determination method and device configured to estimate a distance to an interface in a terrain forma

专利摘要:
TRAINING STRUCTURE IMAGE FORMATION IN FRONT OF THE DRILLING DRILL. The present invention relates to apparatus and methods for the acoustic profiling of the well below. The tool can be used to generate a guided well hole wave that propagates into the formation as a body wave, reflects from an interface, and is converted back to a guided well hole wave. The guided borehole waves resulting from the reflection of the body wave are used to form a reflector image. Methods may include processing acoustic profiling signals including: wave field separation, autocorrelation of wave field components, filtration using a dip filter, and estimating a distance to the reflective interface
公开号:BR112013004287B1
申请号:R112013004287-7
申请日:2011-08-17
公开日:2020-10-27
发明作者:Theodorus W. Geerits；Thomas Bohlen；Olaf Hellwig
申请人:Baker Hughes Incorporated；
IPC主号:

专利说明:

DESCRIPTION FIELD
[0001] The present invention relates to a profiling apparatus during drilling and, more particularly, to an acoustic profiling apparatus during drilling and the generation and use of guided waves to see in front of the drill bit. BACKGROUND OF THE DESCRIPTION
[0002] For obtaining hydrocarbons, such as oil and gas, coated wells or well holes are drilled into the soil through subsurface formations carrying hydrocarbons. Today, a lot of current drilling activity involves not only vertical wells, but also horizontal well drilling. In drilling, information from the well itself must be obtained. Although seismic data has provided information on the area to be drilled and the approximate depth of a production area, seismic information cannot be totally reliable at great depths. To support the data, information is obtained during drilling through profiling devices during drilling or measuring during profiling (MWD). Profiling during drilling (LWD) or MWD are procedures that have been in use for many years. This procedure is preferred by drillers because it can be performed without having to stop drilling to profile a hole. This is primarily due to the fact that profiling an unfinished hole, prior to laying the coating, if necessary, can lead to undermining, damaging the drilling work that has already been done. This can stop the completion of the well and delay production. In addition, this information can be useful while the well is being drilled to make changes in direction immediately.
[0003] An important part of drilling operations is the attempt to control the direction of drilling in a desired direction. This requires the ability to "see ahead" of the drill bit. There is a need for a method of processing acoustic data to see in front of the drill bit. This description satisfies this need. DESCRIPTION SUMMARY
[0004] A description mode is a method of determining a distance to an interface in a terrain formation. The method includes: transporting a profiling instrument to a well bore; the activation of at least one transmitter in the profiling instrument to produce a guided acoustic wave which propagates down to the bottom of the borehole and produces an acoustic wave in the formation of terrain; the use of at least one receiver in the profiling instrument to: receive a first signal in response to the guided downward propagation acoustic wave, and receive a second signal in response to an upward guided acoustic wave resulting from the reflection of the acoustic wave training in an interface there; filtering the first signal and the second signal using a dip filter; and estimating from the first filtered signal and the second filtered signal from a distance to the interface.
[0005] Another modality of the description is a device configured to estimate a distance to an interface in a terrain formation. The apparatus includes: a profiling instrument configured to be transported to a well hole; at least one transmitter in the profiling instrument configured to produce a guided acoustic wave which propagates down to the bottom of the borehole and produces an acoustic wave in the formation of terrain; at least one receiver on the profiling instrument configured to: receive a first signal in response to the guided downward propagation acoustic wave, and receive a second signal in response to an upward guided acoustic wave resulting from the reflection of the acoustic wave in the background well bore and formation at an interface there; and at least one processor configured to: filter the first signal and the second signal using a dip filter, and estimate from the first signal and the second signal from a distance from the bottom of the borehole to the interface.
[0006] Another modality of the description is a medium product that can be read on a non-transitory computer that has instructions stored on it that, when read by a processor, allow the processor to execute a method. The method includes: filtering a first signal and a second signal using a dip filter and estimating a distance from the bottom of a well hole to an interface in a terrain formation, where: the first signal is produced by a receiver in a profiling instrument carried in a well bore in response to a guided acoustic wave propagating down the well bore; and the second signal is produced by the receiver in response to a guided seismic wave of upward propagation in the borehole, the upward propagation wave resulting from the reflection of an acoustic wave produced at the bottom of the borehole by the guided acoustic wave of propagation down and reflected in the interface. BRIEF DESCRIPTION OF THE DRAWINGS
[0007] For a detailed understanding of the present description, a reference should be made to the following detailed description of the modalities, taken in conjunction with the associated drawings, in which equal elements were given equal numbers, in which:
[0008] Figure 1 is an illustration of a downhole assembly (BHA) used in a downhole from a tubular drilling element that includes the apparatus according to an embodiment of the present description;
[0009] Figure 2 is an illustration of an example configuration of transmitters and receivers in the present description;
[00010] Figure 3 schematically illustrates the signals that are generated and used according to one embodiment of the present description to be seen in front of the drill bit;
[00011] Figure 4 is a flow chart that illustrates some of the physical methods and processes according to one embodiment of the present description;
[00012] Figure 5 illustrates the course paths of the different types of waves involved in a modality of the present description;
[00013] Figures 6A to 6C illustrate the model used to evaluate the method of the present description;
[00014] Figures 7A to 7F illustrate snapshots at selected time points of the radial particle vehicle component for the model of Figure 6;
[00015] Figures 8A to 8B show snapshots of the wave field (particle velocity component r): conversion of the S wave (TSS) into a guided borehole wave (TSST);
[00016] Figure 9 shows a modeled seismogram (component r of displayed particle speed) covering receptors along the well bore and ahead of it with a dipole source, 5000 Hz: conversion of a flexion wave (T) into an S (RS) wave at the wellbore z = 5 m; reflection of the S wave in a z = 15 layer interface, conversion of the reflected S wave (TSS) into a bending wave (TSST) at the bottom of a borehole;
[00017] Figure 10 shows the signal energy of converted waves;
[00018] Figure 11 shows the normalized azimuth energy of T-S converted waves;
[00019] Figure 12A shows seismograms with traces recorded between the source position (S) and the conversion point (C), before the execution of a dispersion correction and reduction of stroke time; the TSST wave has the image formed in the course time tss, which corresponds to the distance between the conversion point and the reflector;
[00020] Figure 12B shows seismograms after carrying out a dispersion correction;
[00021] Figure 13 illustrates how the cp dip of a flat reflector and its s'- system along the geometric axis of the borehole can be determined;
[00022] Figure 14 is a flow chart of a method for processing data according to an embodiment of the present description;
[00023] Figure 15A shows trigger accumulation data with the well hole bottom 5 m away from the reflector, before an autocorrelation;
[00024] Figure 15B shows trigger accumulation data after an autocorrelation. The TSST signal is not visible. Its theoretical arrival time is indicated by a yellow dashed line. A wave field separation in waves going UP and DOWN was not applied to the synthetic data. In contrast to real data, the model contains only one reflector. There are no reflectors above the source position on the model. For this reason, autocorrelation can be applied to the total wave field.
[00025] Figure 16 shows autocorrelated trigger accumulation data after applying a dip and stacking filter;
[00026] Figure 17A shows autocorrelated common receiver (CRG) accumulation data before applying a dip filtration;
[00027] Figure 17B shows autocorrelated common receiver (CRG) accumulation data after applying a dip filtration; the TSST signal becomes visible after filtration;
[00028] Figure 18A shows accumulation data from common autocorrelated receiver with filtered dip;
[00029] Figure 18B shows the slowness - time - coherence of the data in Figure 18A.
[00030] Figure 19A shows the CRG data filtered as an entry for migration
[00031] Figure 19B is the result of migration with conventional phase shift;
[00032] Figure 19C shows the weighting function obtained from all five features of the CRG; and
[00033] Figure 19D shows the results of migration with weighted phase shift. DETAILED DESCRIPTION
[00034] The present description generally refers to a profiling device during drilling. More specifically, the present description is related to the processing of acoustic profiling data. The present description is subject to modalities in different ways. They are shown in the drawings and will be described here in detail specific modalities of the present description, with the understanding that the present description is to be considered an example of the principles of the description, and it is not intended to limit the description to that illustrated and described here. Instead, as will be evident, the teachings of the present description can be used for a variety of well tools and at all stages of well construction and production. Therefore, the modalities set out below are merely illustrative of the applications of this description.
[00035] Figure 1 illustrates a schematic diagram of a MWD drilling system 10 with a drilling column 20 carrying a drilling assembly 90 (also referred to as the downhole assembly or “BHA”) carried in a “borehole”. coated well ”or a“ well hole ”26 for drilling the coated well hole. The drilling system 10 includes a conventional tower 11 erected on a floor 12 which supports a rotary table 14 which is rotated by a primary mover, such as an electric motor (not shown) at a desired speed of rotation. Drill column 20 includes a pipe, such as a drill pipe 22 or flexible pipe extending downwardly from the surface to well hole 26. Drill column 20 is pushed into well hole 26 when a drill pipe 22 is used as the pipe. For flexible pipe applications, a pipe injector (not shown) is used to move the pipe from its source, such as a spool (not shown), to well hole 26. Drill bit 50 affixed to the end of the drill string 20 breaks the geological formations when it is rotated to drill the borehole 26. If a drill tube 22 is used, the drill string 20 will be coupled to a drill string 30 through a joint Kelly 21, a swivel 28 and a line 20 through a pulley 23. During drilling operations, the drilling guide 30 is operated to control the weight on the bit, a parameter that affects the penetration rate. The operation of the drill bit is well known in the art and thus is not described in detail here.
[00036] During drilling operations, a drilling fluid matching 31 from a mud well (source) 32 is circulated under pressure through a channel in the drilling column 20 by a mud pump 34. The drilling fluid passes from the mud pump 34 to the drilling column 20 through a spring damper 36, a fluid line 38 and the Kelly joint 21. The drilling fluid 31 is discharged into the wellbore bottom 51 through openings in the drill bit 50. The drilling fluid 31 circulates up well through the annular space 27 between the drill column 20 and the well hole 26 and returns to the mud well 32 via a return line 35. The drilling fluid acts to lubricate the drill bit 50 and to carry cuts or splinters from a well hole away from the drill bit 50. An S1 sensor preferably positioned on line 38 provides information on the flow rate of the fluid. A surface torque sensor S2 and a sensor S3 associated with the drill string 20, respectively, provide information about the torque and rotation speed of the drill string. In addition, a sensor (not shown) associated with line 29 is used to provide the hook load of the drill string 20.
[00037] One rotation of the drill pipe 22 rotates the drill bit 50. Also, a well motor below 55 (mud motor) can be arranged in the drill assembly 90 for rotation of the drill bit 50 and the drill pipe 22 is usually rotated to supplement rotation power, if required, and to effect changes in the direction of drilling.
[00038] In the embodiment of Figure 1, the mud motor 55 is coupled to the drill bit 50 through a drive shaft (not shown) arranged in a bearing assembly 57. The mud engine 55 rotates the drill bit 50 when the drilling fluid 31 passes through the mud motor 55 under pressure. The bearing assembly 57 supports the radial and axial forces of the drill bit 50. A stabilizer 58 coupled to the bearing assembly 57 acts as a centralizer for the lower portion of the mud motor assembly.
[00039] A drill sensor module 59 is positioned close to drill bit 50. The drill sensor module 59 can contain sensors, circuits and processing software and algorithms related to dynamic drilling parameters. These parameters can include drill jump, grip - slip of the drill set, backward rotation, torque, shocks, bore pressure and annular space, acceleration measurements and other measurements of the drill bit condition. A suitable sub telemetry or communication 72 using, for example, two-way telemetry, is also provided as illustrated in drilling set 90. The drilling sensor module 59 processes the sensor information and transmits it to the surface control 40 through the telemetry system 72.
[00040] Communication sub 72, power unit 78 and NMR tool (not shown) are all connected in tandem with drill column 20. Flexible subs, for example, are used in the MWD 77 tool connection in drill set 90. These subs and tools form a downhole drill set 90 between drill column 20 and drill bit 50. Drill set 90 makes several measurements, including pulsed nuclear magnetic resonance measurements , while well hole 26 is being drilled. Communication sub 72 obtains the signals and measurements and transfers the signals, using two-way telemetry, for example, to be processed on the surface. Alternatively, the signals can be processed using a downhole processor in drilling set 90.
[00041] The surface control unit or processor 40 also receives signals from other sensors and well devices below, signals from sensors S1 to S3 and from other sensors used in system 10, and processes these signals according to programmed instructions provided for the surface control unit 40. The surface control unit 40 displays the desired drilling parameters and another bottom surface on a viewfinder / monitor 42 used by an operator to control drilling operations. The surface control unit 40 preferably includes a computer or microprocessor-based processing system, a memory for storing programs or models and data, a recorder for recording data, and other peripherals. The control unit 40 is preferably adapted to activate alarms 44, when certain unsafe or undesirable operating conditions occur. An acoustic profiling tool 100 (discussed below) can be positioned in a suitable location, as shown.
[00042] Turning now to Figure 2, an example tool 100 using the method of the present description is illustrated. As would be known to those skilled in the art, an acoustic well source below (or receiver) has a finite length. The source can consist of several segments stacked in the axial direction of the tool. This can be referred to as a transmitter set. In a description mode, the elements are piezoelectric transducers.
[00043] A first arrangement 221 to ... 221 n of receivers and a second arrangement 261 to ... 261 n of symmetrically arranged receivers around an arrangement 241 to ... 241 n of transmitters are shown in Figure 2. The arrangements may include elements that are arranged axially and / or circumferentially. Although the illustration shows them in a single housing, this is not to be construed as limiting the description; a common configuration uses transmitters and receivers in more than one sub. Also shown in the Figure are the borehole 26, the drill bit 50 and a reflector 211.0 reflector 211 corresponds to an interface where there is a change in the impedance of formation 200, so that incident waves are reflected backwards.
[00044] A new feature of this description is the fact that it takes advantage of the guided waves generated by an acoustic transducer in a well bore. The following terms are defined for the purposes of this description. A guided wave is any type of wave that is propagated along a well hole that involves a coupled movement of the fluid in the well hole, the tool and the well hole wall. A Stoneley wave is a particular type of guided wave, characterized by a pattern of omnidirectional directivity.
[00045] In the present description, each source element can be tuned to achieve a maximum output at a specific central frequency to maximize the generation of these guided waves. If tuning is not possible, different source modules with different center frequencies could be employed. If more than one source is used, the distance between the sources will be directly related to the applied frequencies (wavelength orders), so that interference and beam direction become possible. A coupling of all / some source elements directly to formation 200 by means of shim devices or the like is optional. Some elements could be piezoelectric, piezoceramic, magneto-restrictive devices, or others of pulse or frequency changed.
[00046] This variety of source center frequencies and locations allows the generation of a maximum amount of guided wave energy in monopole, dipole, quadripole or higher order excitations. To be specific, Stoneley waves can be generated by monopole excitation. A quadripole excitation, as described in U.S. Patent No. 6,850,168 to Tang et al., Can produce a guided wave that involves a coupled formation and a fluid movement that travels close to the formation's shear rate.
[00047] Having multiple sources axially distributed in the drill column allows the execution of a measurement with multiple displacement (source-receiver distance and variable source-reflector) in one round. With only one source in the drill string, this could be achieved by repetitive measurements while drilling in the front only. Mapping the same reflector with changing source-reflector distances, as well as having varying source-receiver shifts is beneficial for proper data evaluation.
[00048] Each receiver 221a ... 221n, 261 to ... 261 n is tuned to suit the characteristics of the source used. In the event that different source modules are used, different receiver modules (with receiving characteristics matching the respective source characteristics) need to be applied in the same way. The spatial arrangement (circumferential and axial) of the receivers is influenced by the maximum source frequency and the excitation mode. For lower frequencies, different sensor elements could be connected in parallel. The sensor elements could be pressure or motion sensitive devices mounted directly on the BHA or coupled to the formation using shims or similar devices. Different types of sensors and assemblies could be applied in parallel to serve multiple excitation modes simultaneously in a BHA.
[00049] Turning now to Figure 3, the basic principle of this description is illustrated. An activation of a transmitter, such as 300, excites a variety of waves in the well hole, in the formation and at the interface between the well hole and the formation. It is common knowledge that, in most cases, the strongest guided borehole wave generated by monopole excitation is a Stoneley wave. The generated Stoneley wave is described in Figure 3 by 30. This guided wave propagates along the well hole. This so-called “direct” guided wave is recorded by the receivers, such as 311, and used for further processing discussed below. The use of Stoneley waves is not to be construed as a limitation on the description. Generally, a guided wave will be produced by any type of excitation.
[00050] It should be noted that the drill bit 50 does not completely block the well hole 26, so that much of the direct guided wave actually reaches the bottom 51 of the well hole. When the guided wave reaches the bottom 51 of the well hole, part of it is reflected back. A significant portion of the guided wave is transmitted to formation 200. This is denoted by 303 in the Figure.
[00051] The energy going down 303 is reflected by an interface, such as 211, and the reflected energy 305 re-enters the well bore. Upon re-entering the well hole, much of it is converted back into a guided wave (denoted by 307) and propagates upward into the well hole. All modes are excited when re-entering a well hole. This reflected guided wave is also measured by the receivers, such as 311. Direct and reflected guided wave measurements form the basis for image formation in front of the drill bit 50. With a multipole receiver arrangement, a desired mode can be obtained by stacking azimuth.
[00052] Turning now to Figure 4, a hybrid flowchart is shown, which illustrates the processing steps and the physical processes involved. A guided wave is generated 401 by the activity of at least one transmitter in the profiling tool, and the primary wave field 301 is recorded 403 by at least one receiver in the receiver array. This can be referred to as a "first sign". At the bottom 406 of the well hole, the primary wave field 301 is partially transmitted 303 as an acoustic wave in the formation, reflected at 404 at the interface, for the production of the reflected wave field 305 in the formation. The wave field reflected in the formation is converted at the bottom 406 of the well hole to produce an infinite number of guided wave modes 307 in the well hole that is indicative of the reflection interface. The reflected guided waves are recorded by the receivers in step 405. This can be referred to as a “second signal”. The reflected guided waves recorded from step 405 can be processed with the primary wave field recorded from step 403 in step 407. Also shown in Figure 3 is a reflection 313 of the primary wave field at the bottom of the well hole.
[00053] Those skilled in the art and having the benefit of the present description would recognize that, since the receiver arrangements record the guided wave going down and the guided wave coming up, conventional wave field separation methods can be used to separate guided waves based on the direction of propagation. See, for example, Blias, (2005) SEG Extended Abstracts.
[00054] The practicality of the method is studied using numerical DF models. The modeling is performed using the FDTD 2.5D FDBH software by T. Bohlen and O. Hellwig. It is based on a formulation of speed and tension of the elastic wave equation in cylindrical coordinates with radius r and depth z as spatial model variables. Although the model is assumed to be constant with azimuth θ, the code not only allows to model symmetric wave fields in the rotation excited by monopole sources, but also higher order wave fields n with cos dependence (nθ) and sen (nθ), such as dipole (n = 1) or quadripole (n = 2) wave fields.
[00055] The model comprises a well hole filled with cylindrical fluid with a drilling tool in a homogeneous formation. The drilling tool divides the well hole into a central fluid cylinder and an annular fluid space. 10 m in front of the well hole bottom, perpendicular to the geometric well hole axis, there is a flat reflector. The data example presented contains a dipole volume injection source, which is located in the annular fluid space of the well bore. As a source signal, a Ricker ripple with a center frequency of 5000 Hz is used. The model geometry is given in Figure 6.
[00056] Figure 5 illustrates the course paths of the types of waves involved from the source (S) to the receiver (R) and their conversion at the conversion point (C). An advantage of using guided borehole waves is that they are less attenuated by geometric dispersion than body waves. Figure 5 includes the possibility that the reflector (211 in Figure 3) is inclined at an angle <p with the tool's geometric axis.
[00057] Figure 7 shows snapshots of different time instances (2.5 ms, 7.5 ms, 12.5 ms, 17.5 ms, 22.5 ms and 27.5 ms) of the radial component (component r ) of the particle speed. These snapshots show the propagation of different types of waves excited by the model source (P: direct P wave 701; S: direct S wave 703; T: bending wave (guided borehole wave excited by a dipole source) 705 ; TP: bending wave converted to a P 707 wave; TS: bending wave converted to an S 709 wave; TT: bending wave reflected in the well hole bottom 711; TSS: TS wave reflected in a layer boundary 713; TSST: TSS wave converted into a flexion wave; boundary reflection: modeling artifact, wave reflection at the model boundary). Note that the reflected TSS wave is clearly visible at 22.5 ms and only visible at 17.5 ms.
[00058] The snapshots make it clear that the main portion of the flexion wave (T) is converted into S waves (TS) at the bottom of a well hole. The conversion characteristic is studied in detail at the receiver positions indicated in Figure 10. The result is summarized in Figure 10, which shows the signal energy ^ ú2dt of converted waves 5 m away from the conversion point and normalized by the signal energy of the flexion wave at a receiver position in the annular fluid space, before conversion. The data conversion values TP and T-SV apply to an azimuth of θ = 0o, whereas the conversion values T-SH apply to θ = 90 °, due to the aforementioned dependence cos (nθ) and sen (nθ) ) of the corresponding wave field components. SV refers to vertically polarized S waves and SH refers to horizontally polarized S waves. Figure 10 confirms that converting T wave to S wave 1001, 1003 appears to be much more efficient than converting T wave to P wave 1005. For this reason, only TSST waves are considered with respect to exploration ahead of drilling .
[00059] If the azimuth dependence of T-SV and T-SH conversion is taken into account in the addition, the TS conversion directivity is obtained as shown in Figure 11. It shows the normalized signal energy of TS converted waves depending on their radiation direction. Half of the graph corresponds to the direction along the geometric axis of the borehole (cp = 0o). The edge corresponds to the direction perpendicular to the geometric axis of the borehole (<p = 90 °), and the circumferential direction corresponds to the azimuth angle 0. The Figure shows that the main portion of this type of converted wave is radiated at an interval between cp = 5o and cp = 30 °. This angle range depends on the elastic parameters of the formation, as well as the geometry of the borehole and the drill bit in particular. Furthermore, it is evident that the type of guided borehole wave excited in the borehole and its frequency have an influence on the directivity of the converted waves. If the formation parameters are known, it will be possible to direct the S waves from the conversion point (drill bit) in a desired direction by adjusting the source parameters (frequency range, source order), thus directing the reflectors with a characteristic alignment in relation to the well hole.
[00060] The modeled seismogram (Figure 9) shows the wave field (r component of the particle velocity) along the well bore at r = 0.11 m (annular fluid space) and in front of the well bore at two different types of training. Line 901 marks the conversion point at the bottom of the borehole z = 5 m, and line 903 marks the layer interface (reflector at z = 15 m). Starting at the source position (z = 0 m) and t = 0 ms, the flexion wave (T) 905 propagates towards the bottom of the borehole at z = 5 m. Although a bending wave conversion to S wave exhibits a minimum in the direction of the wellbore geometric axis (cp = 0o; see Figure 10), a conversion to an S wave (TS), which is indicated by 907, can be observed. Arriving at the reflector at z = 15 m, a portion of it is reflected and travels backwards towards the bottom of the borehole (TSS) 909. There, it excites a bending wave (TSST) again 911. This can be seen comparing the two wave field snapshots (r component of the particle velocity) in Figure 8. The TSS wave is approaching at the bottom of the well hole and continues to travel along the well hole. The excited flexion wave (TSST) is separated from the TSS wave and guided by the well bore. It propagates at a slightly slower speed than the S wave (TSS). So it falls back behind the TSS wave.
[00061] At each measurement level, the recorded data is evaluated in the model environment. The assessment comprises the separation of the primary and secondary wave fields, the construction of a well-hole speed model and a speed model in front of the drill, as well as the resource and preconditioning of the data (for example, filtration). It should be noted that the conversion to an acoustic wave propagating in the formation is not limited to the directions of propagation directly in front of the well hole. Consequently, with the use of an array of transmitters and / or receivers, there is a sufficient opening to “form the image” of the reflector to determine the position and dip of the reflectors. The image formation procedure could be any method of rearranging the elements of acoustic information in such a way that reflections and diffractions are plotted in their true locations (for example, an inversion operation such as time or depth migration).
[00062] The data evaluation results are used for the optimization of the source and receiver settings of the next measurement sequence or level (closed loop return). Depending on the telemetry bandwidth from the borehole to the surface, data evaluation and closed loop feedback could be performed on the surface or in the borehole using autonomous inversion schemes (this could involve implementing artificial intelligence and / or neural networks). The determined boundary location can be used to control the direction of drilling (reservoir navigation). The term "reservoir navigation" includes controlling the direction of drilling to be at a predetermined distance from a bed boundary and / or to be at a predetermined distance from a fluid interface that gives rise to reflection.
[00063] Figure 14 shows an example method 1400 for the processing of acoustic data for obtaining a dispersed wave field according to an embodiment of the present description. In step 1405, the traces (as in Figures 9 and 12) of repeated measurements can be stacked. Stacking can be performed to suppress random noise. In step 1410, a low frequency noise (such as from the drill bit) can be suppressed using frequency filtration (high pass). In step 1415, the wave field is decomposed into separate wave modes (monopole, dipole, etc.). In step 1420, waves going up and down into the well hole can be separated. A separation can use a variety of techniques, including, but not limited to, at least one of: (i) single-stroke processing and (ii) dive filtration. In step 1425, wave fields going up and down can be autocorrelated. An autocorrelation can be used to correct dispersion and reduce stroke time. In step 1430, dive events can be suppressed in short correlated sections using dive filtration (such as median filtration). In step 1435, the autocorrelated upward wave field can be decoded with an autocorrelated downward wave field. In some embodiments, step 1435 may not be carried out, or it may be carried out after step 1440. In step 1440, each trigger section can be stacked. In step 1445, the traces resulting from successive shots can be classified into common receptor accumulations (CRG). In step 1450, horizontal events can be removed from the receiver sections by diving filtration (such as median filtration). In step 1455, a slowness - time - consistency analysis is performed. This analysis can be used to determine the arrival time tss and the apparent slowness of diving events in the receiver section. In step 1460, the reflector distance can only be determined. In step 1465, reflector dip ψ can be determined. Step 1465 may require additional information with reference to the S, vs, wave speed of the formation. In step 1470, the reflector azimuth θ can be determined. Alternatively, it may be possible to use the filtered CRG data as an input to a 1475 migration algorithm that is especially suitable for imaging structures in front of the drill bit with a minimum number of well receivers below.
[00064] Some modalities of the present description may use synthetic data, real data or some combination thereof. The synthetic data may contain only the dipole portion of a wave field due to the axial symmetry of the model used. Actual data may show contributions from other multipole orders, in addition to the dipole portion, since axial symmetry is only a rough approximation of the actual well bore conditions. Actual data may also include random and consistent noise, often caused by the drill bit and fluid flow in and around the drill string.
[00065] By elaborating method steps 1400, in step 1410, a drill bit noise can be filtered using a high pass filter with a cutoff frequency below the frequency band of the active source and above the maximum frequency noise can attenuate these unwanted signals. In some embodiments, seismic waves generated by the drill bit can be used for prediction in front of the drill bit.
[00066] In step 1420, the wave field going upwards in a receiver position may contain reflections originating from the drill column, from the drill bit and from the front of the drill caused below the receiver position , although the wave field going down may contain reflections caused above the receiver position. A seismic prediction in front of the well holes can focus on reflectors in front of the drill bit. If the full wave field is used for imaging, reflections from above the receiver level, where the borehole intersects layer boundaries, are likely to cover TSST signals from ahead of the drill bit. perforation and cannot be distinguished from them after a correlation. A wave field separation can be used as a tool for suppressing unwanted reflections and for improving reflections contained in the wave field going upwards originating from below the receiver position. If a wave field separation produces good results, the wave field going downwards can be used in a further processing step for deconvolution. The separation of waves going up and down can be implemented in several ways, including, but not limited to, at least one of: (i) use of the pressure field and vertical particle speed recorded by dual sensors, which can be done trace by trace, and (ii) using dive filters. A wave field separation cannot be performed when only synthetic data is used.
[00067] To determine the distance from reflectors to the front of the drilling, the ISTST stroke time of TSST waves has to be reduced to the tss stroke time of S waves between the conversion point (downhole) and the reflector. Furthermore, it has to be taken into account that the guided well hole wave (T and TSST) is characterized by dispersion. The signal is stretched and the signal amplitude decreases during propagation. The objective is to change the recorded TSST signal to the stroke time tss and reduce the dispersion effect, as shown in Figures 12a to 12b. Figure 12a shows a schematic seismogram section corresponding to receivers between the source position (S) and the conversion point (C) along the well hole. As shown in Figure 12b, the guided borehole wave which is reflected in the borehole bottom (TT) has to be changed to t = 0 ms and the TSST signal to tss.
[00068] In step 1425, the autocorrelation function can display a local maximum in the change of time between similar signal sequences of a seismic trace. The global maximum can be found in a zero time interval. The amplitude in the zero time interval is equal to the total trace energy (sum of all samples squared in the trace). The guided wave from a direct well hole (T) traveling down through the well hole can be reflected in the drill bit (TT). Another part of this wave can be converted into body waves (mainly S waves) and radiated to the formation around a drill bit (TS). Assuming the converted well hole guided wave (TS) is reflected in an interface in front of the drill bit (TSS) and engages back to the well hole as the same wave mode (TSST) as the TT wave, both TT and TSST waves have the same dispersion characteristics, due to the same course of travel inside the well bore. This holds true for a well bore perfectly axially symmetrical and a flat reflector aligned perpendicular to the well bore axis. If there is a deviation in axial symmetry and if the reflector has a noticeable dip, retroconversion can be more complicated, and guided well hole waves not just in a single order (for example, monopole, dipole or quadripole), but of orders different may be involved.
[00069] The TSST wave is more or less a time-changed TT wave with respect to the wave mode that is excited by the source. Although the TT wave and TSST have different amplitudes, both are characterized by the same dispersion pattern. The difference in travel time between the TT wave and the TSST corresponds to the two-way travel time between the drill bit and the reflector. Hence, the autocorrelation of a trace containing TT and TSST signals produces a local maximum in this change in time. Furthermore, a correlation can correct the dispersive character of the waves, as can be seen in the following equations:

[00070] where ATT denotes the guided borehole wave that is directly reflected in the drill bit with its Ai amplitude and ATSST is the TSST wave with the A2 amplitude. S (ω) is the normalized source spectrum, z is the total travel path in the well bore and v (ω) is the velocity-dependent speed of wave propagation in the borehole, tss is the time change between TT waves and TSST. In the frequency domain, the autocorrelation of a trace including these terms can proceed as:

[00071] where * denotes a convolution. It is easy to see that the exponential terms representing the dispersive character of the waves disappear. In addition to the global maximum at T = 0, the other maximums appear exactly in the time interval between TT and TSST waves T = TTss. The remaining integral can be the autocorrelation of the subscriber from source S (ω). An ideal source signal can be an infinitely short pulse (white spectrum), although this may not be practicable in some cases. It may be desirable to use a source signal with a maximum bandwidth (for example, pulse or scan), so that the integral related to the source subscriber becomes a relatively short time pulse. The autocorrelation result can be independent of the travel path z in the well hole and, therefore, in phase for all well hole receivers, which allows additional stacking to minimize random noise. Autocorrelation is always zero phase, which means that changes in time between different events can be easily caught because they coincide with local maximums.
[00072] The autocorrelation function can make more contributions if more than two types of waves are present in the wave field, although unwanted contributions of waves with different overtime in the seismogram had the image formed with a dip in the corresponding autocorrelated seismogram and could be removed by dive-sensitive filters. In some modalities, the T and TT waves can be separated from the recorded wave field and can be cross-correlated with the total wave field. Figure 15A provides an example of a trigger section with waves going up and down. Figure 15B shows the associated autocorrelation section.
[00073] An autocorrelation makes it theoretically possible to use the drill bit signal as a source. The drill bit can excite a guided wave from a direct well hole traveling along the drill string and, in addition, radiate seismic waves into the formation. Reflections can be coupled back to the borehole as guided wave modes. The correlation of a wave generated from a direct drill and a reflection of the S wave from the formation can produce a maximum in the time change tss, which is equal to the time change between TT and TSST waves, when using active sources. Additionally, the drill bit can radiate P waves to form. The time change between the wave generated in a direct drill bit and a converted P reflection would be equal to the two-way stroke time of the P tPP wave between drill and reflector.
[00074] In step 1430, TT and TSST wave arrivals can be characterized by the same overtime in a trigger buildup, as long as they propagate upwardly in the well bore. The contribution of TT and TSST waves to the autocorrelated trigger section can have a horizontal overtime. The same holds true for all (multiple) reflections in the borehole. All events that display a dive in the autocorrelated trigger section can be removed by dive-dependent filtration. These dive events in the autocorrelated trigger section, such as the correlation of T and TT waves, correspond to the contribution of waves with different overtime. Subsequent stacking of all traces in the trigger accumulation reduces random noise (Figure 16). The signal-to-noise ratio is improved by the A / N factor with N denoting the number of stacked dashes. A median filter including a defined number of neighboring strokes is a possible implementation of this dive-sensitive filter. Instead of applying this type of median filter and subsequent stacking, it is also possible to take the median of all strokes for each time sample. The traces resulting from all the trigger sections form a CRG.
[00075] In step 1435, the wave field going downwards at a receiver position can be considered as a source signature of a wave going downwards. This wave can be reflected at different points below the receiver. The wave field going up, then, may turn out to be the convolution of the wave field going down with the system impulse response below the receiver. This impulse response may be related to a series of reflection coefficients below the receiver position, which indicates contrasts in elastic forming properties or tool parameters. Therefore, it is possible to obtain these reflection coefficients by the devolution of the wave field going upwards with the wave field going downwards, thus suppressing multiple reflections from above the receiver position. However, sometimes, a deconvolution may not improve the quality of the data, especially when the wave separation going up and down is not successful for several reasons. In cases where the separation is not successful, step 1435 can be neglected, and subsequent steps have to be applied to the wave field going upwards correlated.
[00076] In step 1450, a dip filtration can be applied, again, this time to remove horizontal events. Horizontal events, which correspond to (multiple) reflections in the well bore, can be subtracted from the input strokes. After successful application of the dive filter (such as a median filter), the TSST signals may become visible. When the drill bit approaches the reflector, the travel time of the TSST signal may decrease, and thus have a distinct overtime in a receiver buildup. In contrast, the stroke times of all reflections due to the structure of the drilling tool (for example, the reflection of TT in the drill bit) can remain constant in a receiver buildup, as long as no strong variation in forming speed occurs along the borehole, because the travel paths within the borehole do not change. Reflections from above the receiver unit caused by layer interfaces that have already been intercepted by the well bore would show an overtime similar to TSST signals with the opposite sign, although these reflections are no longer present in the data, since only the wave field going upwards (unconvoluted) is processed. For illustration, Figure 17A shows a receiver buildup before applying a dip filtration in step 1450, and Figure 17B shows a receiver build up after applying the dip filtration. Dive filtration filters out noise so that signals due to reflections can be seen along a TSST line.
[00077] In step 1455, tss and pa can be derived from the filtered receptor accumulation by an analysis of slowness - time - coherence. The energy of a tilted cell can be plotted in a certain time window normalized by the total energy of all the lines involved in the window. The slowness - time - coherence graph shows a maximum if an event can be tracked over different receiver positions. The apparent slowness pa is connected to the event overtime and its T intercept time depends on a reference position. In the following equation adopted from Kimball et al. (1984), the intercept time is equal to the arrival time at the receiver 1.

[00078] where ai (t *) denotes the amplitude measured at time t * in the 1 st receiver. The T parameter represents the extent of the window and the right and left being 2 to 3 times the period of the event that is wanted to determine its apparent slowness. The axial coordinate, Zi, denotes the distance between the ‘source’ and the ith receiver. N denotes the total number of receivers.
[00079] The determination of the distance s is dependent on the type of wave which is used for the image formation. Both the PP and SS reflections would have the image formed at the same distance s, because the ratio of their two-way travel time between the drill bit and the receiver and their apparent slowness is the same. This is no longer true for determining the cp reflector dip, which depends on the P or S wave velocity of the formation.
[00080] In step 1460, the reflector distance can only be determined. Figure 13 shows two different drill bit positions, where s denotes the distance between a drill bit and a reflector along the geometric axis of the borehole, while s' denotes half the stroke path of the perpendicularly converted wave. to the reflector, ds is the distance between the two shooting positions and ds' is half the difference in the corresponding travel paths between two shots. The reduced stroke time tss of the TSST wave is equal to:

[00081] with Vs being the S wave velocity of the formation and cp being the reflector dip. The dip angle a of the TSST node that can be observed in the receptor accumulation is:

[00082] where pa denotes an apparent slowness that characterizes the observed overtime of the TSST signal. The following expressions for reflector distance s (Figure 13) and dip angle <p (step 1465) can be derived from the above equations:

[00083] The determination of the reflector distance, s, is independent of the type of wave traveling through the formation.
[00084] This means that the reflector distance is only dependent on the reduced TSST travel time tss and the apparent slowness pa. No additional training parameters have to be known. Unlike the distance s, the reflector dip <p can be determined only if the speed of formation S wave vs is also known. The reflector dip cp can be estimated from the speed of guided well hole waves as defined in conventional well hole profiling. For example, quadripole waves propagate at the S-wave speed of true formation at their low frequency limit (cutoff).
[00085] In step 1470, the azimuth orientation θ of the reflector can be determined. The conversion characteristics of different waves in the drill bit and the orientation of sources with higher order than monopole have to be considered. Depending on the polarization of guided borehole waves, areas of formation with a certain azimuth are illuminated by the converted drill waves due to their conversion characteristics. The same holds true for the retroconversion of S waves in the drill bit. Depending on the angle of incidence (dip and azimuth) on the drill, the characteristic well hole guided wave modes with characteristic polarization are excited on the drill. This information could be used to determine the reflector's azimuth orientation in front of the drill.
[00086] The filtered dive CRG can be used as an entry into migration algorithms that are suitable for imaging structures in front of the drill bit with a minimum number of well receptors below. One possible implementation of a migration algorithm may be a phase shift migration with a modified imaging condition (beam migration). The filtered seismic traces of the CRG are changed by the stroke time Δt, depending on the distance between the waking receiver position and an image point x 'and in a given velocity model v in the vicinity of the well hole, and the waking amplitude has the image formed in x '(phase shift migration). Thus, signals caused by reflectors or dispersers are scattered in the isochron around the drill bit position. A constructive superposition of these images can be seen in the position of true reflector. Usually, a high number of seismic traces is necessary to obtain good images. The required number of strokes can be reduced considerably if the angle of incidence of reflections is used as an additional entry in the migration process. This information helps to limit the image to the actual reflector position. The angle of incidence can be derived from the apparent slowness of reflections observed in adjacent seismic traces. For this purpose, the coherent and total signal energy ratio of the time-changed strokes in the time interval |, +1 around t = 0 can be used as a weighting factor for the migration process described above. It reaches values between 0 (no coherence) and 1 (high coherence). High coherence means that the incident wave originates from the direction the reflector is in, while low coherence means that the apparent slowness observed in the different drill bit positions cannot be explained by a wave originating from that direction. In order to further suppress directions with low coherence, an exponent p> 1 can be added to the weighting function.

[00087] The image! (% ') In the above equation is the sum of all dashes with phase shifted A' (t, x ^, x ') at t = 0 weighted with the WTM weighting functions. (X ^. Δt (% ^, x ', v) represents the travel time from the drill bit xj- to an image point, x'.

[00088] provides two-way travel time with respect to the drill bit position ~ x} and an image point x 'for a flat reflector.
[00089]
provides the two-way travel time between the drill bit position x and the image point, x '.
[00090] Figure 18a shows an accumulation of common autocorrelated filtered dip receiver.
[00091] Figure 18b shows a graph of coherence of slowness - time - hearings of the data in Figure 18a.
[00092] Figure 19a shows the filtered CRG that is introduced for the migration. Figure 19b shows the result of a conventional phase shift migration without applying the weighting function.
[00093] Figure 19c shows the weighting function obtained from all 5 features of the CRG, and Figure 19d shows the result of the weighted phase shift migration. As can be seen, the image of the 1901 reflector at 5 m is more clearly defined in Figure 19d.
[00094] A coherence as an imaging condition in a gas mixing algorithm makes it possible to detect the angle of incidence of formation structures around the well bore, without the use of multiple component receivers and thus limit the image to this angle range. The fact that only a few seismic traces are needed in order to produce good images qualifies this migration technique for well-hole applications. Thus, a beam migration can be used to image subsurface structures based on TSST reflection data. This special type of migration is not restricted to TSST imaging. It can also be applied to data acquired by other seismic borehole methods, which focus not so much on the forming structures in front of the drill bit (looking ahead), but, for example, around the borehole ( looking around). Well-bore methods have the disadvantage that the source and receiver locations are restricted to the drilling path. For this reason, it is almost impossible to distinguish between incident reflections with different θ azimuth, a 3D beam migration, thus forming an image of a reflector as a circle around the well hole. The application of well-hole sources with a characteristic azimuth radiation pattern, such as dipole source arrangements or other sources radiating their energy in a certain direction, can be used to reduce ambiguity.
[00095] Additional information useful for the evaluation of measured data is also implemented in the evaluation model (if applicable). This could be a stratigraphic and subsurface velocity model resulting from surface seismic, near-well information, LWD / MWD data measured simultaneously with the description measurement process, etc. Part of this information is implemented before the maneuver in the well hole, others are updated / fed during drilling.
[00096] The above description was in terms of a device carried in a BHA on a tubular drilling element in a well hole in the formation of the terrain. The method and apparatus described above could also be used in conjunction with a profiling column carried on a steel cable to form the terrain. For the purposes of the present description, the BHA and the profiling column can be referred to as “well assembly below”. It should also be noted that, although the example shown described the transmitter set and the receiver set in a single tubular element, this is not to be construed as a limitation of the description. It is also possible to have a segmented acoustic profiling tool to facilitate transport in the well bore.
[00097] It is implicit in data processing to use a computer program implemented in a medium that can be read on a suitable machine, which allows the processor to perform control and processing. The medium that can be read on a machine can include ROMs, EPROMs, EAROMs, flash memories and optical discs. The formation rates and boundary locations determined can be recorded on a suitable medium and used for further processing by recovering the BHA. The determined formation speeds and the border locations can still be found by telemetry well above for display and analysis.
[00098] Although the foregoing description is directed to modalities in a manner of description, various modifications will be evident to those skilled in the art. It is intended that all variations are involved by the preceding description.

权利要求:
Claims (13)
[0001]
1. Method of determining a distance to an interface in a terrain formation, the method characterized by the fact that it comprises: transporting a profiling instrument (100) to a well hole (26); activate at least one transmitter (300) in the profiling instrument (100) to produce a guided acoustic wave (307), which propagates down to the bottom of the well hole (51) and produces an acoustic wave in the formation the terrain; use at least one receiver (311) on the profiling instrument (100) to: receive a first signal in response to the downward guided acoustic wave, and receive a second signal in response to an upwardly propagated acoustic wave resulting from reflection of the acoustic wave in the formation at an interface there; autocorrelate the first signal and the second signal, filter the first autocorrelated signal and the second autocorrelated signal using a dip filter; and estimating from the first filtered autocorrelated signal and the second filtered autocorrelated signal a distance to the interface.
[0002]
2. Method, according to claim 1, characterized by the fact that it still comprises: the application of a median filter to the Autocorrelated Common Shot Accumulations (CSG) deconvoluting the second filtered autocorrelated signal by the first filtered autocorrelated signal; and applying a median filter to an autocorrelated Common Receptor Accumulation (311) (CRG).
[0003]
3. Method, according to claim 1, characterized by the fact that it still comprises: the estimation of a dip angle and an azimuth of the interface, the image formation of the reflector (211) by performing the migration using coherence as a condition of image formation.
[0004]
4. Method, according to claim 1, characterized by the fact that it still comprises the decomposition of the guided acoustic wave (307) in its multiple pole constituents.
[0005]
5. Method, according to claim 1, characterized by the fact that it still comprises the execution of a migration with phase shift using an apparent slowness of observed reflections.
[0006]
6. Method, according to claim 1, characterized by the fact that it still comprises the control of a direction of drilling using the determined distance.
[0007]
7. Apparatus configured to estimate a distance to an interface in a terrain formation, the apparatus characterized by the fact that it comprises: a profiling instrument (100) configured to be transported to a well hole (26); at least one transmitter (300) in the profiling instrument (100) configured to produce a guided acoustic wave (307) which propagates down to the bottom of the well hole (51) and produces an acoustic wave in the formation of the ground; at least one receiver (311) on the profiling instrument (100) configured to: receive a first signal in response to the guided downward acoustic wave (307), and receive a second signal in response to a guided acoustic wave (307) upward propagation resulting from the reflection of the acoustic wave at the bottom of a well hole (26) and in the formation at an interface there; and at least one processor (40) configured to: autocorrelate the first signal and the second signal filter the first autocorrelated signal and the second autocorrelated signal using a dip filter, and estimate from the first autocorrelated signal and the second autocorrelated signal a distance from the bottom of the well hole (51) to the interface.
[0008]
8. Apparatus according to claim 7, characterized by the fact that the at least one processor (40) is additionally configured to estimate a dip angle and azimuth of the interface.
[0009]
9. Apparatus according to claim 7, characterized by the fact that the guided acoustic wave (307) is still a multiple pole wave mode.
[0010]
10. Apparatus according to claim 7, characterized by the fact that the at least one transmitter (300) still comprises a plurality of transmitters (300) which are at least one of: (i) axially disposed in the profiling instrument ( 100), and (ii) circumferentially arranged in the profiling instrument (100).
[0011]
11. Apparatus according to claim 7, characterized in that the at least one processor (40) is additionally configured to perform a phase shift migration using an apparent slowness of an observed reflection.
[0012]
Apparatus according to claim 7, characterized by the fact that the at least one processor (40) is additionally configured to perform a wave field separation in a wave field going UP and a wave field going up LOW representing the first signal and the second signal, and in which to autocorrelate the first signal and the second signal comprises autocorrelating the wave fields going UP and DOWN.
[0013]
13. Apparatus according to claim 8, characterized in that the at least one processor (40) is additionally configured to control a direction of drilling using the given distance.

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公开号 | 公开日

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WO2012027168A2|2012-03-01|

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US20120069713A1|2012-03-22|

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NO20130263A1|2013-02-28|

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法律状态:
2018-12-26| B06F| Objections, documents and/or translations needed after an examination request according art. 34 industrial property law|

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2019-10-15| B06U| Preliminary requirement: requests with searches performed by other patent offices: suspension of the patent application procedure|

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2020-06-02| B09A| Decision: intention to grant|

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2020-10-27| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 17/08/2011, OBSERVADAS AS CONDICOES LEGAIS. |

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