Abstract:
An apparatus and method is disclosed for measuring ultrasound drilling mud velocity downhole in real time. One or more generated acoustical pulses are detected upon traversing two separate path lengths, and ultrasonic velocity is determined from differences in the pulses upon traversing their respective path lengths. Alternately, a single measurement can be made using an acoustic pulse traversing a specified path length. A transducer is discussed having a piezoelectric crystal, a backing material having matching impedance, and a facing material disposed between the crystal and the fluid having an impedance intermediate to crystal and fluid. A concave front face of the crystal increases sensitivity to off-axis signals. Improved signal resolution can be achieved using a controlled shape input pulse optimized for certain drilling conditions. A method of echo detection using wavelet analysis is preferred.

Description:
BACKGROUND OF THE INVENTION  
         [0001]    1. Field of the Invention  
           [0002]    The invention relates to the field of acoustic measurement devices in oil exploration. Specifically, the invention is a method of measuring ultrasound velocity in drilling mud in a borehole formation.  
           [0003]    2. Background of the Art  
           [0004]    Ultrasonic pulse-echo measurements have long been used in wireline and LWD tools to measure a variety of parameters including instantaneous standoff, borehole caliper, or features on the borehole wall such as rugosity, fractures, or cracks. Basic ultrasonic properties are described, for instance, in “Ultrasonic Properties of Oil-Well Drilling Muds”, Hayman, Ultrasonics Symposium, IEEE, 1989. Standoff measurements have been described, for instance, in “Standoff and Caliper Measurements While Drilling Using a New Formation-Evaluation Tool with Three Ultrasonic Transducers, Birchak et al., SPE 68 th  Annual Technical Conference, 1993, “MWD Ultrasonic Caliper Advanced Detection Techniques”, Althoff et al., SPWLA 39 th  Annual Logging Symposium, 1998, and “Utilizing Acoustic Standoff Measurements to Improve the Accuracy of Density and Neutron Measurements”, Minette et al., SPE Annual Technical Conference, 1999. Examples of imaging uses of ultrasound can be found in “High-Resolution Cementation and Corrosion Imaging by Ultrasound”, Hayman et al., SPWLA 32 nd  Annual Logging Symposium, 1991, attenuation measurements are described, for instance, in “Ultrasonic Velocity and Attenuation Measurements in High Density Drilling Muds”, Molz et al., SPWLA, 39 th  Annual Logging Symposium, 1998.  
           [0005]    The working principle for all of these downhole applications involves mounting one or more highly mechanically damped ultrasonic transducers on a logging-while-drilling (LWD) tool for use during a drilling operation. The transducer emits a short duration broadband pulse. The pulse then reflects from the surface being probed and returns and re-excites the emitting transducer. The transducer is positioned such that at least some of the acoustic pulse propagates through the surrounding man-made borehole fluid, commonly referred to as drilling mud.  
           [0006]    Inaccuracy in the exact value of ultrasound velocity in the borehole fluids limits the accuracy of the measurement. The transit time τ for the echo determines the distance D to the reflecting surface. D=V mud *τ. However, the accuracy of the conversion from transit time to distance traveled is limited by the accuracy of the value of ultrasound velocity in the drilling mud, V mud . The ultrasound velocity in standard drilling mud is usually within 20% of that of water (1493 m/sec). Thus the propagation distance may have 20% inaccuracy. Higher accuracy is often required.  
           [0007]    Wireline tools have been developed which compensate for velocity-variation effects. This parameter is measured in real-time to facilitate correcting borehole imaging and for casing inspection. The working principle behind these tools requires a piezoelectric transducer mounted into the wall of a hollow chamber in the wireline tool such that the transducer faces a wall on the opposite side of the chamber. The chamber itself fills with fluid while downhole. The ultrasonic energy travels through the drilling fluid, reflects from the opposite wall, returns and re-excites the transducer. The ultrasonic velocity is determinable once the operator knows the delay time and the travel distance. Ultrasound attenuation can also be measured. Such an apparatus cannot be adapted to an LWD tool, where tighter size and strength constraints exist. Further, continuously flowing cuttings fills the chamber and produces either erroneous ultrasound velocity or, due to scattering of the ultrasound wave, no ultrasound velocity at all.  
           [0008]    LWD tools, like drilling pipe itself, are cylindrical, hollow, and threaded on each end to mount with pipe or other LWD tools in order to form a bottom hole assembly (BHA). The outer diameter of the LWD tool is less than that of the drilling bit. Drilling fluid or mud is circulated from the surface, through the center of the drilling pipe and BHA, out the bit, and returns to the surface between the outer diameter of the pipe and BHA and the borehole wall. The LWD tool, along with the rest of the BHA, may be rotated during drilling or held stationary, while the sliding bit rotates. The ultrasonic transducers are mounted on the outer diameter of the LWD facing the borehole wall to measure the borehole size (caliper) or the instantaneous distance from a point on the outer diameter of the tool to the borehole wall (standoff). Such measurements can be made by a stand-alone tool or can be used in conjunction with other measurements, such as nuclear density or porosity.  
           [0009]    Any drilling mud is mixed to have unique properties and thus each drilling mud has a unique ultrasound velocity. The velocity in the mud is determined by such factors as the mud type (oil or water), the mud weight, density, temperature, pressure, the amount of cuttings in the mud, the amount of formation fluids entering the mud, etc. As if this were not enough, the ultrasound speed in mud can change at any time as the well advances due to changing mud weight for borehole stability or a change in drilling conditions. Thus, while an improvement, calculating the mud velocity a priori and applying a correction factor has limited accuracy, as is described in “Mud Velocity Corrections for High Accuracy Standoff/Caliper Measurements” Molz, SPWLA 41 st  Annual Logging symposium, 2001. What is needed is a method for measuring ultrasound velocity in the mud downhole while the drilling continues. The measured mud velocity can then be used to correct caliper and standoff values in real time.  
           [0010]    U.S. Pat. No. 4,571,693 issued to Birchak et al discloses a method for measuring ultrasonic mud properties in a drilling environment. The method of Birchak &#39;693 involves using one or more ultrasonic transducers mounted within the body of a metal probe. The probe has a cavity cut from it with sides perpendicular to the direction of the ultrasonic wave. The probe connects to the LWD tool such that the cavity fills with drilling fluid when downhole. The ultrasonic signal propagates through the metal body, across the metal/mud interface, into the drilling fluid, reflects from the second mud/metal interface and back. Fluid properties are determined from the amplitude and the travel time of the return signal. Three problems exist with design described in Birchak &#39;693. First, with all the interfaces present in the invention, multiple echoes are observed. Secondly, the mud velocity is not the only variable ultrasound velocity involved. The ultrasound velocity of the metal changes with temperature, too. Third, the design of Birchak &#39;693 is difficult to mount on a typical LWD tool, where size is often a major constraint.  
           [0011]    The invention herein discloses methods to measure ultrasound velocity and attenuation in drilling mud in an LWD environment. The device is particularly useful in applications where real-time mud velocity corrections are needed and cannot be applied after LWD tool use.  
         SUMMARY OF THE INVENTION  
         [0012]    The invention is an apparatus and method for measuring ultrasonic velocity in a fluid within a borehole. The apparatus comprises an acoustic transmitter for generating acoustic waves in the fluid, a first receiver and a second receiver for detecting acoustic waves propagated through the fluid over two separate path lengths, and a processor for determining the parameter of interest from the first and second travel times of the acoustic waves over the respective path lengths. The parameter of interest can comprise the velocity of the acoustic waves in the fluid or a value for the standoff of the logging tool from the wall of the borehole. The processor controls the activation of the transmitter. In one embodiment of the invention, one of the acoustic transmitters is set in a recess on the logging tool, and the difference between the first and second path lengths is equal to the depth of the recess. Typically, in this embodiment, the two transmitters are at the same longitudinal position and separated by a toolface angle. This embodiment of the invention is enabled through rotation of the tool through the toolface angle. An orientation sensor obtains a measurement of the toolface angle. Such an orientation sensor can comprise a magnetometer, for instance.  
           [0013]    In another embodiment of the invention, the first and second receivers are spaced apart along the longitudinal direction of the logging tool. Optionally, one of the receivers can be set in a recess of the logging tool. The acoustic transmitter and either the first or second receiver comprise a single transducer.  
           [0014]    In yet another embodiment of the invention, an acoustic transmitter and acoustic receiver are positioned so as to measure an acoustic wave upon propagation over a specified path length. A typical instance of the embodiment would have the acoustic transmitter and acoustic receiver disposed along opposing walls of a recess in the logging tool, the specified path length being the distance between the acoustic transmitter and the acoustic receiver. In another instance of the embodiment, the acoustic transmitter and the acoustic receiver would comprise a single transducer disposed along a one of the opposing walls of the recess in the logging tool. The specified path length would comprise twice the distance from the transducer to the opposing wall.  
           [0015]    A transducer used in the invention comprises a piezoelectric crystal, a backing material having an impedance substantially matching that of the crystal, and a facing material disposed between the crystal and the fluid having an impedance intermediate to that of the crystal and that of the fluid. A typical backing material can be composed of a tungsten-polymer mixture. A typical facing material can be composed of Torlon. The front face of the piezoelectric crystal is typically concave to increase sensitivity to signals approaching from off-axis.  
           [0016]    A method of the invention comprises generating at least one acoustical pulse, obtaining a first measurement of a physical quantity of the at least one pulse propagated over a first path length, obtaining a second measurement of same physical quantity of the at least one pulse propagated over a second path length, and determining a parameter of interest from the differences in said measurements. The method enables measurement of physical quantities from two receivers having a path length difference equal to the recess difference, as in the embodiment with two receivers displaced by a toolface angle. Also, the method enables measurement of physical quantities from the embodiment having two receivers displaced by a longitudinal distance along the tool.  
           [0017]    In another method of the invention, a transmitter generates an acoustical pulse and a receiver measures the acoustical pulse after it has traveled a specified distance. The parameter of interest can be determined by the measurements and knowledge of the length of the specified distance.  
           [0018]    Improved signal resolution can be achieved using a controlled shape input pulse. Such a controlled pulse can be optimized for certain drilling conditions. A method of echo detection using wavelet analysis is preferred, thereby improving the dynamic range of detection for ultrasonic pulse echoes. 
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0019]    [0019]FIG. 1A (prior art) is a simplified depiction of a drilling rig, a drillstring and a wellbore equipped with an apparatus for interrogating the borehole in accordance with the present invention.  
         [0020]    [0020]FIG. 1B shows an azimuthal cross section of a method of the invention.  
         [0021]    [0021]FIG. 2 shows the peripheral electronics required to obtain a measurement using the method depicted in FIG. 1.  
         [0022]    [0022]FIGS. 3 a ,  3   b  show a longitudinal cross-sections of a second method of the invention.  
         [0023]    [0023]FIG. 4 shows the peripheral electronics required to obtain a measurement using the embodiment depicted in FIGS. 3 a  and  3   b.    
         [0024]    [0024]FIG. 5 is an azimuthal cross-section of a third method of the invention.  
         [0025]    [0025]FIG. 6 shows the peripheral electronics required to obtain a measurement using the method depicted in FIG. 5.  
         [0026]    [0026]FIG. 7 is the design of an LWD ultrasonic transducer that makes high-resolution pulse-echo measurements.  
         [0027]    [0027]FIG. 8 is a graph showing the effect of changing frequency and duration of a sine wave high voltage input on the shape of the transducer emitted pulse. 
     
    
     DESCRIPTION OF THE PREFERRED EMBODIMENT  
       [0028]    With reference to FIG. 1A, there will now be described an overall simultaneous drilling and logging system in accordance with one preferred embodiment of the present invention that incorporates an electromagnetic wave propagation (EWP) resistivity measurement system according to this invention.  
         [0029]    A well  1  is drilled into the earth under control of surface equipment including a rotary drilling rig  3 . In accordance with a conventional arrangement, rig  3  comprises a derrick  5 , derrick floor  7 , draw works  9 , hook  11 , swivel  13 , kelly joint  15 , rotary table  17 , and drill string  19  that comprises drill pipe  21  secured to the lower end of kelly joint  15  and to the upper end of a section of drill collars including an upper drill collar  23 , an intermediate drill collar or sub (not separately shown), and a lower drill collar measurement tubular  25  immediately below the intermediate sub. A drill bit  26  is carried by the lower end of measurement tubular  25 .  
         [0030]    Drilling fluid (or “mud”, as it is commonly called) is circulated from a mud pit  28  through a mud pump  30 , past a desurger  32 , through a mud supply line  34 , and into swivel  13 . The drilling mud flows down through the kelly joint and an axial tubular conduit in the drill string, and through jets (not shown) in the lower face of the drill bit. The drilling mud flows back up through the annular space between the outer surface of the drill string and the inner surface of the borehole to be circulated to the surface where it is returned to the mud pit through a mud return line  36 . A shaker screen (not shown) separates formation cuttings from the drilling mud before it returns to the mud pit.  
         [0031]    The overall system of FIG. 1A uses mud pulse telemetry techniques to communicate data from downhole to the surface while drilling operation takes place. To receive data at the surface, there is a transducer  38  in mud supply line  34 . This transducer generates electrical signals in response to drilling mud pressure variations, and these electrical signals are transmitted by a surface conductor  40  to a surface electronic processing system  42 .  
         [0032]    [0032]FIG. 1B shows a method of the invention comprised of two transducers displaced by a toolface angle along a tool device  105 . The tool device  105  could be positioned, for example, at the drill collar measurement tubular  25  of FIG. 1A. The transducers measure an ultrasound velocity and attenuation of a signal transmitted into a drilling mud  120 . The position of the first transducer  101 , referred to herein as the recessed transducer, is recessed a distance D closer to the center axis  110  of said drilling tool  105  than the second transducer  103 , hereafter referred to as the in-gauge transducer. The recess distance D is chosen to be large enough to give an accurate value of mud velocity. Both transducers are mounted at the same vertical position along the axis of the tool. The front faces of both transducers face the borehole wall  100  such that the acoustic paths of the emitted ultrasonic pulses extend toward the borehole wall and back to the transducer face.  
         [0033]    A first signal is produced at the in-gauge transducer, which also records the echo and attenuation of the first signal. Then the tool is rotated by rotation of the drillstring so that the recessed transducer is in substantially the same position at which the in-gauge transducer obtained measurements of the first signal. Measurement of toolface rotation can be made by magnetometers (not shown), for example. The recessed transducer then produces a second signal, and records echo and attenuation of the second signal.  
         [0034]    [0034]FIG. 2 shows a typical electronics assembly that enables measurement of the transit time for the echoes reflected from the borehole wall. This is shown with reference to the device of FIG. 1B. System timing is controlled by an Field Programmable Gate Array (FPGA)  201 , which sends a signal to the transducer pulsers. To obtain a measurement at the in-gauge transducer  222 , the pulser  212 P fires the in-gauge transducer at a time set by the FPGA  201 . The echo signal is received by the receiver  212 R and sent to a multiplexer  203 . The multiplexer  203  is set to channel corresponding to the receiver  212 R of the in-gauge transducer.  
         [0035]    The signal is then sent from through the multiplexer  203  to an analog to digital converter  205 . Upon receiving said signal, the analog to digital converter  205  immediately starts digitizing data. The digitized data is placed in memory  209 . The data in memory is processed by the microprocessor  207  to determine the transit time between firing and echo return and to determine the amplitude of the received echo. The described process is repeated for the recessed transducer  224 , with signals produced by the transducer pulser  214 P and received by the transducer receiver  214 R.  
         [0036]    As the tool device  105  rotates, every point on the outer tool diameter eventually passes through the same toolface angle. Toolface angle can be related to azimuthal angle using methods disclosed, for instance, in U.S. Pat. No. 4,909,336, issued to Brown et al. Thus, the recessed transducer  101  eventually passes through the same points as the in-gauge transducer  103 . When the tool is rotated so that the recessed transducer faces the same toolface angle at which a measurement of the in-gauge transducer has been obtained, said recessed transducer sees the same acoustic path of the in-gauge transducer lengthened according to the recessed distance D. For firings correlated to the toolface angle, the transit time before echo detection recorded by the recessed transducer, τ R , will be greater than the correlated transit time recorded by the in-gauge transducer τ G  at the same toolface angle within the borehole. The ultrasound velocity of the mud can then be calculated via 
           V   mud   =D /2(τ R −τ G )  (2) 
         [0037]    In addition, the amplitude of the echoes for the recessed transducer, A R , and for the in-gauge transducer, A G , can be measured, and the attenuation of the signal due to the mud, α mud , can be calculated via 
         α mud =20*log[ A   R   /A   G   ]/D   (3) 
         [0038]    A system of logic correlates the toolface angle of each transducer. Since LWD tools can move laterally within the borehole as well as circumferentially, the recessed transducer may be shifted to a different location along the axial length by the time it has rotated into the toolface angle position at which the in-gauge transducer has recorded its measurements. Therefore, each transducer may measure different positions along the borehole wall and thus different standoffs at the same toolface angle orientation. Furthermore, upon a complete rotation of the tool device, the caliper value of any one transducer may be slightly different from that of another. There are simple solutions to this problem. There is a minimum standoff that a transducer can be from the borehole wall. This minimum standoff corresponds to a minimum transit time. The standoff transit time measured by the system never goes below this minimum velocity besides the obvious mud velocity uncertainty. Since tool rotation is at least 60 RPM and often as high as 180 RPM, the minimum transit time will be encountered, if not in the first rotation due to lateral movement, then quickly on subsequent rotations. The minimum transit times over a period of rotations can be used in equations 2 and 3 for mud velocity and attenuation. Other coherent features of the standoff during tool rotations, such as washouts, can also be used.  
         [0039]    [0039]FIGS. 3 a  and  3   b  show a second method of the invention comprised of two transducers displaced axially along a tool device. In the second method shown in FIG. 3 a , the position of one transducer, hereafter referred to as the source transducer  301   a , is separated by a distance D in the axial direction from a second transducer, hereafter referred to as the receiving transducer  303   a . The transducers are mounted at the same toolface angle on the tool. The separation D between transducers  301   a  and  303   a  must be large enough to provide an accurate value of ultrasound velocity in the drilling mud. The front faces of both transducers are substantially facing the borehole wall  300 . The source transducer  301   a  can be used in a normal pulse-echo mode. The receiving transducer  303   a , rather than being fired, receives the echo caused by firing the source transducer  301   a . Alternately, the method would work equally well having transducer  301   a  and  303   a  both transmitting a pulse, while one transducer, for example,  301   a , can be used to detect the acoustic waves generated by both  301   a  and  303   a . The acoustic paths of the source AP S    310   a  and of the receiver AP R    315   a  created in such an embodiment are shown in FIG. 3 a . The acoustic path for the source transducer AP S    310   a  is simply the distance from the center face of source transducer  301   a  to the borehole wall  300  and back to the source transducer  301   a . The acoustic path of the receiver transducer AP R    315   a  is the distance from the center face of the source transducer  301   a  to a point on the borehole wall  300  half way between the two transducers back to the center face of the receiver transducer  303   a.    
         [0040]    [0040]FIG. 4 shows a typical electronics assembly that measures the transit time for the echoes traveling the acoustic paths of FIG. 3 a  or of FIG. 3 b . System timing is controlled by an FPGA  401 . The pulser  412 P fires the source transducer  422  at a time set by the FPGA  401 . The return signal received by the source transducer  422  is sent from the receiver electronics  412 R to an analog to digital converter  403 . The digitized data is placed in memory  407 . Simultaneously, the signal from the receiving transducer  424  is sent from the receiver electronics  414 R to another analog to digital converter  405 . The digitized data is placed in memory  407 . The data in memory is processed by the microprocessor  409  to determine the delay after firing and the amplitude of the echo for the source transducer  422  and for the receiving transducer  424 .  
         [0041]    In FIG. 3 a , since AP R    310   a  is larger than AP S    315   a , the transit time for the echo received at the receiver transducer (τ R ) will be longer than the transit time for the echo received at the source transducer (τ S ). The mud velocity can be calculated using these two transit times and the value of the separation D. The two acoustic paths are related through a right triangle: 
           AP   R   2   =AP   S   2 +( D /2) 2   (4) 
         [0042]    Replacing path lengths with measured transit times and the unknown mud velocity yields: 
         (τ R   *V   mud ) 2 =(τ S   *V   mud ) 2+ ( D /2)  (5) 
         [0043]    Solving for mud velocity yields a function of transit times and separation D: 
           V   mud   =D /[2(τ R   2 −τ S   2 ) 1/2 ]  (6) 
         [0044]    In addition, the amplitude of the two echoes, A R  and A S , can be measured, and the attenuation, α mud , can be calculated via 
         α mud =20*log[ A   R   /A   S   ]/D   (7) 
         [0045]    In an alternate technique of the second method, the receiver transducer can be recessed into the tool device, as shown in FIG. 3 b . Mud velocities are solved through similar methods. The acoustic path for the echo at the source transducer  301   b  is given by AP1=V mud T 1 =2SO, where SO is the perpendicular distance from the source transducer to the borehole wall  300 . This equation can be solved for SO to yield the equation:  
             SO   =           V   mud     *     T   1       2     .             (   8   )                               
 
         [0046]    The acoustic path for the echo at the receiver transducer  303   b  is given by 
           AP 2 =V   mud   T   2 =( SO   2   +X   2 ) 1/2 +{( SO   2   +R   2 ) 1/2 +( D−X ) 2 } 1/2   (9) 
         [0047]    where D is the distance from source transducer to receiver transducer, X is the distance along the axis from the source of the pulse to its point of reflection, and R is the depth of recession of the receiver transducer. Since angle of incidence Φ equals the angle of reflection, the following two equalities can be set up:  
               tan                 Φ     =       SO   X     =       SO   +   R       D   -   X                 (   10   )                               
 
         [0048]    to obtain  
             X   =         SO   *   D         2      SO     +   R       ·             (   11   )                               
 
         [0049]    Equation 8 can be substituted into equation 11 to get  
             X   =         (         V   mud     *     T   1       2     )     *   D           V   mud     *     T   1       +   R               (   12   )                               
 
         [0050]    Finally, the following relation can be formed by substitution of eqations 8 and 12 into equation 9:  
                       V   mud     *     T   2       =                (         (         V   mud     *     T   1       2     )     2     +       (         (         V   mud     *     T   1       2     )     *   D           V   mud     *     T   1       +   R       )     2       )       1   /   2       +                              {         (           V   mud     *     T   1       2     +   R     )     2     +       (     D   -     (         (         V   mud     *     T   1       2     )     *   D           V   mud     *     T   1       +   R       )       )     2       }       1   /   2       .                   (   13   )                               
 
         [0051]    Equation 13 can be solved to obtain mud velocity.  
         [0052]    [0052]FIG. 5 shows two possible techniques of a third method of the invention. A pulse-echo technique is displayed at the bottom of FIG. 5 and a source-receiver technique is displayed at the top. Unlike the first two methods of the invention, neither technique of this method uses the borehole wall as the reflecting surface. Rather, the ultrasonic signal can reflect off of the body of the LWD tool  505 . For the pulse-echo technique (shown at bottom), a channel  515  of tightly controlled width is machined into the body of the LWD tool  505  or into a module that fits into the LWD tool  505 . A transducer  501  is mounted into one side of the channel so that the front face is pointed toward the opposite wall  507 . During drilling, this channel fills with drilling mud. The acoustic path (AP 2 ) for the pulse-echo technique uses a two-way travel path. An ultrasonic pulse is emitted into the channel  515 , reflects from the face of the opposite wall  507 , returns, and re-excites the transducer  501  after a delay time τ 2 . The velocity of ultrasound in the mud can be calculated using this measured delay time.  
         [0053]    For the source-receiver technique (shown at top), a second transducer is mounted in the wall opposite the first transducer. The acoustic path (AP 1 ) uses a one-way travel path. An ultrasonic pulse is emitted from the source transducer  503 S, travels through the channel  515 , and excites the receiver transducer  503 R after some delay time τ 1 . The velocity of ultrasound in the mud can be calculated from this delay time.  
         [0054]    [0054]FIG. 6 shows a typical electronics assembly for measuring the transit times for the echoes traveling the acoustic paths of FIG. 5. System timing is controlled by an FPGA  601 . The pulser  612 P fires either the pulse-echo transducer  623  of pulse-echo technique or the source transducer  622  of the source-receiver technique at a time set by the FPGA  601 . The returned echo signal is received either by the pulse-echo transducer  623  of the pulse-echo technique or by the receiver transducer  624  of the source-receiver technique. Data is sent to the multiplexer  603 , which sends data to the analog to digital converter  605 . The digitized data is placed in memory  609 . The data in memory is processed by the microprocessor  607  to determine the delay after firing and amplitude of the echoes for the pulse-echo transducer and for the receiving transducer.  
         [0055]    In both techniques discussed with reference to FIG. 5, only one delay time is measured. Therefore delay times in water, τ 1W  and τ 2W , are used to calibrate against for both techniques. The ultrasound velocity in standard drilling mud is usually within 20% of that of water. The value of ultrasound velocity in drilling mud is found in the literature, for example, in “The Operation Characteristics of a 250 KHz Focused Borehole Imagine Device”, Zemanek et al., SPWLA 31 st  Annual Logging Symposium, 1990, and “New Ultrasonic Caliper for MWD Applications”, Orbin et al., SPE Drilling conference, 1991. A typical value for this velocity is 1493 m/sec. Once these delay times are measured, the ultrasound velocity in drilling mud can thus be calculated: 
         (pulse-echo)  V   mud =1493 m/sec*(τ 1 /τ 1W )  (13) 
         (source-receiver)  V   mud =1493 m/sec*(τ 2 /τ 2W )  (14). 
         [0056]    Also, in both techniques of this method, only one amplitude is measured. Therefore previously obtained values for the amplitudes in water, A 1W  and A 2W , are used to calibrate against for both techniques. Once these amplitudes are obtained, the ultrasound attenuation in drilling mud can be calculated: 
         (pulse-echo) α mud =20*log[ A   1   /A   1W ]/2 D   (15) 
         (source-receiver) α mud =20*log[ A   2   /A   2W ]/2 D   (16). 
         [0057]    It should be noted that either transducer can be used as the source or the receiver in the source-receiver method. Further, since the ultrasonic wave reflects from the front face of a transducer almost as well as from metal, the transducers in the source-receiver technique can be used in a pulse-echo mode.  
         [0058]    [0058]FIG. 7 shows an embodiment of a high-resolution pulse-echo broadband transducer designed for LWD applications including standoff and caliper determination. The design comprises a piezoelectric crystal  701  backed with a heavy tungsten-polymer mixture  703 . The backing material  703  is bonded into a metal cap  705  to give the back a flat, uniform surface. The crystal  701  is machined concave. Leads  707  are soldered to the front and back electrodes prior to applying the backing material. This crystal/backing/metal cap combination fits into a Torlon housing piece  711  with the crystal  701  in contact with the front Torlon face  720 . The Torlon housing  711  is machined with sides thick enough to withstand the wear of the drilling environment. The inner and outer faces of the Torlon front  720  are machined to the same curvature of that of crystal  701 . The Torlon housing  711  fits either into a window machined either into an independent module that fits into an LWD tool or into the LWD tool itself so that the front face  720  is exposed to the drilling mud. The module or tool has a groove and O-ring  715  to seal the drilling mud from the inside of the transducer. A backing plate  709  (for the module design), O-ring  717 , and screws  721 , seal the back of the transducer. The backing plate  709  also performs two other functions. While mounting the back plate, a spring  719  is compressed between a groove  730  in the metal cap  705  and the backing plate  709 . The backing plate  709  acts as the resistance for the spring loading of the piezoelectric crystal  701  to the Torlon housing front face  720 . The backing plate  709  comprises guide pins  727  that fit into holes  729  in the metal cap  705 . The backing plate  709  acts to keep the crystal/backing/metal cap combination from moving or rotating. The module or tool is machined with retaining lips to fasten the housing while spring loading. The transducer is filled with oil for pressure compensation. Not shown in FIG. 7 are a fill port and a method for oil-pressure compensation.  
         [0059]    Impedance matching enables acoustic energy to leave the crystal through both the front and back faces, further enabling a high-resolution transducer to be heavily damped with minimal ringing after firing. Impedance matching for the front and back faces is done with very different methods. The tungsten-polymer backing material  703  is designed to be very dense and hard, yielding a high acoustic impedance close to that of the crystal  701 . Much of the acoustic energy leaves the crystal  701  and enters the backing  703 . The backing material is also designed with high acoustic attenuation. With high acoustic attenuation, the energy that leaves and is reflected from edges of the crystal and external drilling mud cannot re-excite the crystal. This, along with a carefully designed thickness, maximizes the energy that leaves the crystal and enters the drilling mud. The crystal is machined with curvature, enabling higher sensitivity to ultrasonic energy that is approaching the transducer off the axis perpendicular to the Torlon front face  720 . The internals of the transducer are oil-filled to enable acoustic coupling, and to displace any air gap between the crystal and Torlon that might ruin the acoustic coupling. These oil-filled internals also enable oil pressure compensation between the drilling mud and the internal transducer. Spring loading ensures excellent contact between the crystal and the Torlon.  
         [0060]    A methodology of exciting and detecting a high-resolution pulse is presented here. The transducers used to generate these high-resolution pulses are highly mechanically damped and have a broadband response around their fundamental frequency. In general, these transducers are excited electrically with a high voltage spike having a wide range of frequency components. Given this broadband input, the transducer “picks” its fundamental frequency, as well as significant components surrounding the fundamental, as the frequency to transmit. The signature of the transmitted pulse with this type of input excitation is very difficult to control.  
         [0061]    The methodology presented herein is a controlled shape input pulse. The duration and frequency content of the emitted (and thus of the received) pulse can be more easily manipulated. Consider the simple example of a high voltage sine wave input. Both the frequency and the duration can be selected to give the emitted pulse the desired center frequency and bandwidth. FIG. 8 displays the pulse response for a 250 kHz broadband transducer excited with 1-cycle 180 kHz  801 , 2-cycle 180 kHz  803 , 1-cycle 250 kHz  811 , and 2-cycle 250 kHz  813 , sine wave inputs. As can clearly be observed, the frequency content and character is highly dependent on the input signal, even at 180 kHz. Such control can be very useful as the pulse shape can be optimized for certain drilling conditions.  
         [0062]    For instance, the transducers can be used to automatically select the optimal operating frequency down hole while drilling. As the distance between the transducer and borehole wall increases, the excitation frequency for the transducers can be lowered for lower attenuation. As the distance between the transducer and the borehole wall decreases, the transducers can be excited at higher frequency to increase resolution and prevent overlap of the reflected signal with the exciting signal, and thereby to reduce the dynamic of the transducer.  
         [0063]    The preferred detection method of the present invention herein is wavelet analysis. Wavelet analysis has applications in the medical, seismic, and vibration fields in which known low-level responses may exist. In borehole ultrasonics, the size of the echo may be the same as the size of other signals, such as residual transducer ringing after firing, electronic noise, etc. The proper wavelet is selected to match the expected echo signature. Wavelet selection comprises consideration for both shape and duration of the wavelet, easily predictable given the results in FIG. 8. Said proper wavelet is then correlated with the entire transducer spectrum after firing. The wavelet enhances the echo above the non-wavelet like background, making detection more clear. Such technique greatly improves the dynamic range of detection for ultrasonic pulse-echo measurement in the drilling environment.  
         [0064]    While the foregoing disclosure is directed to the preferred embodiments of the invention, various modifications will be apparent to those skilled in the art. It is intended that all such variations within the scope and spirit of the appended claims be embraced by the foregoing disclosure.