You are an expert at summarizing long articles. Proceed to summarize the following text:

You are an expert at summarizing long articles. Proceed to summarize the following text: 
BACKGROUND OF THE INVENTION 
       [0001]    1. Field of the Invention 
         [0002]    The invention relates generally to devices and methods for releasing a stuck portion of a tubular string from within a wellbore and thereby translating tubular members within a wellbore. In particular aspects, the invention relates to tubular string arrangements which incorporate vibratory devices within the string itself. In other aspects, the invention relates to the use of rotational vibration devices in association with tubular strings in wellbores to help prevent and respond to sticking conditions. 
         [0003]    2. Description of the Related Art 
         [0004]    The process of drilling through open hole at bottom of cased wellbore requires that the drill string pass through multiple layers, or zones, of formation. Depending upon the composition, some of these layers are problematic because they do not hold their drill diameter well. They are prone to caving in and sloughing off. The drill string tends to becomes stuck in these areas. This problem is complicated when portions of the wellbore are deviated or even horizontal as lower portions of the drill string will tend to contact the side of the wellbore and the weight of the drill string will create increased friction and drag to inhibit movement of the drill string along the wellbore, increasing the likelihood that the drill string will become stuck. 
         [0005]    It is noted that the problems of sticking is not unique to drill strings and, in fact, is inherent in other varieties of tubular strings used in wellbores, such as casing and liner drilling strings, work strings, and production strings, whether used in cased or uncased bores. Sticking can occur during run-in as well as retrieval of a tubular string from a wellbore. 
         [0006]    Attempts to free conventional tubular strings from a stuck condition are often done using a set of impact jars that are translated through the drill string to the total depth and then engaged and actuated to try to unstick the drill string. However, if the sticking zone is significantly distant (i.e., above) the location of effective jarring, the jar attempt may fail. In these cases, it would be desirable to locate a vibratory device proximate the sticking zone in order to effectively unstick the string, as vibration is effective in loosening surrounding soils or debris that may be causing the tubular string to be stuck. In addition, vibration is useful in overcoming frictional jams within the wellbore. However, there are practical difficulties in placing an effective vibration device close to the stuck location. The flowbore defined within a drill string is generally too small to run in an effective vibration device. 
         [0007]    U.S. Patent Publication No. US 2005/0257931 describes a method and apparatus for helping to remove a stuck object in a wellbore wherein a tubular assembly includes a work string with a vibratory apparatus that may have been incorporated therein before its initial tripping into the wellbore. However, this system may not be sufficient in all situations to free a stuck string. 
         [0008]    The present invention addresses the problems of the prior art. 
       SUMMARY OF THE INVENTION 
       [0009]    The invention provides devices and methods for translating casing within a wellbore and, as a result, effectively freeing a stuck tubular string within a wellbore. In a preferred embodiment, multiple vibrator devices are incorporated into a tubular string, such as a drill string. Each of the vibratory devices may be turned on or off independently, as needed, to help effectively free the tubular string from a stuck condition. 
         [0010]    In a preferred embodiment, each of the vibrators is a rotary vibrator device that can be incorporated into the tubular string and, where required, provide an open central flowbore which will allow drilling mud, tools, and the like to be passed through the vibrator so that normal operations need not be interrupted by operation of the vibrator. The vibrator includes a housing that encloses a rotary vibratory element, a motor to rotate the vibratory element, and a power source. In addition, the vibrator includes an actuation mechanism for selectively starting and stopping the motor. In one embodiment, pressure pulse identification is used to communicate with the vibrators. In this embodiment, each vibrator has a receiver adapted to receive a specific pressure pulse activation signal that is provided from the surface of the wellbore. In a further embodiment, each of the vibrators is provided with a detector for detecting signals indicative of wellbore conditions. The signals may be MWD (measurement-while-drilling) or LWD (logging-while-drilling) pulsed signals of a type known in the art. 
         [0011]    In operation, a tubular string is constructed having one or more vibrators positioned within. In a preferred embodiment, a plurality of vibrators are incorporated into the tubular string at predetermined intervals. Should the tubular string become struck during normal operation in the wellbore, the vibrators incorporated therein are selectively actuated to help free the tubular string from its stuck condition. To do this, it is preferred that signals be sent from the surface of the wellbore to determine the approximate location of the point at which the tubular string is stuck. Once the location of the stuck portion of the tubular string is determined, the vibrator or vibrators that are located proximate the sticking point are actuated to create one or more vibrations proximate the sticking point. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0012]      FIG. 1  is a side, cross-sectional view depicting an exemplary wellbore containing a drill string with a plurality of vibratory assemblies constructed in accordance with the present invention. 
           [0013]      FIG. 2  is a side, cross-sectional view of an exemplary vibratory device used within the vibratory assembly shown in  FIG. 1 . 
           [0014]      FIG. 3  is an isometric view of an exemplary vibratory element used within the vibratory device shown in  FIG. 2 . 
           [0015]      FIG. 4  is a top view of the vibratory element shown in  FIG. 3 . 
       
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
       [0016]      FIG. 1  illustrates a wellbore  10  that has been drilled from drilling rig  12  on the surface  14  downward through earth  16  and formation zones  18 ,  20 ,  22 . The wellbore  10  has a deviated portion  24 . It is noted that, while the deviated portion  24  is shown as being substantially horizontal, it may be angled in other directions as well. The wellbore  10  has a cased portion  26  proximate the surface  14  and an uncased portion  28 . 
         [0017]    A tubular string in the form of a drill string  30  is disposed within the wellbore  10  and includes a plurality of drill string sections  32 ,  34 ,  36 ,  38 ,  40  that are secured together in a manner well known in the art. An axial fluid flowbore  42  is defined along the length of the drill string  30 . The lower end of the drill string  30  carries a bottom hole assembly (BHA)  44  with drill bit. Vibration subs  46 ,  48 ,  50 ,  52  are incorporated within the drill string  30  in between each adjacent sections of the drill string  30 . Although  FIG. 1  illustrates a vibration sub disposed between each of the drill string sections  32 ,  34 ,  36 ,  38  and  40 , this need not be the case. It is preferred that vibration subs be located within the drill string  30  at predetermined intervals which correspond to expected wellbore conditions at the depths at which those portions of the drill string will be located. Thus, there may be long stretches of drill string that have no vibration subs incorporated in them and other stretches of drill string that have a number of vibrators located therein. In particular embodiments, the surface  14  will include a pressure pulse generator  54 , of a type known in the art for generating fluid pulses within the fluid flowbore  42  of the drill string  30 , and a controller  56  operably associated with the generator  54 . 
         [0018]      FIG. 1  illustrates a stuck position  58  in the uncased well portion  28  which has resulted from the formation  20  surrounding the wellbore  10  caving in and partially burying the drill string  30 . 
         [0019]      FIG. 2  depicts an exemplary vibratory assembly  60 , which may be representative of each of the vibration subs  46 ,  48 ,  50 ,  52  incorporated into the drill string  30 . The vibratory assembly  60  includes a housing  62  with upper and lower axial ends  64 ,  66 , respectively. The housing  62  defines a central axial flowbore  68  that extends through the housing  62 . The upper end  64  is provided with a box-type threaded connection while the lower end  66  is provided with a pin-type threaded connection so that the vibratory assembly  60  may be threadedly affixed to neighboring components in the drill string  30 . A compartment  70  is formed within the vibratory assembly  60 . In  FIG. 2 , the compartment  70  is an annular space formed between the housing  62  and cover member  72 . The compartment  70  houses a power source  74 , which may be a battery and an electric motor  76 , which is operably associated with the power source  74 . The motor  76  turns drive gearing  78  to rotate vibratory element  80  within the compartment  70 . 
         [0020]      FIGS. 3 and 4  illustrates an exemplary vibratory element  80  apart from the other components. The vibratory element  80  includes an annular ring body  82  that is heavier upon one half  84  of the body  82  than the other half  86 . In the depicted embodiment, the half  84  is heavier than the half  86  because of the presence of a plurality of blind bores  88  that are disposed within the half  86 , thereby removing mass from that half. Rotation of the vibratory element  80  within the compartment  70  will be eccentric due to the off-center location for the center of mass for the element  80 . When rotated by the motor  76  and the gearing  78 , the vibratory element  80  will cause the housing  62  to wobble or vibrate due to the eccentric motion of the element  80 . It is noted that one can create an eccentric vibratory element in a number of alternative ways as well. For example, two halves of an annular element could be made from two separate materials, with one of the materials being of a lighter weight than the other half. Additionally, eccentric vibration of the housing  62  could be created by, for example, rotation of a heavy fluid within an annular chamber within the housing  62  could cause a similar vibratory effect. 
         [0021]    Referring once again to  FIG. 2 , it is noted that a fluid conduit  90  is formed within the housing  62  of the vibratory assembly  60  and extends from the central flowbore  68  to the compartment  70 . A sensor  92  is located within the compartment  70  and is associated with the fluid conduit  90  so that fluid from the flowbore  68  will be transmitted to the sensor  92  during typical operation of the drill string  30 . The sensor  92  is selected to detect MWD or LWD signals within a drilling mud column passing through the flowbore  68 . The sensor  92  is operably associated with a programmable processor/controller  94 . The processor/controller  94  is also operably interconnected with the power source  74  and the motor  76 . 
         [0022]    If, during normal operation, the drill string  30  should become stuck within the wellbore  10 , one or more of the vibratory subs  46 ,  48 ,  50 ,  52  is operated to free the drill string and allow drilling to continue. In one embodiment, the subs  46 ,  48 ,  50 ,  52  are selectively chosen and actuated from the surface  14 . First, the drilling operation is halted and an attempt is made to determine the approximate location of the sticking point  58  within the wellbore  10 . This can be done, for example, by pulling upward on the drill string and measuring the amount of stretch that the upper portion of the drill string  30  provides. Using a measured or approximated modulus of elasticity for the drill string  30 , the approximate distance along the drill string  30  to the stuck point  58  can be determined. Thereafter, the vibratory sub or subs that are located closest to the stuck point  58  are operated to cause vibration of the drill string  30  proximate the stuck point  58 . In the instance depicted in  FIG. 1 , the vibratory sub  52  would be actuated. 
         [0023]    In this method of operation, each of the vibratory subs  46 ,  48 ,  50 ,  52  can be selectively operated using a distinct pulsed signal from the pulse generator  54  at the surface  14 . In order to accomplish this, the processor/controller  94  of each of the vibrator subs  46 ,  48 ,  50 ,  52  must be preprogrammed to actuate its respective motor  74  in response to receipt of a unique signal from the sensor  92 . In order to actuate the vibratory sub  52 , a unique pulsed signal is generated by the pulse generator  54 . The pulsed signal is transmitted through the axial flowbore  42  of the drill string  30 . Due to the presence of the fluid conduit  90  in the housing  62 , the pulsed signal will be detected by the sensor  92  and the processor/controller  94  will actuate the motor  74  upon detection of the correct unique pulsed signal. 
         [0024]    An alternative method of operation of the vibratory subs  46 ,  48 ,  50 ,  52  allows automatic operation of the subs  46 ,  48 ,  50 ,  52  in response to one or more predetermined wellbore conditions. In this embodiment, the processor/controllers  94  of the various vibration subs  46 ,  48 ,  50 ,  52  are preprogrammed to actuate their respective motors  74  upon detection by the sensor  92  of a particular predetermined wellbore condition or conditions. In a currently preferred embodiment, the sensor  92  is one that is able to detect MWD or LWD signals. In this embodiment, of course, the BHA  44  must be provided with an MWD or LWD pulser system, of a type well-known in the art for detecting wellbore conditions proximate the BHA  44  and transmitting fluid pulse signals representative of those conditions through the flowbore  42  of the drill string  30 . The pulsed signals are traditionally received by a receiver located at the surface  14  of the wellbore  10  and are then interpreted. Typical wellbore conditions detected and transmitted by MWD/LWD systems include temperature, pressure, depth, weight on bit (WOB), drill string torque, and rate of penetration. In a particularly preferred embodiment of the present invention, the processor/controllers  94  of the vibration subs  46 ,  48 ,  50 , and  52  are preprogrammed to actuate their respective motors  74  in response to detected wellbore condition of torque, as detected by the BHA  44 . The processor/controllers  94  of one or more of the vibration subs  46 ,  48 ,  50 ,  52  are programmed so as to actuate their respective motors  74  upon detection of a predetermined level of torque, as detected by the BHA. 
         [0025]    Alternately, the processors/controllers  94  of one or more of the vibration subs  46 ,  48 ,  50 ,  52  may be preprogrammed to actuate their respective motors  74  upon detection that the BHA  44  has reached a particular predetermined depth. The depth would correspond, for example, to a particularly unstable formation or formations. Other measured MWD/LWD parameters may be used as well to selectively operate the subs  46 ,  48 ,  50 ,  52 . 
         [0026]    The several vibration subs  46 ,  48 ,  50 ,  52  may be collectively considered to be a vibratory system  100  since they act in accordance with one of the predetermined control schemes outlined above. It is noted that the vibratory system  100  of the present invention is not confined to use with a drill string, but may also be adapted for use with other strings of tubular members, such as production tubing strings or work strings. In the example outlined above, it will be appreciated that once vibration of the selected vibration sub or subs begins, the drill string  30  becomes unstuck by the localized vibration of the vibration sub  52  proximate the stuck location  58 . The vibration will cause the surrounding solids to be broken up and the drill string  30  to be translated within the wellbore  10 . 
         [0027]    It is also noted that one or more of the vibrations subs  46 ,  48 ,  50 ,  52  can be vibrated during normal operation of the drill string  30  (i.e., when the drill string  30  is not stuck) in order to help prevent sticking conditions from occurring. 
         [0028]    Those of skill in the art will recognize that numerous modifications and changes may be made to the exemplary designs and embodiments described herein and that the invention is limited only by the claims that follow and any equivalents thereof.

Summary:
Devices and methods for translating tubulars within a wellbore and, as a result, effectively freeing a stuck tubular string within a wellbore. One or more vibrator devices are incorporated into a tubular string, such as a drill string. Each of the vibratory devices may be turned on or off independently, as needed, to help effectively free the tubular string from a stuck condition.