Abstract:
A downhole acoustic logging tool uses a phased-array of transmitters and/or receivers to improve the signal level of compressional waves generated by the transmitters and propagating in the formation. It is emphasized that this abstract is provided to comply with the rules requiring an abstract which will allow a searcher or other reader to quickly ascertain the subject matter of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Description:
BACKGROUND OF THE DISCLOSURE 
       [0001]    1. Field of the Disclosure 
         [0002]    The present disclosure pertains to logging while drilling apparatus and more particularly to acoustic logging while drilling apparatus and improving the signal-to-noise ratio of compressional wave pulses that travel parallel to the direction of drilling. 
         [0003]    2. Summary of the Related Art 
         [0004]    To obtain hydrocarbons such as oil and gas, wells or wellbores are drilled into the ground through hydrocarbon-bearing subsurface formations. Currently, much current drilling activity involves not only vertical wells but also drilling horizontal wells. In drilling, information from the well itself must be obtained. While seismic data has provided information as to the area to drill and approximate depth of a pay zone, the seismic information can be not totally reliable at great depths. To support the data, information is obtained while drilling through logging while drilling or measuring while drilling (MWD) devices. Logging-while-drilling, or measuring-while-drilling are procedures that have been in use for many years. This procedure is preferred by drillers because it can be accomplished without having to stop drilling to log a hole. This is primarily due to the fact that logging an unfinished hole, prior to setting casing if necessary, can lead to washouts, damaging the drilling work that has already been done. This can stall the completion of the well and delay production. Further, this information can be useful while the well is being drilled to make direction changes immediately. Measurements, however, are taken long after the actual drilling of the well. 
         [0005]    An important part of determining the properties of subsurface formations involves measurement of compressional and shear wave velocities. This is typically done by exciting acoustic waves using a transmitter and receiving compressional (P-waves) and shear waves (S-waves) through formation and analyzing signals received by an array of receivers. It is also common practice to measure acoustic waves propagating through the borehole. 
         [0006]    P-waves usually have much lower amplitude than S-waves. The large difference in signal amplitude makes the detection and measurement of P-waves more difficult. The problem is worse for logging while drilling (LWD) because of the interference of waves propagating along the tool. For wireline tools, acoustic isolators can be designed that almost completely block the tool wave so that there is little contamination of the formation arrival by the tool signal. See, for example, U.S. Pat. No. 5,229,553 to Lester. However, for an MWD tool, the mechanical strength constraints limit the performance of the acoustic isolator. Examples of acoustic isolators for LWD are shown, for example, U.S. Pat. No. 6,082,484 to Molz et al., in U.S. Pat. No. 6,615,949 to Egerev et al., U.S. Pat. No. 6,820,716 to Redding et al., U.S. Pat. No. 6,915,875 to Dubinsky et al., U.S. Pat. No. 7,028,806 to Dubinsky et al., and U.S. Pat. No. 7,032,707 to Egerev et al all having the same assignee as the present disclosure. See also U.S. Pat. No. 7,216,737 to Sugiyama, U.S. Pat. No. 5,639,997 to Mallett. 
       SUMMARY OF THE DISCLOSURE 
       [0007]    One embodiment of the disclosure is an apparatus for logging an earth formation. The apparatus includes a logging tool having at least one transmitter which includes a plurality of segments. The logging tool is configured to be conveyed in a borehole and generate an acoustic wave in the formation. At least one receiver is configured to produce a signal responsive to the generated acoustic wave. The apparatus further includes a processor configured to activate the plurality of segments using a time delay which accentuates an axially propagating compressional wave in the formation, determine from the signal a compressional wave velocity of the formation, and record the determined compressional wave velocity on a suitable medium. The at least one receiver may include a plurality of spaced-apart receivers forming a receiver array. The processor may further be configured to determine the time delay based at least in part on an estimated compressional wave velocity and a spacing between the segments of the at least one transmitter. The processor may further be configured to improve the determined compressional wave velocity using redundancy in signals received by the plurality of receivers. The processor may be further configured to estimate a shear wave velocity of the formation. The logging tool may be part of a downhole assembly conveyed on a drilling tubular or a wireline. 
         [0008]    Another embodiment of the disclosure is a method of logging an earth formation. The method includes conveying at least one transmitter having a plurality of segments into a borehole, sequentially activating the plurality of segments using a time delay which accentuates a compressional wave component of a generated acoustic wave in the formation, using at least one receiver to produce a signal responsive to be generated acoustic wave, determining from the signal a compressional wave velocity of the formation, and recording the determined compressional wave velocity on a suitable medium. The method may include using for the at least one receiver a plurality of spaced apart receivers forming a receiver array. The time delay may be determined based at least in part on an estimated compressional wave velocity and a spacing between the segments of the at least one transmitter. The method may further include improving the determined compressional wave velocity using information redundancy in signals received by the plurality of receivers. The method may further include estimating a shear wave velocity of the formation. 
         [0009]    Another embodiment of the disclosure is an apparatus for logging an earth formation. The apparatus includes a logging tool configured to be conveyed in a borehole. At least one transmitter on the logging tool is configured to generate an acoustic wave in the formation. The apparatus further includes at least one receiver including a plurality of segments, each of the segments configured to produce a signal in response to the generated acoustic wave. The apparatus also includes a processor configured to combine the signals from the plurality of segments using a time delay which accentuates an axially propagating compressional wave in the formation, determine from the combined signal a compressional wave velocity of the formation, and record the determined compressional wave velocity on a suitable medium. The at least one receiver may further comprise a plurality of spaced apart receivers forming a receiver array. The processor may be further configured to determine the time delay based at least in part on an estimated compressional wave velocity and a spacing between the segments of the at least one receiver. The processor may be further configured to improve the determined compressional wave velocity using information redundancy in signals by the plurality of receivers. The processor may be further configured to estimate a shear wave velocity of the formation. The logging tool may be part of a downhole assembly conveyed on a drilling tubular or a wireline. 
         [0010]    Another embodiment of the disclosure is a method of logging an earth formation. The method includes conveying at least one transmitter into a borehole and generating an acoustic wave. Each of a plurality of segments of at least one receiver is used to produce a signal responsive to the generated acoustic wave. The signals from the plurality of segments are combined using a time delay which accentuates an axially propagating compressional wave in the formation. A compressional wave velocity of the formation is determined from the combined signal and recorded on a suitable medium. A plurality of receivers forming a receiver array may be used for the at least one receiver. The time delay may be determined based at least in part on an estimated compressional wave velocity and a spacing between the segments of the at least one receiver. The determined compressional wave velocity may be improved by using information redundancy in signals generated by the plurality of receivers. The method may further include estimating a shear wave velocity of the formation. 
     
    
     
       BRIEF DESCRIPTION OF THE FIGURES 
         [0011]    For detailed understanding of the present disclosure, references should be made to the following detailed description of exemplary embodiment(s), taken in conjunction with the accompanying drawings, in which like elements have been given like numerals, wherein: 
           [0012]      FIG. 1  is an illustration of a bottomhole assembly (BHA) deployed in a borehole from a drilling tubular that includes the apparatus according to one embodiment of the present disclosure; 
           [0013]      FIG. 2  is an illustration of a phased-transmitter array used for generating signals recorded by a receiver array; 
           [0014]      FIG. 3  is an illustration showing P-wave signals recorded by the apparatus of  FIG. 2  without and with the use of the phased array; 
           [0015]      FIG. 4  illustrates the complete wave train including the S-wave arrival; and 
           [0016]      FIG. 5  is an illustration of a phased-receiver array used for recording signals from a transmitter. 
       
    
    
     DETAILED DESCRIPTION OF THE EMBODIMENTS 
       [0017]    In view of the above, the present disclosure through one or more of its various aspects and/or embodiments is presented to provide one or more advantages, such as those noted below. 
         [0018]      FIG. 1  illustrates a schematic diagram of an MWD drilling system  10  with a drill string  20  carrying a drilling assembly  90  (also referred to as the bottom hole assembly, or “BHA”) conveyed in a “wellbore” or “borehole”  26  for drilling the wellbore. The drilling system  10  includes a conventional derrick  11  erected on a floor  12  which supports a rotary table  14  that is rotated by a prime mover such as an electric motor (not shown) at a desired rotational speed. The drill string  20  includes tubing such as a drill pipe  22  or a coiled-tubing extending downward from the surface into the borehole  26 . The drill string  20  is pushed into the wellbore  26  when a drill pipe  22  is used as the tubing. For coiled-tubing applications, a tubing injector (not shown), however, is used to move the tubing from a source thereof, such as a reel (not shown), into the wellbore  26 . The drill bit  50  attached to the end of the drill string  20  breaks up the geological formations when it is rotated to drill the borehole  26 . If a drill pipe  22  is used, the drill string  20  is coupled to a drawworks  30  via a Kelly joint  21 , swivel  28  and line  29  through a pulley  23 . During drilling operations, the drawworks  30  is operated to control the weight on bit, a parameter that affects the rate of penetration. The operation of the drawworks is well known in the art and is thus not described in detail herein. 
         [0019]    During drilling operations, a suitable drilling fluid  31  from a mud pit (source)  32  is circulated under pressure through a channel in the drill string  20  by a mud pump  34 . The drilling fluid passes from the mud pump  34  into the drill string  20  via a desurger  36 , fluid line  38  and Kelly joint  21 . The drilling fluid  31  is discharged at the borehole bottom  51  through openings in the drill bit  50 . The drilling fluid  31  circulates uphole through the annular space  27  between the drill string  20  and the borehole  26  and returns to the mud pit  32  via a return line  35 . The drilling fluid acts to lubricate the drill bit  50  and to carry borehole cutting or chips away from the drill bit  50 . A sensor S 1  preferably placed in the line  38  provides information about the fluid flow rate. A surface torque sensor S 2  and a sensor S 3  associated with the drill string  20  respectively provide information about the torque and rotational speed of the drill string. Additionally, a sensor (not shown) associated with line  29  is used to provide the hook load of the drill string  20 . 
         [0020]    Rotating the drill pipe  22  rotates the drill bit  50 . Also, a downhole motor  55  (mud motor) may be disposed in the drilling assembly  90  to rotate the drill bit  50  and the drill pipe  22  is rotated usually to supplement the rotational power, if required, and to effect changes in the drilling direction. 
         [0021]    In the embodiment of  FIG. 1 , the mud motor  55  is coupled to the drill bit  50  via a drive shaft (not shown) disposed in a bearing assembly  57 . The mud motor  55  rotates the drill bit  50  when the drilling fluid  31  passes through the mud motor  55  under pressure. The bearing assembly  57  supports the radial and axial forces of the drill bit. A stabilizer  58  coupled to the bearing assembly  57  acts as a centralizer for the lowermost portion of the mud motor assembly. 
         [0022]    A drilling sensor module  59  is placed near the drill bit  50 . The drilling sensor module  59  contains sensors, circuitry and processing software and algorithms relating to the dynamic drilling parameters. Such parameters may include bit bounce, stick-slip of the drilling assembly, backward rotation, torque, shocks, borehole and annulus pressure, acceleration measurements and other measurements of the drill bit condition. A suitable telemetry or communication sub  72  using, for example, two-way telemetry, is also provided as illustrated in the drilling assembly  90 . The drilling sensor module  59  processes the sensor information and transmits it to the surface control unit  40  via the telemetry system  72 . 
         [0023]    The communication sub  72 , a power unit  78  and an NMR tool  79  are all connected in tandem with the drill string  20 . Flex subs, for example, are used in connecting the MWD tool  79  in the drilling assembly  90 . Such subs and tools form the bottom hole drilling assembly  90  between the drill string  20  and the drill bit  50 . The drilling assembly  90  makes various measurements including the pulsed nuclear magnetic resonance measurements while the borehole  26  is being drilled. The communication sub  72  obtains the signals and measurements and transfers the signals, using two-way telemetry, for example, to be processed on the surface. Alternatively, the signals may be processed using a downhole processor in the drilling assembly  90 . 
         [0024]    The surface control unit or processor  40  also receives signals from other downhole sensors and devices, signals from sensors S 1 -S 3  and other sensors used in the system  10  and processes such signals according to programmed instructions provided to the surface control unit  40 . The surface control unit  40  displays desired drilling parameters and other information on a display/monitor  42  utilized by an operator to control the drilling operations. The surface control unit  40  preferably includes a computer or a microprocessor-based processing system, memory for storing programs or models and data, a recorder for recording data, and other peripherals. The control unit  40  is preferably adapted to activate alarms  44  when certain unsafe or undesirable operating conditions occur. An acoustic logging tool  100  (discussed next) may be positioned at a suitable location such as shown. 
         [0025]    Turning now to  FIG. 2 , an exemplary tool  100  using the method of the present disclosure is illustrated. As would be known to those versed in the art, a downhole acoustic source (or receiver) usually has a finite length. The source may consist of several segments stacked in the tool axial direction. This may be referred to as a transmitter assembly. In one embodiment of the disclosure, the elements are piezoelectric transducers. In prior art devices, the segments  101   a ,  101   b ,  101   c  are fired at the same time. The waves induced by neighboring segments travel to a receiver such as  121  at slightly delayed times. In other words, the waves tend to be out of phase. When stacked over time, the waves will interfere destructively with each other to a certain degree and will have more ringing than that of a single segment. This is illustrated in  FIG. 3  by the waveform  201  that is the result of simultaneous excitation of three point sources at distances of 11 ft, 11.2 ft and 11.4 ft (3.35 m, 3.41 m and 3.47 m) from a receiver. The abscissa is time in milliseconds and the ordinate is the signal amplitude in arbitrary units. The display in  FIG. 3  has been selected so that the shear wave arrival cannot be seen. It should be noted that receiver  121  is part of an array that includes additional receivers such as  127 . The array of receivers may be referred to as a receiver assembly. In one embodiment, six receivers are used, though more than six or less than six may be used. 
         [0026]    The present disclosure uses a phased array approach. The different segments of the transmitter are fired in such a time sequence that the farthest segment is fired first, the second one fired with a predefined time delay, and so on. Referring back to  FIG. 2 , the segments are fired with a time delay ΔT. By selecting an appropriate time delay (0.04 ms in this example), all the compressional waves arrive at the receiver at the same or approximately the same time. Stacking of the waves will produce a stronger signal. In the example shown, ΔT=Δz/V f , where Δz is the spacing between the segments and V f  is the formation P-wave velocity. This result of using this phased-array approach is shown in  FIG. 3  by  203 . As can be seen, the signal strength is much greater than in  201  where the different segments are fired simultaneously. The P-wave arrival  205  can easily be picked. It should be noted that an approximate value of the formation velocity is sufficient to provide this improvement. 
         [0027]    Turning now to  FIG. 4 , the entire wave train for the example of  FIG. 3  is illustrated. Note that the scale is compressed relative to that of  FIG. 3 . It can be seen that even though the time delays were chosen to emphasize the P-wave arrival, the S-wave arrival  301  can still be seen as can the fluid arrival  303 . 
         [0028]    An alternate embodiment of the disclosure is illustrated in  FIG. 5 . Shown therein is a transmitter  501  and an array of receivers (of which two— 511 ,  513 ) are shown. Each of the receivers comprises a plurality of segments, the signals from the segments being delayed relative to each other prior to summing by using suitable electronic circuitry or a processor (not shown). With either configuration ( FIG. 2  or  FIG. 5 ), the recorded signals are processed to determine formation P-wave velocities and, optionally, S-wave velocities. See, for example, U.S. Pat. No. 6,477,112 to Tang, the contents of which are incorporated herein by reference. As discussed therein, improved results are achieved by minimizing the noise contamination effects by maximizing the information redundancy in waveform data with multiple receivers. 
         [0029]    The determined velocity can be used in conjunction with the downhole or surface data for imaging of reflectors, determination or formation lithology, and determination off the fluid content of formations using known methods. 
         [0030]    The description above has been in terms of a device conveyed on a BHA on a drilling tubular into a borehole in the earth formation. The method and apparatus described above could also be used in conjunction with a logging string conveyed on a wireline into the earth formation. For the purposes of the present disclosure, the BHA and the logging string may be referred to as a “downhole assembly.” It should further be noted that while the example shown depicted the transmitter assembly and the receiver assembly on a single tubular, this is not to be construed as a limitation of the disclosure. It is also possible to have a segmented acoustic logging tool to facilitate conveyance in the borehole. 
         [0031]    The time delays may be implemented by a suitable firing circuit under microprocessor control. Implicit in the processing of the data is the use of a computer program implemented on a suitable machine readable medium that enables the processor to perform the control and processing. The machine readable medium may include ROMs, EPROMs, EAROMs, Flash Memories and Optical disks. The determined formation velocities may be recorded on a suitable medium and used for subsequent processing upon retrieval of the BHA. The determined formation velocities may further be telemetered uphole for display and analysis. 
         [0032]    The foregoing description is directed to particular embodiments of the present disclosure for the purpose of illustration and explanation. It will be apparent, however, to one skilled in the art that many modifications and changes to the embodiment set forth above are possible without departing from the scope and the spirit of the disclosure. It is intended that the following claims be interpreted to embrace all such modifications and changes.