Abstract:
A method and apparatus for determining formation parameters including a seismic array for receiving seismic waves at plurality of depth simultaneously, thereby enabling a determination of a formation velocity by using a difference in the seismic waves received by the various portions of the array.

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application is a non-provisional application of U.S. Provisional Patent Application 60/991,216, filed 29 Nov. 2007, the content of which is incorporated herein by reference for all purposes. 
     BACKGROUND OF THE DISCLOSURE 
     1. Field of the Invention 
     The present disclosure relates to techniques for acquiring downhole seismic data of a formation, and, more particularly, to techniques using a multi-level seismic tool to acquire seismic data simultaneously at multiple location or depths. 
     2. Background of the Related Art 
     Existing Borehole Seismic While Drilling tools contain seismic receivers with a highly accurate downhole clock. The seismic sensors are disposed in a drill collar to record borehole seismic data while drilling ceases, as shown in  FIG. 1 . The tool digitizes the received seismic signals or waves and puts the data into a circular buffer. In other words, as the tool is drilling seismic data is typically buffered in an on-going basis keeping only the most recent acquisitions. As soon as the tool recognizes the first break/indication of a desired seismic signal or cessation of drilling, the tool acquires data from a specified time before the first break or cessation in a predefined time window. Thus, the tool is able to record a seismic signal that was received during a period of time that is deemed to be the time window in which the relevant data should appear. The tool then stores the data with a time stamp based on the high precision clock. The tool then transmits the first break time, and possibly some data (possibly after data compression), to the surface by using a MWD telemetry system. Using the downhole first break time and the surface reference time, the travel time for seismic energy between the surface and downhole may then be computed. 
     Since seismic data cannot be acquired while drilling because of high noise, acquisition is performed each time drilling ceases. For example, when adding a new stand, which is typically three joints of a drill pipe. The typical length of a drill pipe joint is about 10 m and the length of a stand is therefore typically 30 m. This means that the seismic data is acquired at every 30 m. In contrast, conventional wireline borehole seismic measurements are acquired at 15 m intervals to optimize spatial aliasing in Vertical Seismic Profiling data. Therefore, in order to obtain the benefits of the 15 m intervals using conventional single level or single module while drilling seismic tool, the drilling has to be stopped in the middle of running the stand, just to take the measurement. Such an operation is not preferred because of rig time is expensive and additional downtime or non-drilling time is costly. 
     A further limitation of the current Borehole Seismic While Drilling tools is the clock drift that occurs when the tool has been drilling for an extended period of time. In other words, once a tool has been drilling for several days (three or more for example), the downhole clock becomes desynchronized from the uphole or reference clock, the difference in the synchronization being the drift. This drift then causes inaccuracies in the interpretation of the received data. Currently, in order to compensate or eliminate the drift, the tool is brought back to where a previous checkshot was completed when the clocks were still synchronized, so that the clocks can be recalibrated or resynchronized. Since the drill pipe has to be pulled up, or possibly some joints of the drill pipe have to be removed at the surface to lift the tool to the depth where the previous checkshot was performed, the clock calibration requires rig downtime which, again, is expensive. 
     SUMMARY OF THE DISCLOSURE 
     According to one exemplary embodiment, an apparatus including a drill string, a drill bit and first and second seismic modules having seismic sensors for receiving seismic waves is disclosed. The drill string comprises at least a first and a second section of drill pipe, with the drill bit being disposed at a distal end thereof. The first seismic module is disposed near the distal end of the drill string, between the drill bit and the first section of drill pipes, and the second seismic module is disposed between the first and the second section of drill pipe. 
     According to another exemplary embodiment, a method of obtaining formation parameters using a seismic tool array is disclosed. The method includes receiving seismic waves with a plurality of seismic modules, wherein a first and a second of the plurality of modules are disposed on a drill string and are separated by at least one section of drill pipe; and determining a parameter of the formation by using the seismic wave information received by the first and the second modules. 
     According to another exemplary embodiment, a method of obtaining formation parameters using a seismic tool array is disclosed. The method includes providing a seismic tool array having a least a reference clock and a downhole clock; propagating a first set of seismic waves into a subterranean formation at a first time, wherein the clocks are synchronized; receiving the first set of seismic waves with a plurality of seismic modules, wherein a first and a second of the plurality of modules are disposed on a drill string and are separated by at least one section of drill pipe; propagating a second set of seismic waves into the subterranean formation at a second time, wherein the clocks are desynchronized; receiving the second set of seismic waves with the plurality of seismic modules; and determining a velocity of the formation by using a difference in the seismic waves received by the first and the second tool at the first and second times. 
     According to yet another exemplary embodiment, an apparatus for determining formation parameters using a plurality of modules is disclosed. The apparatus includes a drill string that includes a first section of wired drill pipe and a second section of non-wired drill pipe, having a drill bit disposed at a distal end thereof. The apparatus further includes a first module disposed near the distal end of the drill string, between the drill bit and the first section of drill pipe, and a second module disposed between the first and the second section of drill pipe, wherein the modules include sensors for receiving one of a formation and borehole parameter. 
    
    
     
       DESCRIPTION OF THE DRAWINGS 
       The accompanying drawings illustrate certain embodiments and are a part of the specification. Together with the following description, the drawings demonstrate and explain some of the principles of the present disclosure. 
         FIG. 1  is a schematic side view of a while-drilling tool with drill pipe; 
         FIG. 2  is a schematic side view of a drilling rig and partial while-drilling tool disposed in a wellbore; 
         FIG. 3  is a cross-sectional view of an exemplary wired drill pipe that may be used in one embodiment of the disclosure; 
         FIG. 4  is a schematic side view a downhole seismic array of the present disclosure; 
         FIG. 5  is a cross-sectional side view of one exemplary embodiment of a seismic module of the downhole seismic array of  FIG. 4 ; 
         FIG. 6  is a flowchart of one exemplary drilling operation; 
         FIGS. 7A-8B  are side views of various types of exemplary seismic measurement techniques usable with the present disclosure; 
         FIG. 9  is a cross sectional view along line A-A of  FIG. 5  illustrating one possible geophone arrangement; 
         FIG. 10  is a cross sectional view along line A-A of  FIG. 5  illustrating another possible geophone arrangement; 
         FIG. 11  is a cross sectional view along line B-B of  FIG. 5  illustrating one possible hydrophone arrangement; 
         FIG. 12  is a side view of a drill string at two depths; 
         FIG. 13  is a side view of two checkshots at two different depths; 
         FIG. 14  is a Time v. Depth chart of the checkshots of  FIG. 13 ; 
         FIG. 15  is a Time v. Depth chart depicting drift of the clock by subtracted from the second checkshot time and calibrated checkshot time can be obtained; 
         FIG. 16  is a Time v. Depth chart depicting drift determination by polynomial fitting; 
         FIG. 17  is a Time v. Depth chart illustrating when a tool interval is less than a shot interval; 
         FIG. 18  is a Time v. Depth chart depicting that clock drift may be compensated by shifting later data to match the checkshot time at the extrapolated depth; 
         FIG. 19  is a Time v. Depth chart depicting an interval velocity in every checkshot that is determined by the downhole break time difference between two levels divided by the difference in the depths; 
         FIG. 20  is a Velocity v. Depth chart depicting an interval velocity that may be defined at the middle depth of two depths of acquisition; 
         FIG. 21  is a Time v. Depth chart depicting an interval velocity using three modules; and 
         FIG. 22  is a Time v. Depth chart depicting a Time-Depth curve obtained by checkshot and an integrated velocity log. 
     
    
    
     Throughout the drawings, identical reference numbers and descriptions indicate similar, but not necessarily identical elements. While the principles described herein are susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and will be described in detail herein. However, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed. Rather, the disclosure includes all modifications, equivalents and alternatives falling within the scope of the appended claims. 
     DETAILED DESCRIPTION 
     So that the above recited features and advantages of the present disclosure can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to the embodiments thereof that are illustrated in the accompanied drawings. It is to be noted, however, that the drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. 
       FIG. 2  illustrates a wellsite system in which the present invention can be employed. The wellsite can be onshore or offshore. In this exemplary system, a borehole  11  is formed in subsurface formations by rotary drilling in a manner that is well known. Embodiments of the invention can also use directional drilling or drilling with a mud motor, as will be described hereinafter. 
     A drill string  12 , that includes a plurality of drill pipes  101 , is suspended within the borehole  11  and has a bottom hole assembly  100  which includes a drill bit  105  at its lower end. The surface system includes platform and derrick assembly  10  positioned over the borehole  11 , the assembly  10  including a rotary table  16 , kelly  17 , hook  18  and rotary swivel  19 . The drill string  12  is rotated by the rotary table  16 , energized by means not shown, which engages the kelly  17  at the upper end of the drill string. The drill string  12  is suspended from a hook  18 , attached to a traveling block (also not shown), through the kelly  17  and a rotary swivel  19  which permits rotation of the drill string relative to the hook. As is well known, a top drive system could alternatively be used. The wellsite system also includes a control unit  25  communicably coupled to a tool or source  14 , as it may be, has a reference or surface clock  27  for, among other things, tracking and logging the times at which the source(s)  14  are activated. 
     In the example of this embodiment, the surface system further includes drilling fluid or mud  26  stored in a pit  27  formed at the well site. A pump  29  delivers the drilling fluid  26  to the interior of the drill string  12  via a port in the swivel  19 , causing the drilling fluid to flow downwardly through the drill string  12  as indicated by the directional arrow  8 . The drilling fluid exits the drill string  12  via ports in the drill bit  105 , and then circulates upwardly through the annulus region between the outside of the drill string and the wall of the borehole, as indicated by the directional arrows  9 . In this well known manner, the drilling fluid lubricates the drill bit  105  and carries formation cuttings up to the surface as it is returned to the pit  27  for recirculation. For generating and propagating a seismic signal  15 , such as seismic waves, the surface system also includes a seismic source  14 , that may be an air gun, vibrator, dynamite, or other sources know in the art. The present disclosure may also be used with passive sources, such as natural fracturing and induces acoustic signals. 
     The bottom hole assembly  100  of the illustrated embodiment may includes a logging-while-drilling (LWD) module  120 , a measuring-while-drilling (MWD) module  130 , a roto-steerable system and motor  150 , and drill bit  105 . 
     The LWD module  120  is housed in a special type of drill collar, as is known in the art, and can contain one or a plurality of known types of logging tools, such as a seismic tool. It will also be understood that more than one LWD and/or MWD module can be employed, e.g. as represented at  120 A. (References, throughout, to a module at the position of  120  can alternatively mean a module at the position of  120 A as well.) The LWD module includes capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment. In the present embodiment, the LWD module includes a seismic measuring device. 
     The MWD module  130  is also housed in a special type of drill collar, as is known in the art, and can contain one or more devices for measuring characteristics of the drill string and drill bit. The MWD tool further includes an apparatus (not shown) for generating electrical power to the downhole system. This may typically include a mud turbine generator powered by the flow of the drilling fluid, it being understood that other power and/or battery systems may be employed. In the present embodiment, the MWD module may includes one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device. 
     In an alternate embodiment, the BHA may be connected to the surface with wired-drill-pipe (WDP) as is illustrated in  FIG. 3 . More specifically, reliably conveying data and/or power along a drill string has become an increasingly important aspect of wellbore drilling operations. In particular, oil companies have become increasingly reliant on the use of real-time downhole information, particularly information related to the conditions associated with the drill bit  105 , the BHA  100 , and a formation F, to improve the efficiency and accuracy of their drilling operations. 
     Numerous types of telemetry systems are commonly used in connection with MWD and LWD systems. For example, mud-pulse or mud siren telemetry systems use modulated acoustic waves in the drilling fluid to convey data or information between the BHA  100  and the surface equipment. However, mud-pulse telemetry systems have a relatively low data transmission rate of about 0.5-12 bits/second and, thus, substantially limit the amount of information that can be conveyed in real-time and, as a result, limit the ability of an oil company to optimize their drilling operations in real-time. 
     In contrast to mud-pulse, a wired drill pipe system can convey data at a relatively high rate along the length of a drill string. One example of a wired drill pipe system  200  is shown in  FIG. 3 , which shows three interconnected pipe sections  201 ,  201   a ,  201   b . The upper pipe section  201   a  is connected to the center pipe section  201  by mating the pin end  220   a  of the upper section  201   a  with the box end  210  of the center pipe section  201 . Likewise, the center pipe section  201  is connected with the lower pipe section  201   b  by mating the pin section  220  of the center pipe section  201  with the box end  210   b  of the lower pipe section  201   b . In this manner, an entire drill string may be created by mating adjacent sections of pipe. 
     The center section  201  includes a communicative coupler  211  in the box end  210  of the pipe section  201 . When the upper pipe section  201   a  and the center pipe section  201  are connected, the communicative coupler  211  in the center pipe section is located proximate a communicative coupler  221   a  in the box end  220   a  of the upper pipe section  201   a . Likewise, a communicative coupler  221  in the pin end  220  of the center pipe section  201  may be proximate a communicative coupler  211   b  in the box end  210   b  of the lower pipe section  201   b.    
     A wire  202  in the center pipe section  201  spans the length of the pipe section  201  and is connected to each communication coupler  211 ,  221 . Thus, data and/or power that is transferred to a pipe section from an adjacent pipe section may be transferred through the wire to the communicative coupler at the opposing end of the pipe section, where it may then be transferred to the next adjacent pipe section. 
     The communicative coupler may be any type of coupler that enables the transfer of data and/or power between pipe sections. Such couplers include direct or galvanic contacts, inductive couplers, current couplers, and optical couplers, among others. 
     Regardless of the types of drill pipe that is used, be it WDP as is shown in  FIG. 3  or regular drill pipe as is illustrated in  FIG. 2 , the presently disclosed seismic array  310  may include at least one seismic module in the BRA  100  (BHA module), such as the module  120  and/or  120   a  for example, and one or more additional seismic modules (in-pipe modules)  120   b ,  120   c  . . .  120   n  disposed in the drill string  12  as is illustrated in  FIG. 4 . The in-pipe modules be may be separated by a section of drill pipe  301  that includes only one drill pipe section that is approximately 10 meters long, or may be separated by a section of drill pipe  301  that includes a plurality of drill pipes, such as a stand that is approximately 30 meters long. 
     The in-pipe module  120   c , as illustrated in  FIG. 5 , includes an upper end  121  having a box joint connection for connecting to the pipe section  301   c  and a lower end  123  having a pin joint connection for connecting to the pipe section  301   b . Other methods or means of connecting drill pipe known in the art may be utilized for connecting the in-pipe modules to the drill pipe  301  and is, therefore, contemplated herein as well As shown in the cross-sectional view of the in-pipe module of  FIG. 5 , the modules may include a plurality of seismic sensors  130 , such as geophones  130   a  and a hydrophone  130   b . The geophones may be grouped in a set of three, wherein one is oriented vertically and the other two are oriented horizontally relative to the direction of the tool. The hydrophone  130   b  may be mounted around the modules  120  to be exposed to a fluid pressure in the annulus or borehole. Electronics  125  and a power source  127  may be packaged inside the modules  120 . The power source  127  may include a battery, a turbine, other power generating device, and/or may receive power through a WDP system. A clock  131  is also disposed in at least one of the modules (BHA and/or in-pipe) that is communicably coupled to the sensors  130  and electronics  125  for tracking and logging the times at which the seismic signals are received. When using WDP, the seismic data may be sent via the WDP infrastructure to the BHA for processing. However, other methods for communicating the seismic data to the BHA, or for permitting communication between the modules  120 , may be accomplished by electromagnetic, acoustic or mud pulse telemetry, or any other telemetry means know to those of skill in the art. Disposed in the center of the modules  120  is a passageway  129  to facilitate the flow of mud from the surface of to the drill bit  105 . 
     In one exemplary operation  320 , as is illustrated in  FIG. 6  (and with reference to  FIG. 2 ), the drilling process begins with the lowering of the BHA  100  into the wellbore  11 . Once the BHA  100  is lowered, a first drill pipe section  301  may be connected to the BHA  100  ( 323 ). As noted earlier, typically the length of a single drill pipe is about 10 m and the length of a stand (e.g. three drill pipes connected) is 30 m. Thus the operation, depending on the need of the spacing of the modules  120 , may see drill pipe sections  301  having various lengths separating the in-pipe modules  120 . Once the desired length of drill pipe has been added to the BHA  100 , the first in-pipe module  120   b  may be connected to the pipe section  301   a  ( 325 ). The first in-pipe module  120   b  would then be connected to the second pipe section  301   b  ( 327 ), followed by more in-pipe modules  120  and pipe sections  301  as needed ( 329 ). As is know to those with skill in the art, as the drill string  12  is being created, drilling may occur by rotation of the drill string  12 . During drilling various times throughout the drilling process, the drilling may be temporally stopped or suspended ( 331 ) to acquire seismic signal data with the modules  120 . The seismic data will be received by the seismic sensors  130  ( 333 ), from seismic waves  15  generated by the seismic source  14  ( 335 ). Using this or a similar basic drilling process, various types of seismic measurements or measurement processes can be accomplished, some of which are described below. 
     For example,  FIG. 4  illustrates a seismic array  310  which can be used as a part of an LWD tool suite disclosed in P. Breton et al., “Well Positioned Seismic Measurements,” Oilfield Review, pp. 32-45, Spring, 2002, incorporated herein by reference. The seismic array  310  has a plurality of receivers/modules  120 , as depicted in  FIGS. 7A-8B , and can be employed in conjunction with a single seismic source at the surface (as depicted in  FIGS. 7A and 8A ) or a plurality of seismic sources at the surface (as depicted in  FIGS. 7B and 8B ). Accordingly,  FIG. 7A , which includes reflection off a bed boundary, and is called a “zero-offset” vertical seismic profile arrangement;  FIG. 7B , which includes reflections off a bed boundary, and is called a “walkaway” vertical seismic profile arrangement (although multiple lines to all receivers are not shown for clarity);  FIG. 8A , which includes refraction through salt dome boundaries, and is called a “salt proximity” vertical seismic profile; and  FIG. 8B , which includes some reflections off a bed boundary, and is called a “walk above” vertical seismic profile. 
     The present techniques may be used with the above and other measurement processes to obtain seismic related formation parameters. Specifically, with an array of in-pipe modules  120  or sensors  130  as described in  FIGS. 4 and 5 , many levels of seismic sensors  130  or in-pipe modules  120  can be deployed in a drill-string with a large or desired spacing. 
     Motion Attenuation 
     As the drill string  12  obtains its length, the drill string  12 , and hence the modules  120 , may encounter undesired noise. Specifically, for a long cylindrical body (such as the drill-string  12 ) the dominant modes acting on the body may be a tortional mode and a bending mode. However, tortional and bending modes are not present in the pure plane wave propagation of seismic energy and can be considered as noise. This means that if the tortional and bending modes acting on the string  12  can be isolated and removed from the received seismic signal, then a more accurate or noise-less signal can be achieved. To accomplish this, the geophones  130   a  can be arranged in the annulus of the tool or module  120  to measure tensor components of seismic waves and undesired noise, as shown in  FIG. 9 . 
     As such, using the geophone configuration shown in  FIG. 9 , the seismic signal received in the X and Y directions can be obtained by summing the values obtained by two of the geophones from opposite sides of the drill collar or module  120  as:
 
 X=X 1+ X 2
 
 Y=Y 1+ Y 2
 
Using the above summations allows for the rotational component of the seismic signal to be cancelled. Specifically, the rotational component can then be obtained by subtracting the values of geophones located on opposite side of the drill collar or module  120  from the others, such as:
 
 R =( X 1− X 2)+( Y 1− Y 2)
 
The summation can be done either directly at the geophones  130   a  output or numerically after digitization. The vertical component can be obtained by summing the four vertical geophones  130   b  of  FIG. 9  as:
 
 Z=Z 1+ Z 2+ Z 3+ Z 4
 
The bending components are:
 
 Zx =( Z 2− Z 1)+( Z 3− Z 4)
 
 Zy =( Z 1− Z 3)+( Z 2− Z 4)
 
     It is also possible to reduce the number of geophones and arrange them at every 120 degrees around the cylindrical tool as shown in  FIG. 10 . In this arrangement,
 
 X=R 1+( R 2− R 3)—horizontal component
 
 Y=R 2+ R 3—horizontal component
 
 R=R 1+ R 2+ R 3—rotational component
 
 Z=Z 1+ Z 2+ Z 3—vertical component
 
 Zx =( Z 2− Z 1)—bending component
 
 Zy=c ×( Z 1+ Z 2)− Z 3—bending component
 
Where c is a constant determined from the locations of the geophones.
 
     Furthermore, the cylindrical hydrophone can be segmented into four pieces as shown in  FIG. 11  to form gradients. By subtracting it received signals, the direction of wave propagation may be determined. 
     The X component of a hydrophone signal is obtained by the pressure gradient as:
 
 X=H 2− H 4
 
The Y component is:
 
 Y=H 1− H 3
 
The pressure is then the sum of all hydrophones as:
 
 P=H 1+ H 2+ H 3+ H 4
 
Clock Calibration
 
     Referring again to  FIG. 4 , with the two or more seismic modules  120  or with the seismic array  310  of  FIG. 4 , clock calibration may be accomplished as is illustrated in  FIG. 12 . Specifically, when drilling is stopped at Depth  1 , checkshot A is performed by activating the source  14  at the surface and receiving the source signal with sensor S 1 , as shown on the left in  FIG. 12 . The time at which the source is activated is the Surface time as measured with the surface or reference clock, and the time at which the signal is first received by the sensor S 1  is the Break time as measured with the downhole clock. If another checkshot (B) is acquired at Depth  2  for sensor S 1  (the depth of sensor S 1  is at Depth  2 ), S 2  acquires checkshot at Depth  1 , which is now at the same depth at which S 1  received the first checkshot. Checkshot A at Depth  1  with S 1  should be the same as Checkshot B at Depth  1  with S 2 . If there is any difference between checkshot A and checkshot B, in the time it took for the signal to travel from the surface to the sensor (first S 1  then S 2 ) at Depth  1 , then that difference is attributable to the drift in either the uphole or downhole clock or both. 
     Practically speaking, however, it may not be possible to repeat checkshots at the same depth (as illustrated in  FIG. 13 ) and there could be depth errors or differences between two checkshots, resulting in some overlap in the depth and data received. This can also be seen in the Time v. Depth graph of  FIG. 14 , which illustrates a line  350  from (d 1 , T 1 ) to (d 2 , T 2 ) and a line  352  from (d 3 , T 3 ) to (d 4 , T 4 ). By taking the slope of the line  350  and the slope of line  352 , the velocity of the formation is obtained between those respective depths. Therefore, when placing the information of  FIG. 13  into the graph of  FIG. 14 , it can be seen that the velocity determined at d 3  (from line  352 ) is different from the interpolated velocity  354  at d 3  from line  350 . 
     Once again, this discrepancy is the drift of the clock or the difference in the uphole and downhole over time as they become desynchronized. One way of dealing with this drift is to subtract the time value corresponding to the drift from the second checkshot time or line  352 , such that a calibrated checkshot time can be obtained, as shown in  FIG. 15 . In other words, by subtracting the drift of the clock, the velocity at d 3  obtained with line  352  can be brought to the interpolated velocity at d 3  obtained with line  350  at  354 . Alternatively, the drift as shown in  FIG. 14 , may also be subtracted by a polynomial fitting resulting in the graph as shown in  FIG. 16 . Specifically, the checkshot times at d 3  and d 4  are shifted to minimize least square errors in second order polynomial fitting. 
     In another alternate embodiment, other techniques may be used to calibrate the clocks or compensate for the clock drift. For example, as shown in  FIG. 17 , when the second checkshot (d 3 , d 4 ) is wholly beneath the first checkshot (d 1 , d 2 ), such that there is no overlap in the respective velocities  362  and  360  as shown in  FIG. 17 , the clock drift appears in the extrapolation of the two consecutive checkshots. More specifically, by extrapolating the velocity  360  toward d 3  and extrapolating the velocity  362  toward d 2 , a drift may be obtained by calculating the difference in the clock time at a point between d 2  and d 3 , which in this case is located at (d 2 +d 3 )/2. The clock drift can then be compensated for by shifting the later data ( 362 ) to match the checkshot time at the extrapolated depth, as shown in  FIG. 18 . 
     Thus, if the same seismic wave is detected by multiple levels or modules  120  at the same time, the velocity is still valid even if the downhole (uphole or both) clock drifts as long as the acquisition among multiple levels or modules  120  is synchronized. The interval velocity of the checkshots, which is the velocity between two modules  120  in this embodiment, may be determined by the downhole break time difference between two depths of the modules  120  divided by the difference in the depths, as shown in  FIG. 19 . In other words, by determining a slope of a line  366  between (d 1 , d 2 ), a slope of a line  368  between (d 3 , d 4 ), etc. the velocity of the formation disposed between those respective depth can be determined. 
     This interval velocity may then be defined at a middle depth of two depths of acquisition, as shown in  FIG. 20 , and the velocity may be plotted against the depth. More specifically, the velocity between d 1  and d 2  may be determined by calculating the slope of line  366 . Similarly, the velocity between d 3  and d 4  may be determined by calculating the slope of line  368 . Before or after the velocity determination, the drift of the clock may also be compensated for using any of the previously mentioned or other methods. Regardless, once velocities  366   a ,  368   b  of lines  366 ,  368  have been determined, the velocities may be plotted along with their respective depths at which that velocity was determined in the velocity v. depth graph of  FIG. 20 . 
     The above description has been giving with the exemplary embodiment of using two modules  120  in the determination of the velocity and/or the drift of the clocks. However, it is contemplated herein that the array  310  may have three, four, or many more number of modules that would take part in the determination. For example, in a three module embodiment as shown in  FIG. 21 , the three modules may acquire a first shot t 1 , t 2 , and t 3  at depths of d 1 , d 2 , and d 3  respectably. Some time after, as the drilling progresses, the modules may acquire a second shot t 4 , t 5 , and t 6  at d 4 , d 5 , and d 6 . Once again, drift of the clock(s) may occur. To overcome the drift, the first checkshot times may be expressed in a polynomial (a second order polynomial is used in this instance) as:
 
 t=a   0   +a   1   d+a   2   d   2  
 
From the fist shot,
 
 t   1   =a   0   +a   1   d   1   +a   2   d   1   2  
 
 t   2   =a   0   +a   1   d   2   +a   2   d   2   2  
 
 t   3   =a   0   +a   1   d   3   +a   2   d   3   2  
 
Assuming that the distance between three tools are the same for simplicity sake,
 
Δ= d   2   −d   1   =d   3   −d  
 
Then the coefficients, a 0 , a 1 , and a 3  are found to be
 
               a   0     =       t   2     -         (       t   3     -     t   1       )       2   ⁢           ⁢   Δ       ⁢     d   2       +         (       t   1     -     2   ⁢           ⁢     t   2       +     t   3       )       2   ⁢           ⁢     Δ   2         ⁢     d   2   2                       a   1     =         (       t   3     -     t   1       )       2   ⁢           ⁢   Δ       -         d   2     ⁡     (       t   1     -     2   ⁢           ⁢     t   2       +     t   3       )         Δ   2                       a   2     =       (       t   1     -     2   ⁢           ⁢     t   2       +     t   3       )       2   ⁢           ⁢     Δ   2               
The formation velocity is the gradient of the polynomial
 
                 ⅆ   t       ⅆ   d       =       a   1     +     2   ⁢           ⁢     a   2     ⁢   d             
The velocity at middle depth d 2  is evaluated as
 
     
       
         
           
             
               
                 
                   ⅆ 
                   t 
                 
                 
                   ⅆ 
                   d 
                 
               
               ⁢ 
               
                 ❘ 
                 
                   d 
                   = 
                   
                     d 
                     2 
                   
                 
               
             
             = 
             
               
                 
                   t 
                   3 
                 
                 - 
                 
                   t 
                   1 
                 
               
               
                 2 
                 ⁢ 
                 
                     
                 
                 ⁢ 
                 Δ 
               
             
           
         
       
     
     The result is the same as in case of two tools for the second order polynomial. The velocity is accurate, since downhole tools are synchronized; however, the clocks would be altered or desynchronized. Then shift the second shot data by Dt. Define the drift time Dt to optimize errors between the first and second checkshots. 
     For example, define d 7  at middle of d 3  and d 4  and evaluate checkshot time t 7  from the first shot by using the polynomial coefficients, a 0 , a 1  and a 2 .
 
 t   7   =a   0   +a   1   d   7   +a   2   d   7   2  
 
In a similar fashion, the second shot can be expressed in another polynomial,
 
 t   7   −Dt=b   0   +b   1   d   7   +b   2   d   7   2  
 
b 0 , b 1 , and b 2  are coefficients found from the second shot and Dt is the drift. Then the drift Dt may be found as
 
 Dt =( a   0   +a   1   d   7   +a   2   d   7   2 )−( b   0   +b   1   d   7   +b   2   d   7 )
 
     In light of the above, regardless of the umber of modules that are present, it becomes possible to obtain an accurate velocity v. depth information and accurate time v. depth information, even if the clock has drift or are generally desynchronized. In one embodiment, by integrating and correlating the velocity log to data obtained when the clocks were still accurate or synchronized, accurate information can be obtained as illustrated in  FIG. 22 . 
     However, even if the clock drift can be calibrated and/or compensated for, it is still important to synchronize the multi-level seismic arrays relative to each other during a multi-level acquisition. This may be accomplished in several ways and will depend on the means by which the modules  120  are connected or communicate. For example, a seismic array  310  connected via WDP may use the inherent ability for the modules  120  to commutate with each other and/or with the BHA for example ( FIG. 4 ). The modules  120  of the array  310 , once again regardless of the connection means, do not require the ability of being able to communicate with the surface, as long as they can communicate or send information among themselves or to one another. Other means of communication between the modules  120  or from one module  120  to another or from one module  120  to the BHA contemplated herein, include, but are not limited to, drill-string waves, tube waves, downhole source such as the drillbit, mud pressure, and jars. 
     It will be understood from the foregoing description that various modifications and changes may be made in the preferred and alternative embodiments of the present invention without departing from its true spirit. In addition, this description is intended for purposes of illustration only and should not be construed in a limiting sense.