System and methodology for estimating formation elastic properties using decomposed and undecomposed signal

A technique facilitates estimating elastic properties of formations by exciting a wavefield and acquiring the signal with and without azimuthal decompositions. For example, the elastic properties may be estimated by exciting a multipole wavefield and acquiring the signal with and without the azimuthal decomposition. The technique is effective for estimating elastic properties of azimuthally homogeneous and heterogeneous formations including isotropic and anisotropic formations.

BACKGROUND

Hydrocarbon fluids, e.g. oil and natural gas, are obtained from a subterranean geologic formation, referred to as a reservoir, by drilling a well that penetrates the hydrocarbon-bearing formation. Various logging tools are used to obtain information regarding the surrounding hydrocarbon-bearing formation. In some applications, a wireline and logging-while-drilling (LWD) tool is used in a drill string to obtain logging data. In azimuthally heterogeneous formations, conventional multipole logging has certain limitations because, for example, the signal processing averages formation properties over different azimuths.

SUMMARY

In general, the present disclosure provides a system and methodology for estimating elastic properties of formations by exciting a wavefield and acquiring the signal with and without azimuthal decompositions. For example, the elastic properties may be estimated by exciting a multipole wavefield and acquiring the signal with and without the azimuthal decomposition. The technique is effective for estimating elastic properties of azimuthally homogeneous and heterogeneous formations including isotropic and anisotropic formations.

DETAILED DESCRIPTION

The disclosure herein generally relates to a system and methodology for estimating elastic properties of formations. Estimates may be obtained by exciting a wavefield and acquiring the signal with and without azimuthal decompositions. The signal data is obtained by, for example, an array of receivers and provided to a data processing system operated to determine the estimates. According to an example, the elastic properties may be estimated by exciting a multipole wavefield and acquiring the signal with and without the azimuthal decomposition. The technique is effective for estimating elastic properties of azimuthally homogeneous and heterogeneous formations including isotropic and anisotropic formations. The processed data may then be used to, for example, map elastic properties in the formation and to output the mapped data to a suitable display.

The techniques disclosed herein may be used to facilitate and improve data acquisition and analysis in various downhole tools and systems. Various types of downhole tools and systems may utilize arrays of sensing devices positioned downhole to obtain the desired signal data. The arrays of sensing devices may be configured for easy attachment and detachment in downhole sensor tools or modules deployed for purposes of sensing data which relates to environmental and/or tool parameters within a borehole. The tools and sensing systems disclosed herein may effectively sense and store characteristics relating to components of downhole tools as well as formation parameters, e.g. formation parameters at elevated temperatures and pressures.

According to an embodiment, sensing systems may be incorporated into tool systems such as wireline logging tools, measurement-while-drilling tools, logging-while-drilling tools, permanent monitoring systems, drill bits, drill collars, sondes, or other downhole tool systems. The downhole tool systems may be conveyed downhole via suitable conveyances, such as wireline, cable line, slick line, coiled tubing, or other suitable mechanisms for delivering the tools and sensing systems downhole. At desired positions in the borehole, acoustic signals may be transmitted and then received via the sensing system. The received acoustic signals are then processed as described herein to provide estimates (and sometimes maps or other output formats) of formation elastic properties.

For example, embodiments described herein provide a technique for estimating elastic properties of formations by exciting a wavefield, e.g. a monopole wavefield, dipole wavefield, or other multipole wavefield, and acquiring the returning signal with and without azimuthal decomposition. The technique is effective for estimating elastic properties of azimuthally homogeneous or heterogeneous formations including isotropic and anisotropic formations. Various systems of multi-mode excitation transmitters and receivers may be used in sonic logging tools or other types of tools to obtain the desired information on a given formation.

Referring generally toFIG. 1, an embodiment of a tool20, e.g. a sonic logging tool, is illustrated. In this example, the tool20comprises a sonic logging tool having an array of receivers22, e.g. receivers R1, R2, R3, R4, and a plurality of transmitters24, e.g. transmitters T1, T2, T3, T4. The plurality of transmitters24and the array of receivers22transmit and receive, respectively, acoustic signals with different azimuthal harmonics. For example, monopole, dipole, quadrupole, and unipole wavefields can be excited and acquired by the sonic logging tool20. Examples of the mode excitation by transmitters24are illustrated inFIG. 1as Monopole, Dipole-1, Dipole-2, Dipole-3, Dipole-4, Quadrupole, Unipole. Similarly, examples of the mode extraction after signal detection via receivers22are illustrated with respect to the corresponding modes: Monopole, Dipole-1, Dipole-2, Dipole-3, Dipole-4, Quadrupole, Unipole. The data extracted by receivers22may be sent to a processing system26, e.g. a computer-based processing system, to process the acoustic signal data. In this embodiment, the array of receivers22comprises azimuthally distributed receivers22.

With additional reference toFIG. 2, characteristics of multipole excitation (including unipole) have been illustrated. It should be noted the dipole excitation example inFIG. 2corresponds with Dipole-4 illustrated inFIG. 1. Due to the directivity of the firing directions, dipole and unipole may be used for estimating azimuthal variation of elastic properties. The estimation is especially effective for anisotropic formations and may be used in, for example, a deviated well in vertical axis of symmetry (VTI) formations.

Referring generally toFIG. 3, a graphical example has been provided that represents signal data from receivers22which has been processed by processing system26. The processed signal data is illustrated as output to a display28, e.g. a display screen of processing system26. In this example, the data is represented in compressional (P) and shear (S) slowness logs obtained with respect to a horizontal well30in a VTI formation32for both a sector up direction34and a sector side direction36. In this example, both the dipole log and the unipole log show consistent results with respect to each other. By way of example, the processing system26may utilize suitable software or other programs for calculating and outputting the dipole and unipole logs. According to one example, the dipole log may be determined via the Sonic Scanner Acoustic Scanning Platform available from Schlumberger Corporation, and the unipole log may be determined via the SonicPacer Acoustics Shale Evaluation system also available from Schlumberger Corporation.

The situation is different if formations are azimuthally heterogeneous as shown on the left side of the graphical display illustrated inFIG. 4. In this example, the horizontal well30has intersecting bed boundaries with an up sector38, e.g. up side, and a down sector40, e.g. down side. A drill string collar42is illustrated as disposed in the borehole of well30and is surrounded by mud44. As illustrated on the right side ofFIG. 4, a second track46of the log compares shear slowness acquired by unipole mode with respect to the corresponding up side38(labeled UP) and down side40(labeled DOWN) and acquired by dipole mode (labeled WL dipole). While the unipole mode provides different slownesses corresponding to the two different formations (up side38and down side40), the dipole mode shows an averaged slowness of the two layers. The example illustrated inFIG. 4indicates certain limitations of dipole logging for azimuthally heterogeneous formations. One such limitation is caused by the azimuthal decomposition process of dipole measurements.

Conventional multipole logging has been conducted by a decomposition process using azimuthally distributed receiver arrays. However, embodiments described herein involve exciting a multipole mode via an evaluating acoustic signal with and without azimuthal decomposition of waveforms. This unique approach improves the ability to characterize elastic properties, e.g. compressional (P) and shear (S) slownesses, of formations as compared to conventional approaches.

It should be noted unipole mode measurements alone have certain limitations such as complexity of dispersion analysis and less coherent slow shear arrivals when signal data is collected in a deviated well formed in strong VTI anisotropic formations. Furthermore, dipole mode measurements alone in sonic applications have certain limitations such as inaccurate measurements in azimuthally heterogeneous formations. Combining such measurements can be useful but also can result in redundant acquisition time and data storage especially for logging-while-drilling applications. However, the multipole mode approach described herein overcomes such limitations for estimating elastic properties with respect to azimuthally heterogeneous formations and certain other types of formations.

According to an embodiment, acquiring the nthorder multipole mode involves exciting the nthorder multipole mode via transmitters24and acquiring sensor waveforms via receivers22followed by the nthorder azimuthal decomposition (see block A of the workflow chart illustrated inFIG. 5). The waveforms may be acquired at each azimuth (YRX,i). Then, the decomposed waveforms (represented by YRX,n) are also obtained. Application of a modal decomposition to the waveforms acquired by the multipole firing and azimuthally distributed receivers22for extracting the n-th azimuthal harmonics can be achieved according to the following equation:

YRXn⁡(t)=∑i=1J⁢YRXi⁡(t)·cos⁡(n⁢⁢θi)∑i=1J⁢cos2⁡(n⁢⁢θi)
Here, θistands for the azimuthal position of the receiver22which takes YRXiwaveforms. This allows formation elastic properties, e.g. compressional and shear slownesses, to be calculated and obtained by processing YRX,nvia processing system26, as represented by block B inFIG. 5. The compressional and shear slownesses, for example, can be calculated from the semblance processing according to the so called STC (Slowness-Time-Coherence) method (see, for example, Christopher V. Kimball and Thomas L. Marzetta, Semblance processing of borehole acoustic array data, Geophysics, Vol. 49, No. 3, March 1984). By way of further example, the compressional and shear slownesses can be calculated from a DSTC (Dispersive Slowness-Time-Coherence) method (see, for example, Christopher V. Kimball Shear slowness measurement by dispersive processing of the borehole flexural mode, Geophysics, Vol. 63, No. 2, March-April 1998). The STC and DSTC methods may be used both for the decomposed and undecomposed waveforms. If the desired orientation for the signal analysis is not in line with the alignment of receivers22, then a process of rotating waveforms and/or composing waveforms via algebraic transform over multiple azimuthal waveforms may be conducted. An example of this general workflow is indicated in blocks A and B ofFIG. 5.

According to another workflow path, the formation elastic properties may be obtained from the ithazimuthal array of receivers22. In this case, the formation elastic properties are obtained without azimuthal decomposition of waveforms, as represented by block D inFIG. 5. The sensor waveforms without azimuthal decomposition are represented by YRX,i.

In this embodiment, the slownesses calculated for YRX,nand YRX,ican be compared for evaluating formation heterogeneity and anisotropy as shown in block C ofFIG. 5. For example, formation properties may be azimuthally mapped to evaluate the formation heterogeneity and anisotropy. This is useful especially with logging-while-drilling in view of geosteering and geolanding applications where knowledge regarding the relative position of the well being drilled with respect to the formation layer may be important. By way of example, the mapping may comprise outputting the mapping data to a display, e.g. a display of processing system26, to provide a map with respect to azimuth around a wellbore. With reference to the workflow example illustrated inFIG. 5, it should be noted the processes represented in blocks B and D may be accompanied with signal processing at different frequency bands and time windows to facilitate the estimation of elastic properties in the formation.

Referring generally toFIG. 6, a graphic illustration is provided of a reference acquired by high-frequency unipole modeling. In this example, the data represented is based on unipole mode firing without decomposition at 12-18 kHz. The graphical illustration shows that the slowness log as a function of azimuth corresponds with the azimuthal heterogeneity of formations.

Referring generally toFIGS. 7 and 8, further examples are provided utilizing dipole mode firing with decomposition at 1.5-3 kHz (seeFIG. 7) and dipole mode firing without decomposition at 12-18 kHz (seeFIG. 8). These examples are for a logging-while-drilling dipole mode (n=1) utilizing both the (A-B) and (A-D) workflow processes illustrated in the workflow chart ofFIG. 5. In this example, the workflow processes are for azimuthally heterogeneous formations and the data processing may be performed on processing system26and/or other suitable data processing systems.

As illustrated, with decomposed low-frequency dipole waveforms, heterogeneous characteristics of formations are not seen. Without decomposing waveforms, however, the azimuthally different slowness log(s) can be obtained using high-frequency waveforms. The slownesses of the waveforms at the up sector38correspond to compressional and shear slowness of the up formation. At the down sector40, slownesses corresponding to the down formation is observed as well as slownesses corresponding to the up formation.

Accordingly, the azimuthal heterogeneity of formations can be addressed and elastic properties estimated if the multipole wavefield is processed as described herein and as indicated graphically inFIGS. 7 and 8. As described herein, the multipole wavefield is processed with both the decomposed signal and also the undecomposed signal. According to an embodiment, processing of the decomposed signal and also the undecomposed signal can be accomplished by processing acoustic signal data at a sufficiently high frequency band.

If VTI anisotropy exists in homogeneous formations, the low-frequency dipole mode shows fast and slow shear slownesses. As a result, the decomposed and undecomposed waveforms can be compared to estimate elastic properties. For example, such a comparison may be effective for estimating elastic properties of heterogeneous formations and/or anisotropic formations. Regardless of the specific type of formation, borehole, or equipment deployed downhole, the technique of using decomposed and undecomposed waveforms enables changes to be made in exploiting a given reservoir found in the formation. For example, the improved estimation of elastic properties provides information which can be used to adjust drilling parameters, e.g. drilling directions. Additionally, the improved estimation facilitates optimization of well treatment, well completion, well production, and/or other aspects of utilizing the well and formation.

The systems and processes described herein may be used to estimate elastic properties of formations in a variety of environments. By way of example, embodiments described herein may be used with various types of equipment deployed downhole into deviated wellbores, e.g. horizontal wellbores. The equipment may comprise logging equipment or other types of equipment combined with appropriate transmitters24and receivers22. Additionally, the receivers22and transmitters24may be arranged in various patterns and positions. With certain embodiments described herein, for example, the receivers22may be arranged in an array or arrays to receive acoustic signal data in the form of a plurality of azimuthally distributed axial array waveforms. Elastic properties of the formation may then be calculated, as described above, using each of the axial array receiver waveforms of the plurality of azimuthally distributed axially array waveforms. Similarly, processing system26may comprise various types of computer-based processing systems for processing data, outputting graphical log displays, and indicating appropriate courses of action based on the estimated elastic properties of the formation.

Although a few embodiments of the system and methodology have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims.