Abstract:
A method of generating an axial shear wave in a formation surrounding a wellbore comprising urging a clamp pad into contact with a wall of the wellbore, and applying an axial force to the clamp pad to impart a shear force into the wall of the wellbore to generate a shear wave in the formation.

Description:
BACKGROUND 
       [0001]    The present disclosure relates generally to the field of acoustic logging. 
         [0002]    Certain earth formations exhibit a property called “anisotropy”, wherein the velocity of acoustic waves polarized in one direction may be somewhat different than the velocity of acoustic waves polarized in a different direction within the same earth formation. Anisotropy may arise from intrinsic structural properties, such as grain alignment, crystallization, aligned fractures, or from unequal stresses within the formation. Anisotropy is particularly of interest in the measurement of the velocity of shear/flexural waves propagating in the earth formations. Shear or S waves are often called transverse waves because the particle motion is in a direction “transverse”, or perpendicular, to the direction that the wave is traveling. 
         [0003]    Acoustic waves travel fastest when the direction of particle motion polarization direction is aligned with the material&#39;s stiffest direction. If the formation is anisotropic, meaning that there is one direction that is stiffer than another, then the component of particle motion aligned in the stiff direction travels faster than the wave component aligned in the other, more compliant, direction in the same plane. In the case of 2-dimensional anisotropy, a shear wave induced into an anisotropic formation splits into two components, one polarized along the formation&#39;s stiff (or fast) direction, and the other polarized along the formation&#39;s compliant (or slow) direction. Generally, the orientation of these two polarizations is substantially orthogonal (components which are at a 90° angle relative to each other). The fast wave is polarized along the direction parallel to the fracture strike and a slow wave in the direction perpendicular to it. 
         [0004]    A significant number of hydrocarbon reservoirs comprise fractured rocks wherein the fracture porosity makes up a large portion of the fluid-filled space. In addition, the fractures also contribute significantly to the permeability of the reservoir. Identification of the direction and extent of fracturing is important in reservoir development for at least two reasons. 
         [0005]    One reason for identification of fracture direction is that such a knowledge makes it possible to drill deviated or horizontal boreholes with an axis that is preferably normal to the plane of the fractures. In a rock that otherwise has low permeability and porosity, a well drilled in the preferred direction will intersect a large number of fractures and thus have a higher flow rate than a well that is drilled parallel to the fractures. Knowledge of the extent of fracturing also helps in making estimates of the potential recovery rates in a reservoir and in enhancing the production from the reservoir. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0006]    A better understanding of the present invention can be obtained when the following detailed description of example embodiments are considered in conjunction with the following drawings, in which: 
           [0007]      FIG. 1A  shows an example of a drilling system traversing a downhole formation; 
           [0008]      FIG. 1B  shows an example of a drilling system traversing a dipping downhole formation; 
           [0009]      FIG. 2  shows an example of an acoustic tool; 
           [0010]      FIG. 3  shows an example set of decomposed received signals; 
           [0011]      FIG. 4  shows an example of logging in two wells, inclined to each other, in the same formation; 
           [0012]      FIG. 5  shows an example of an acoustic tool having an axial shear wave generator; and 
           [0013]      FIG. 6  shows an example of an axial shear wave generator in a wellbore. 
       
    
    
     DETAILED DESCRIPTION 
       [0014]      FIG. 1A  shows a schematic diagram of a drilling system  110  having a downhole assembly according to one embodiment of the present invention. As shown, the system  110  includes a conventional derrick  111  erected on a derrick floor  112  which supports a rotary table  114  that is rotated by a prime mover (not shown) at a desired rotational speed. A drill string  120  comprising a drill pipe section  122  extends downward from rotary table  114  into a directional borehole, also called a wellbore,  126 , through subsurface formations A and B. Borehole  126  may travel in a two-dimensional and/or three-dimensional path. A drill bit  150  is attached to the downhole end of drill string  120  and disintegrates the geological formation  123  when drill bit  150  is rotated. The drill string  120  is coupled to a drawworks  130  via a kelly joint  121 , swivel  128  and line  129  through a system of pulleys (not shown). During the drilling operations, drawworks  130  may be operated to raise and lower drill string  120  to control the weight on bit  150  and the rate of penetration of drill string  120  into borehole  126 . The operation of drawworks  130  is well known in the art and is thus not described in detail herein. 
         [0015]    During drilling operations a suitable drilling fluid (also called “mud”)  131  from a mud pit  132  is circulated under pressure through drill string  120  by a mud pump  134 . Drilling fluid  131  passes from mud pump  134  into drill string  120  via fluid line  138  and kelly joint  121 . Drilling fluid  131  is discharged at the borehole bottom  151  through an opening in drill bit  150 . Drilling fluid  131  circulates uphole through the annular space  127  between drill string  120  and borehole  126  and is discharged into mud pit  132  via a return line  135 . A variety of sensors (not shown) may be appropriately deployed on the surface according to known methods in the art to provide information about various drilling-related parameters, such as fluid flow rate, weight on bit, hook load, etc. 
         [0016]    In one example, a surface control unit  140  may receive signals from downhole sensors (discussed below) via a telemetry system and processes such signals according to programmed instructions provided to surface control unit  140 . Surface control unit  140  may display desired drilling parameters and other information on a display/monitor  142  which may be used by an operator to control the drilling operations. Surface control unit  140  may contain a computer, memory for storing data and program instructions, a data recorder, and other peripherals. Surface control unit  140  may also include drilling models and may process data according to programmed instructions, and respond to user commands entered through a suitable input device, such as a keyboard (not shown). 
         [0017]    In one example embodiment of the present invention, bottom hole assembly (BHA)  159  is attached to drill string  120 , and may comprise a measurement while drilling (MWD) assembly  158 , an acoustic tool  190 , a drilling motor  180 , a steering apparatus  161 , and drill bit  150 . MWD assembly  158  may comprise a sensor section  164  and a telemetry transmitter  133 . Sensor section  164  may comprise various sensors to provide information about the formation  123  and downhole drilling parameters. 
         [0018]    MWD sensors in sensor section  164  may comprise a device to measure the formation resistivity, a gamma ray device for measuring the formation gamma ray intensity, directional sensors, for example inclinometers and magnetometers, to determine the inclination, azimuth, and high side of at least a portion of BHA  159 , and pressure sensors for measuring drilling fluid pressure downhole. The above-noted devices may transmit data to a telemetry transmitter  133 , which in turn transmits the data uphole to the surface control unit  140 . In one embodiment a mud pulse telemetry technique may be used to generate encoded pressure pulses, also called pressure signals, that communicate data from downhole sensors and devices to the surface during drilling and/or logging operations. A transducer  143  may be placed in the mud supply line  138  to detect the encoded pressure signals responsive to the data transmitted by the downhole transmitter  133 . Transducer  143  generates electrical signals in response to the mud pressure variations and transmits such signals to surface control unit  140 . Alternatively, other telemetry techniques such as electromagnetic and/or acoustic techniques or any other suitable telemetry technique known in the art may be utilized for the purposes of this invention. In one embodiment, drill pipe sections  122  may comprise hard-wired drill pipe which may be used to communicate between the surface and downhole devices. Hard wired drill pipe may comprise segmented wired drill pipe sections with mating communication and/or power couplers in the tool joint area. Such hard-wired drill pipe sections are commercially available and will not be described here in more detail. In one example, combinations of the techniques described may be used. In one embodiment, a surface transmitter/receiver  180  communicates with downhole tools using any of the transmission techniques described, for example a mud pulse telemetry technique. This may enable two-way communication between surface control unit  140  and the downhole tools described below. 
         [0019]      FIG. 2  shows an example of acoustic tool  190 .  FIG. 2  shows the tool  190  disposed in BHA  159  within a fluid filled borehole  126 . Alternatively, the tool  190  may be suspended within the borehole by a multi-conductor armored cable known in the art. 
         [0020]    The tool  190  comprises a set of dipole transmitters: a first dipole transmitter  20 , and a second dipole transmitter  22 . In the perspective view of  FIG. 2 , only one face of each of the dipole transmitters  20 ,  22  may be seen. However, one of ordinary skill in the art understands that a complimentary face of each dipole transmitter  20  and  22  is present on a back surface of the tool  10 . The dipole transmitters may be individual transmitters fired in such a way as to act in a dipole fashion. The transmitter  20  induces its acoustic energy along an axis, which for convenience of discussion is labeled X in the  FIG. 2 . Transmitter  22  induces energy along its axis labeled Y in  FIG. 2 , where the X and Y axes (and therefore transmitters  20 ,  22 ) may be, in one example, orthogonal. The orthogonal relationship of the transmitters  20 ,  22  need not necessarily be the case, but a deviation from an orthogonal relationship complicates the decomposition of the waveforms. The mathematics of such a non-orthogonal decomposition are within the skill of one skilled in the art without undue experimentation. 
         [0021]    Tool  190  may also comprise a plurality of receiver pairs  24  and  26  at elevations spaced apart from the transmitters  20 ,  22 . In one embodiment tool  190  comprises four pairs of dipole receivers  24  A-D and  26  A-D. However, any number of receiver pairs may be used without departing from the spirit and scope of the invention. In the example shown in  FIG. 2 , the receivers are labeled  24 A-D and  26 A-D. In one example, each set of dipole receivers at a particular elevation has one receiver whose axis is coplanar with the axis of transmitter  20  (in the X direction) and one receiver whose axis is coplanar with the axis of transmitter  22  (in the Y direction). For example, one set of dipole receivers could be receivers  24 A and  26 A. Thus, the dipole receivers whose axes are coplanar with the axis of transmitter  20  are the transmitters  24 A-D Likewise the dipole receivers whose axes are coplanar with the axis of transmitter  22  are receivers  26  A-D. It is not necessary that the axes of the receivers be coplanar with the axes of one of the transmitters. However, azimuthally rotating any of the receiver pairs complicates the trigonometric relationships and, therefore, the data processing. The mathematics of such a non-orthogonal decomposition are within the skill of one skilled in the art without undue experimentation. 
         [0022]    Anisotropic earth formations tend to break an induced shear wave into two components: one of those components traveling along the faster polarization direction, and the second component traveling along the slower polarization direction, where those two directions are substantially orthogonal. The relationship of the fast and slow polarizations within the formation, however, rarely lines up with the orthogonal relationship of the dipole transmitters  20 ,  22 . For convenience of the following discussion and mathematical formulas, a strike angle Θ is defined to be the angle between the X direction orientation (the axis of dipole transmitter  20 ) and the faster of the two shear wave polarizations (see  FIG. 2 ). Further, it must be understood that the shear wave of interest does not propagate in the X or Y direction, but instead propagates in the Z direction where the Z direction is parallel to the axial direction. 
         [0023]    Operation of the tool  190  involves alternative firings of the transmitters  20 ,  22 . Each of the receivers  24 A-D and  26 A-D create received waveforms designated R, starting at the firing of a particular transmitter. Each of the received waveforms or signals has the following notation: R [receiver][source] . Thus, for the firing of transmitter  20  in the X direction, and receipt by one of the receivers having an axis coplanar to the axis of transmitter  20  (receivers  24 A-D), the time series received signal is designated as R XX . Likewise, the cross-component signal, the signal received by the dipole receiver whose axis is substantially perpendicular to the axis of the firing transmitter, is designated R YX  in this situation. In similar fashion, firing of the transmitter whose axis is oriented in the Y direction, transmitter  22 , results in a plurality of received signals designated as R YY  for the axially parallel receivers, and R XY  for the cross-components. Thus, each transmitter firing creates two received signals, one for each receiver of the dipole receiver pair. It follows that for a set of dipole transmitter firings, four signals are received at each receiver pair indicative of the acoustic signals propagated through the formation. The acoustic signals may be processed using transform techniques known in the art to indicate formation anisotropy. 
         [0024]    In one example, a processing method comprises calculating, or estimating, source signals or source wavelets that created each set of received signals by assuming a transfer function of the formation. Estimating source wavelets can be described mathematically as follows: 
         [0000]        S   EST     i   ( t )=[ TF]   −1   R   i ( t )  (1)
 
         [0000]    where S ESTi  is the estimated source signal calculated for the ith set of receivers, [TF] is the assumed transfer function of the formation in the source to receiver propagation, and R i  is the decomposed waveforms (described below) for the ith receiver set. Thus, for each set of received signals R i , an estimate of the source signal S ESTi  is created. The estimated source signals are compared using an objective function. Minimas of a graph of the objective function are indicative of the angle of the anisotropy, and the slowness of the acoustic waves through the formation. Further, depending on the type objective function used, one or both of the value of the objection function at the minimas, and the curvature of the of the objective function plot near the minimas, are indicative of the error of the slowness determination. 
         [0025]    Thus, a primary component of the source signal estimation is the assumed transfer function [TF]. The transfer function may be relatively simple, taking into account only the finite speed at which the acoustic signals propagate and the strike angle, or may be very complex, to include estimations of attenuation of the transmitted signal in the formation, paths of travel of the acoustic signals, the many different propagation modes within the formation (e.g. compressional waves, shear waves, Stonely waves), and if desired even the effects of the acoustic waves crossing boundaries between different layers of earth formations. For reasons of simplicity of the calculation, the preferred estimated transfer functions take into account only the propagation speed (slowness) of the acoustic energy in the formation and the strike angle of the anisotropy. 
         [0026]    Each of the received signals in the case described above contains components of both the fast and slow shear waves, and hence can be considered to be composite signals. That is, for example, an R XX  receiver signal contains information regarding both the fast and slow polarized signals. These composite signals may be decomposed into their fast and slow components using equations as follows: 
         [0000]        FP ( t )=cos 2 (θ) R   XX ( t )+sin(θ)cos(θ)[ R   XY ( t )+ R   YX ( t )]+sin 2 (θ) R   YY ( t )  (2)
 
         [0000]        SP ( t )=sin 2 (θ) R   XX ( t )−cos(θ)sin(θ)[ R   XY ( t )+ R   YX ( t )]+cos 2 (θ) R   YY ( t )  (3)
 
         [0000]      sin(2θ)[ R   XX ( t )− R   YY ( t )]−cos(2θ)[ R   XY ( t )+ R   YX ( t )]=0  (4)
 
         [0000]    where FP(t) is the fast polarization time series, SP(t) is the slow polarization time series, and θ is the strike angle as defined above. The prior art technique for decomposing the multiple received composite signals involved determining the strike angle θ by solving equation (4) above, and using that strike angle in equations (2) and (3) to decompose the composite signals into the fast and slow time series. 
         [0027]    In another example for decomposing the composite signals into the fast and slow time series, a close inspection of equations (2) and (3) above for the fast and slow polarization time series respectively shows two very symmetric equations. Taking into account the trigonometric relationships: 
         [0000]      sin θ=cos(90°−θ)  (5)
 
         [0000]      cos θ=sin(90°−θ)  (6)
 
         [0000]    it may be recognized that either the fast polarization equation (2) or the slow polarization equation (3) may be used to obtain either the fast or slow polarization signals by appropriately adjusting the angle θ used in the calculation. Stated otherwise, either the fast or slow polarization equations (2) or (3) may be used to decompose a received signal having both fast and slow components into individual components if the strike angle θ is appropriately adjusted. 
         [0028]    Rather than using a single strike angle in both equations (2) and (3) above, each assumed transfer function comprises a strike angle. A plurality of transfer functions are assumed over the course of the slowness determination, and thus a plurality of strike angles are used, preferably spanning possible strike angles from −90° to)+90° (180°. For each assumed transfer function (and thus strike angle), the four received signals generated by a set of receivers at each elevation are decomposed using the following equation: 
         [0000]        DS ( t )=cos 2 (θ)· R   XX ( t )+sin(θ)·cos(θ)·( R   XY ( t )+ R   YX ( t ))+sin 2 (θ)· R   YY ( t )  (7)
 
         [0000]    where DS(t) is simply the decomposed signal for the particular strike angle used. This process is preferably repeated for each set of received signals at each level for each assumed transfer function. Equation (7) is equation (2) above; however, equation (3) may be equivalently used if the assumed strike angle is appropriately adjusted. 
         [0029]    Consider a set of four decomposed signals, see  FIG. 3 , that are created using equation (7) above for a particular transfer function (strike angle). In the exemplary set of decomposed signals, R 1  could be the decomposed signal created using the strike angle from the assumed transfer function and the composite signals received by the set of receivers  24 A,  26 A. Likewise, decomposed signal R 2  could be the decomposed signal created again using the strike angle from the assumed transfer function and the composite signals created by the set of receivers  24 B,  26 B. In this example, the amplitude of the decomposed signal of the set of receivers closest to the transmitters, decomposed signal R 1 , is greater than the decomposed signals of the more distant receivers, for example R 4 . The waveforms may shift out in time from the closest to the more distant receivers, which is indicative of the finite speed of the acoustic waves within the formation. 
         [0030]    For a particular starting time within the decomposed signals, for example starting time T 1 , and for a first assumed transfer function having an assumed strike angle and slowness, portions of each decomposed signal are identified as being related based on the transfer function. Rectangular time slice  50  of  FIG. 3  is representative of a slowness in an assumed transfer function (with the assumed strike angle used to create the decomposed signals exemplified in  FIG. 3 ). In particular, the slope of the rectangular time slice is indicative of the slowness of the assumed transfer function. Stated another way, the portions of the decomposed signals within the rectangular time slice  50  should correspond based on the assumed slowness of the formation of the transfer function. The time width of the samples taken from each of the received signals may be at least as long as each of the source signals in a firing set. In this way, an entire source waveform or source wavelet may be estimated. However, the time width of the samples taken from the decomposed signals need not necessarily be this width, as shorter and longer times would be operational. 
         [0031]    Thus, the portions of the decomposed signals in the rectangular time slice  50  are each used to create an estimated source signal. These estimated source signals are compared to create an objective function that is indicative of their similarity. In one example, the estimated source signals may be compared using cross correlation techniques known in the art. In another example, cross correlation of the frequency spectra of the received signals may be compared using techniques known in the art. The process of assuming a transfer function, estimating source wavelets based on decomposed signals and creating an objective function may be repeated a plurality of times. The rectangular time slices  50  through  54  are exemplary of multiple assumed transfer functions used in association with starting time T 1  (and the a strike angle used to create the decomposed signals). Estimating source wavelets in this fashion (including multiple assumed transfer functions) may also be repeated at multiple starting times within the decomposed signals. 
         [0032]    The value of the objective function may be calculated for each assumed transfer function and starting time. Calculating the objective function of the first example technique comprises comparing estimated source signals to determine a variance between them. This slowness determination comprises calculating an average of the estimated source signals within each time slice, and then calculating a variance against the average source signal. In more mathematical terms, for each assumed transfer function, a series of estimated source waveforms or signals S ESTi  are calculated using equation (1) above. 
         [0033]    From these estimated source signals, an average estimated source signal may be calculated as follows: 
         [0000]    
       
         
           
             
               
                 
                   
                     
                       S 
                       
                         EST 
                         AVG 
                       
                     
                      
                     
                       ( 
                       t 
                       ) 
                     
                   
                   = 
                   
                     
                       1 
                       N 
                     
                      
                     
                       
                         ∑ 
                         
                           i 
                           = 
                           1 
                         
                         N 
                       
                        
                       
                         
                           S 
                           
                             EST 
                             i 
                           
                         
                          
                         
                           ( 
                           t 
                           ) 
                         
                       
                     
                   
                 
               
               
                 
                   ( 
                   8 
                   ) 
                 
               
             
           
         
       
     
         [0000]    where S ESTiAVG  is the average estimated source signal, N is the number of decomposed received signals, S ESTi  is the source wavelet estimated for each decomposed received signal within the time slice, and t is time within the various time series. 
         [0034]    The average estimated source signal is used to calculate a value representing the variance of the estimated source signals from the average estimated source signal. The variance may be calculated as follows: 
         [0000]    
       
         
           
             
               
                 
                   
                     δ 
                     2 
                   
                   = 
                   
                     
                       ∑ 
                       
                         i 
                         = 
                         1 
                       
                       N 
                     
                      
                     
                       
                         ( 
                         
                           
                             
                               S 
                               
                                 EST 
                                 i 
                               
                             
                              
                             
                               ( 
                               t 
                               ) 
                             
                           
                           - 
                           
                             
                               S 
                               
                                 EST 
                                 AVG 
                               
                             
                              
                             
                               ( 
                               t 
                               ) 
                             
                           
                         
                         ) 
                       
                       2 
                     
                   
                 
               
               
                 
                   ( 
                   9 
                   ) 
                 
               
             
           
         
       
     
         [0000]    where δ 2  is the variance. In one embodiment, the variance value is determined as a function of slowness, starting time, and strike angle. Large values of the variance indicate that the assumed transfer function (assumed strike angle and/or assumed slowness) did not significantly match the actual formation properties. Likewise, small values of the variance indicate that the assumed transfer function closely matched the actual formation properties. Thus, the minimas of the objective function described above indicate the slowness of the fast and slow polarized waves as well as the actual strike angle. The value of the variance objective function at the minimas is indicative of the error of the determination of the acoustic velocity and strike angle. The curvature of the variance objective function at the minima is indicative of the error of the calculation. 
         [0035]    A second embodiment for calculating an objective function is based on determining a difference between each estimated source signal. As discussed above, using the assumed transfer function, an estimated source signal is created using the portions of the decomposed signal within a time slice. Differences or differentials are calculated between each estimated source signal, for example between the source signal estimated from a portion of the R 1  signal and the source signal estimated from the portion of the R 2  signal. This difference is calculated between each succeeding receiver, and the objective function in this embodiment is the sum of the square of each difference calculation. The differential objective function is generated as a function of slowness, starting time, and strike angle. However, the function obtained using the differential slowness calculation has slower transitions from maximas to minimas which therefore makes determining the minimas (indicative of the actual slowness of the fast and slow polarizations) easier than in cases where the function has relatively steep slopes between minima and maxima More mathematically, the objective function of this second embodiment is calculated as follows: 
         [0000]    
       
         
           
             
               
                 
                   ζ 
                   = 
                   
                     
                       ∑ 
                       
                         i 
                         = 
                         1 
                       
                       
                         N 
                         - 
                         1 
                       
                     
                      
                     
                       
                         ( 
                         
                           
                             S 
                             
                               EST 
                               
                                 i 
                                 + 
                                 1 
                               
                             
                           
                           - 
                           
                             S 
                             
                               EST 
                               i 
                             
                           
                         
                         ) 
                       
                       2 
                     
                   
                 
               
               
                 
                   ( 
                   10 
                   ) 
                 
               
             
           
         
       
     
         [0000]    where ζ is the objective function, and N is the number of receivers. Much like using the variance as the objective function, this differential objective function is a function of slowness versus starting time versus strike angle. Known techniques may be used to determine minima of these functions, and the locations of the minima are indicative of formation slowness and the strike angle. 
         [0036]    Either of the two calculational techniques may be used. Numerous variations and modifications will become apparent to those skilled in the art once the above disclosure is fully appreciated. For example, the disclosed method for determining shear wave velocity and orientation may be implemented using any number of receiver levels and different receiver types for the acoustic logging tool. Indeed, even a single set of dipole receivers may be used relying on rotation of the tool to obtain additional composite signals for decomposition. Further, the source may be located at any arbitrary angle relative to the receivers. Moreover, processing of the data after collection at receivers can be performed downhole in real time with only the results being transferred uphole to a computer system for storage. Throughout this discussion, the various earth formation characteristics were discussed with reference to finding minimas of the objective function. However, one of ordinary skill in the art could easily invert the values used, thus making a determination a search for maximum values in the plot, and this would not deviate from the scope and spirit of the invention. While assuming the transfer functions in the embodiments described involved thus far assume a strike angle, it is possible that the transfer function need not include a strike angle estimation, and instead the composite signals could be decomposed for the range of possible strike angles independent of an assumed transfer function. It is also possible to solve for the strike angle using equation (4) above and decompose the composite waveforms using that strike angle; and thereafter, estimate and apply transfer functions to the decomposed signals, thus also removing the strike angle from the transfer function. 
         [0037]    As discussed above, crossed-dipole acoustic tools use a pair of orthogonal acoustic sources to create acoustic surface waves on the borehole wall. These surface waves (flexural waves) are strongly influenced by the mechanical stresses in the formations surrounding the borehole as well as any intrinsic anisotropy (such as fine layering in shales). The tools measure the anisotropy in the X-Y plane that is orthogonal to the tool longitudinal axis. The tool is substantially insensitive to anisotropy in the Z axis aligned with the tool longitudinal axis. In several drilling situations, complex stress regimes in the formations of interest make it desirable to know the three-dimensional stress field surrounding the borehole. 
         [0038]    As indicated, the acoustic tool described herein, provides information related to the anisotropy in the plane perpendicular to the local Z axis of the tool. At the L 0  location in  FIG. 1A , the XY plane of the tool is aligned with the XY plane of the earth system G. As the tool progresses, during drilling, along the path of borehole  126  in  FIG. 1A , the local coordinate system rotates from vertical to horizontal, as indicated by the local coordinate systems L 0 , L 1 , and L 2 . When acoustic tool  190  is in the horizontal section of the borehole, the Z axis of the earth coordinate system falls in the tools XY measurement plane. Thus by measuring in both the substantially vertical and substantially horizontal sections of the wellbore  126 , the horizontal (earth) field measurements from location L 0  and the vertical (earth) field measurements from L 2  may be combined using suitable techniques known in the art to provide a three dimensional stress field. 
         [0039]      FIG. 1B  shows a system similar to that described above traversing through a formation that is dipping, or tilted, with respect to the earth&#39;s coordinate system G. The properties of the dipping formation are aligned to the coordinate system F, where the XY plane is substantially parallel the bed interface  90 . Acoustic measurements made at location L 0  will measure components of the formation Z axis anisotropy. However, depending on the dipping angle, the sensitivity to the formation Z axis anisotropy may be weak. By again measuring in both the vertical (earth) and horizontal (earth) planes, the combined measurements may be related to the three dimensional stress field of the formation. In one example, the wellbore  126  may be drilled along a trajectory based on the three dimensional stress field. For example, the wellbore may be drilled to intersect fractures. In another example, the wellbore may be drilled along a path of minimum stresses. In one example, the calculations may be made downhole and may be used with drilling models stored in the downhole processor to adjust steering assembly  160  to drill the wellbore along a predetermined path based on the calculated anisotropic characteristics. 
         [0040]    In one example, see  FIG. 4 , the formation B is not large enough in the axial direction to allow the wellbore  126 ′ to be turned to the horizontal direction. Alternatively, the well plan may not call for an inclined or horizontal section in the particular well. It may be possible to acquire suitable acoustic anisotropy measurements in an offset wellbore  126 ″ that penetrates formation B at an inclination αc from vertical. Offset wellbore  126 ″ may have been drilled and logged prior to the drilling of wellbore  126 ′. In one example, the measurements from tool  190 ″ in well  126 ″ may be stored and later downloaded in memory of tool  190 ′ before deployment of tool  190 ′. The stored measurements may be combined with measurements made by tool  190 ′ and the resulting anisotropy results transmitted to the surface using known MWD telemetry techniques. Alternatively, tool  190 ″ may take measurements at approximately the same time as tool  190 ′. Measurements from both tool  190 ′ and  190 ″ may alternatively be processed in a surface control unit  140 , or at a remote site using techniques known in the art. 
         [0041]    In another example, see  FIG. 5 , instead of taking measurements at different axially displaced, orthogonal locations to acquire 3-D anisotropy results, a 3-axis acoustic tool  400  excites shear waves in all 3 axes by including an axial shear wave generator  401 . In one example, acoustic tool  400  comprises the 2-D tool  190  described previously and axial shear wave generator  401 . Axial shear wave generator  401  comprises a clamping device  405  that is extendable from the axial shear wave generator body  402  to engage the borehole wall around at least a portion of the circumference of the borehole wall. Clamp  405  is forced into cyclical axial motion by a force element in generator body  402 . The cyclical axial motion generates shear on the borehole wall in the axial motion direction. The resulting shear waves propagate away from the borehole wall. The shear waves produced by the clamped axial generator propagate substantially orthogonal to the shear waves generated by the dipole sources  20 ,  22  described above. 
         [0042]    In an isotropic medium, the clamped axial shear wave generator  401  will produce shear waves that move out into the formation and compressional waves along the borehole axis. If there is anisotropy, the wave from the clamped dipole source may split producing wave components along the three principle axes depending on the orientation of those axes relative to the borehole. The signals propagate out into the formation and are reflected back to the receivers  24  and  26  described previously. In one example, the signals may be processed in a downhole processor, using techniques known in the art, to determine the 3-D anisotropy characteristics of the formation, and the results transmitted to the surface using known telemetry techniques. Alternatively, the raw data may be transmitted to the surface and processed at the surface. The anisotropic characteristics comprise at least one of a three dimensional stress field and a three dimensional velocity field of the formation. 
         [0043]      FIGS. 6A and 6B  show one example of an axial shear wave generator  401  comprising a housing  402  that may be in drillstring  122  (see  FIGS. 1A and 1B ). As used herein, the term axial is intended to mean along, or parallel to, the longitudinal axis of the wellbore. An extendable member  409  is controllably extendable outward from housing  402  toward the wall  430  of wellbore  426 . In one example, a clamp pad  407  is attached to extendable member  409 , and engages wall  430 . As shown in  FIG. 5B , each pads  407  A-D may approximate a circumferential ring attached to wall  430  when all of pads  407  A-D are extended to engage wall  430 . In one embodiment, extendable member  409  may be part of a telescoping cylinder located on a movable base  410  disposed in housing  402 . In one example, movable base is  410  is attached to an axial force assembly  412  that provides axial back and forth motion to movable base  410 , thus providing axial motion to clamp pads  407 . In one embodiment, axial force assembly  412  comprises a stack of piezoelectric disks  413  polarized to extend and contract axially when excited by a suitable electric signal. In one embodiment, a backing mass  450  is mounted between the piezoelectric disks  413  and a shoulder  403  in housing  402 . In one example, backing mass  450  may comprise a tungsten material and/or a tungsten carbide material. Backing mass  451  helps to ensure that the majority of axial movement of the piezoelectric stack is directed toward the clamp bands. In one example, controller  415  comprises suitable electric circuits and processors to power the crystals and control the extension, and/or retraction, of extendable members  409 . Power source  420  may comprise suitable batteries for powering the axial shear wave generator during operation. Controller  415  may be in suitable data communication with other controllers in the downhole tool. Programmed instructions in controller  415  may be used control shear wave generation, data acquisition, and calculation of the anisotropic properties of the formation. In an alternative embodiment, magnetostrictive materials may be used to power the back and forth movement of clamp members  407  to generate axial shear waves in the surrounding formation. Such magnetostrictive materials may include nickel and rare earth materials for example a terbium-dysprosium-iron material. Such materials are known in the art. 
         [0044]    While described above with relation to an MWD/LWD system, one of ordinary skill in the art will appreciate that the apparatus and methods described herein may be used with wireline, slickline, wired drill pipe, and coiled tubing to convey the acoustic tools into the wellbore.