those skilled in the art that these are not intended to limit disclosure to these embodiments. It is therefore contemplated that various other embodiments and modifications may be added to the described embodiments without departing from the scope of the disclosure as defined by the appended claims and the equivalents thereof.
    权利要求:
    Claims (11)
    [1" id="c-fr-0001]
    A method for correcting deviation and scattering effects on deviated well acoustic log measurements, characterized in that the method comprises: a) defining the Thomsen parameters for each log depth of the log using at least one or more of the formation components, one or more predetermined training constraints, one or more predetermined thresholds of the formation type and Thomsen maximum parameters for the formation; b) the computation of the dispersion, Vsh9o, Vsho, Vpo, Vp9o, Vsve, and Thomsen's new parameters by correcting the DTS and the DTC for the deviation and dispersion using the parameters of Thomsen, a nonlinear solver and a computer processor; and c) the graphical representation of the actual log measurements and calculated dispersion, Vsh9o, Vsho, Vpo, Vp9o, Vsve, of the new Thomsen parameters on respective separate graphs.
    [2" id="c-fr-0002]
    The method of claim 1, further comprising graphing one or more predetermined lines of velocity trend and a predetermined rock type line on each graph.
    [3" id="c-fr-0003]
    The method of claim 2, wherein the one or more predetermined lines of velocity trend comprises a Brie correlation graph line and a Castagna correlation graph line.
    [4" id="c-fr-0004]
    The method of any one of claims 1 to 3, wherein the one or more components of the formation are determined by interpreting the actual logging measurements from one or more wells in the formation.
    [5" id="c-fr-0005]
    The method of claim 4, wherein the one or more predetermined constraints of the formation and the one or more predetermined thresholds of the formation are identified for each actual logging measurement based on the lithology for each logging measurement. and a type of logging measurement.
    [6" id="c-fr-0006]
    The method of claim 5, wherein Thomsen maximum parameters are determined for training by interpreting geophysical data from the formation.
    [7" id="c-fr-0007]
    The method of any one of claims 1 to 6, further comprising: d) selecting at least one different interpretation technique and one or more new real logging measurements; and e) repeating the steps a) - d) using the at least one of the different interpretation technique and the one or more real logging measurements until the calculated dispersion, Vsh9o, Vsho, Vpo, Vp9o, Vsve, and the new Thomsen parameters are validated.
    [8" id="c-fr-0008]
    The method of claim 7, wherein the validation of the calculated dispersion, Vsroo, Vsho, Vpo, Vp9o, Vsve, and the new Thomsen parameters is based on a comparison of each graph.
    [9" id="c-fr-0009]
    9. The method of claim 8, wherein the validation of the calculated dispersion, Vsh9o, Vsho, Vpo, Vp9o, Vsve, and the new parameters of Thomsen is based on a comparison of the real logging measurements and the calculated dispersion, Vsh9o, Vsho, Vpo, Vp9o, Vsve, and the new Thomsen settings.
    [10" id="c-fr-0010]
    The method of any one of claims 1 to 9, wherein the one or more predetermined constraints of the formation and the one or more predetermined thresholds of the formation type are identified for each actual logging measurement.
    [11" id="c-fr-0011]
    A non-transient program support device that tangibly supports computer-executable instructions for correcting deviation and scattering effects on deviated well acoustic log measurements, characterized in that the instructions are executable to implement a process according to any one of claims 1 to 10.
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    同族专利:
    公开号 | 公开日
    MX2017015209A|2018-04-13|
    GB2554597A|2018-04-04|
    US20180210103A1|2018-07-26|
    GB201719286D0|2018-01-03|
    WO2017003517A1|2017-01-05|
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    法律状态:
    2017-04-12| PLFP| Fee payment|Year of fee payment: 2 |
    2018-04-25| PLFP| Fee payment|Year of fee payment: 3 |
    2020-02-14| ST| Notification of lapse|Effective date: 20200108 |
    优先权:
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    US201562186975P| true| 2015-06-30|2015-06-30|
    PCT/US2016/015270|WO2017003517A1|2015-06-30|2016-01-28|Correcting the effects of deviation and dispersion on sonic log measurements of deviated wells in laminated formations|
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