Patent Publication Number: US-2023151706-A1

Title: Downhole Vibration Tool

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims priority to, and the benefit of, U.S. Provisional Patent Application Ser. No. 63/279,967 filed on Nov. 16, 2021 and entitled “Downhole Vibration Tool”, which is incorporated herein by referenced in its entirety. 
    
    
     TECHNICAL FIELD 
     The present disclosure relates generally to downhole tools for use in a wellbore, and specifically to tools for generating vibrations in a wellbore. 
     BACKGROUND 
     When drilling a wellbore, a drill string comprising a plurality of tubular members joined end to end may be fed through a wellbore. In certain circumstances, for example while drilling a deviated or horizontal wellbore, friction between the drill string and the wellbore may cause difficulty in inserting or removing the drill string from the wellbore. Friction reduction tools (FRT) or other hydraulically actuated tools may be used to generate friction reducing forces in the drill string to temporarily reduce friction between the drill string and the wellbore. Hydraulically actuated tools may be powered by pressure pulses of drilling fluid supplied through the drill string. 
     SUMMARY 
     The present disclosure provides for a downhole vibration tool. The downhole vibration tool includes a body. The body may be generally tubular. The body may have one or more helical slots formed on an inner surface thereof. The downhole vibration tool includes a mandrel, the mandrel being generally tubular. The mandrel may have a bore. The mandrel may be positioned at least partially within the body. The mandrel may have one or more helical splines formed on an outer surface of the mandrel, the helical splines engaging the helical slots of the body. The space between the body and the mandrel wherein the helical splines are located may define a spline chamber. The mandrel may be translatable axially relative to the body. The downhole vibration tool may include a spring positioned in an annular space formed between the mandrel and the body defined as a spring chamber. The downhole vibration tool may include a balance piston positioned in an annular space formed between the mandrel and the body, wherein the balance piston separates an oil-filled chamber from an internal pressure chamber. The internal pressure chamber may be fluidly coupled to the bore of the mandrel by a balance port. The balance piston may be movable axially relative to the mandrel and the body wherein the oil filled chamber, spring chamber, and spline chamber are fluidly coupled. 
     The present disclosure provides for a system. The system may include a drill string, the drill string having a bore. The system may include a downhole vibration tool. The downhole vibration tool includes a body. The body may be generally tubular. The body may have one or more helical slots formed on an inner surface thereof. The body may be coupled to the drill string. The downhole vibration tool includes a mandrel, the mandrel being generally tubular. The mandrel may have a bore fluidly coupled to the bore of the drill string. The mandrel may be positioned at least partially within the body. The mandrel may have one or more helical splines formed on an outer surface of the mandrel, the helical splines engaging the helical slots of the body. The space between the body and the mandrel wherein the helical splines are located may define a spline chamber. The mandrel may be translatable axially relative to the body. The downhole vibration tool may include a spring positioned in an annular space formed between the mandrel and the body defined as a spring chamber. The downhole vibration tool may include a balance piston positioned in an annular space formed between the mandrel and the body, wherein the balance piston separates an oil-filled chamber from an internal pressure chamber. The internal pressure chamber may be fluidly coupled to the bore of the mandrel by a balance port. The balance piston may be movable axially relative to the mandrel and the body wherein the oil filled chamber, spring chamber, and spline chamber are fluidly coupled. The system may include a pressure pulsation tool. The pressure pulsation tool may be adapted to generate pulses within the bore of the drill string in response to fluid flow through the drill string. 
     The present disclosure provides for a method. The method may include coupling a downhole vibration tool to a drill string. The downhole vibration tool may include a body. The body may be generally tubular. The body may have one or more helical slots formed on an inner surface thereof. The body may be coupled to the drill string. The downhole vibration tool may include a mandrel. The mandrel may be generally tubular. The mandrel may have a bore fluidly coupled to the bore of the drill string. The mandrel may be positioned at least partially within the body. The mandrel may have one or more helical splines formed on an outer surface of the mandrel. The helical splines may engage the slots of the body. The space between the body and the mandrel wherein the helical splines are located may define a spline chamber. The mandrel may be translatable axially relative to the body. The mandrel may include a piston. The piston may be positioned in an annular space between the mandrel and the body defined as an actuation chamber. The piston may divide the actuation chamber into an external pressure actuation chamber and an internal pressure actuation chamber, wherein the body comprises an external port formed therein that fluidly couples the external pressure actuation chamber to the exterior of the body and wherein the internal pressure actuation chamber is fluidly coupled to the pressure within the bore of the mandrel. The downhole vibration tool may include a spring. The spring may be positioned in an annular space formed between the mandrel and the body defined as a spring chamber. The downhole vibration tool may include a balance piston. The balance piston may be positioned in an annular space formed between the mandrel and the body, wherein the balance piston separates an oil-filled chamber from an internal pressure chamber. The internal pressure chamber may be fluidly coupled to the bore of the mandrel by a balance port. The balance piston may be movable axially relative to the mandrel and the body wherein the oil filled chamber, spring chamber, and spline chamber are fluidly coupled. The method may include positioning the downhole vibration tool within a wellbore. The method may include increasing the pressure within the bore of the mandrel. The method may include imparting a differential pressure between the internal pressure actuation chamber and the external pressure actuation chamber across the piston, The method may include generating a longitudinal extension force and torsional force on the mandrel relative to the body. The method may include helically extending the mandrel relative to the body. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion. 
         FIG.  1    depicts an overview of a drill string having a downhole vibration tool consistent with at least one embodiment of the present disclosure in a wellbore. 
         FIG.  2    depicts a side elevation view of a downhole vibration tool consistent with at least one embodiment of the present disclosure. 
         FIG.  3    depicts a cross section view of a downhole vibration tool consistent with at least one embodiment of the present disclosure. 
         FIG.  4    depicts a perspective view of a mandrel of the downhole vibration tool of  FIG.  3   . 
         FIG.  5    depicts a cross section view of the downhole vibration tool of  FIG.  3    taken at line 
       A-A. 
         FIG.  6    depicts a cross section view of the downhole vibration tool of  FIG.  3    in an extended position. 
         FIG.  6 A  depicts a detail view of  FIG.  6   . 
         FIG.  7    depicts a cross section view of the downhole vibration tool of  FIG.  3    in a retracted position. 
         FIG.  7 A  depicts a detail view of  FIG.  7   . 
         FIG.  8    depicts a cross section view of a downhole vibration tool consistent with at least one embodiment of the present disclosure. 
         FIG.  9    depicts a perspective view of a mandrel of the downhole vibration tool of  FIG.  8   . 
         FIG.  10    depicts a cross section view of the downhole vibration tool of  FIG.  8    taken at line 
       B-B. 
         FIG.  11    depicts a cross section view of the downhole vibration tool of  FIG.  8    in an extended position. 
         FIG.  12    depicts a cross section view of the downhole vibration tool of  FIG.  8    in a retracted or compressed position. 
         FIG.  13    depicts a detail cross section view of a downhole vibration tool consistent with at least one embodiment of the present disclosure. 
         FIG.  14    depicts a detail cross section view of a downhole vibration tool consistent with at least one embodiment of the present disclosure. 
         FIG.  15 A  depicts a side view of a downhole tool consistent with at least one embodiment of the present disclosure. 
         FIG.  15 B  depicts a side view of a downhole tool consistent with at least one embodiment of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. 
       FIG.  1    depicts drill string  10  positioned within wellbore  20 . Drill string  10  may include downhole vibration tool  100 . Drill string  10  may be constructed from a plurality of tubular components that together define drill string bore  12 . Wellbore annulus  23  may be defined as the annular space within wellbore  20  about drill string  10 . One or more pumps  14  may be positioned to pump fluid through drill string bore  12 . Pumps  14  may be controlled by controller  18  so as to provide different flow rates of fluid through drill string bore  12 . For the purposes of this disclosure, “up”, “above”, and “upper” denote a direction within wellbore  20  toward the surface  22 , and “down”, “below”, and “lower” denote a direction within wellbore  20  away from the surface  22 . 
     In some embodiments, drill string  10  may include bottom hole assembly (BHA)  17 . In some embodiments, BHA  17  may include, for example and without limitation, one or more of drill bit  16 , MWD system  19 , downhole motor  21 , rotary steerable system  24 , or other downhole tools. 
     In some embodiments, drill string  10  may include downhole vibration tool  100 . Downhole vibration tool  100  may be positioned at or near BHA  17  as shown in  FIG.  1    or may be positioned at any other point along drill string  10 . Drill string  10  may include pressure pulsation tool  30 . Pressure pulsation tool  30  may generate pressure pulses within drill string bore  12  in response to fluid flow through drill string  10  from pumps  14 . For the purposes of this disclosure, internal pressure refers to the pressure within drill string bore  12 , external pressure refers to the pressure within wellbore annulus  23 , and differential pressure refers to the difference between internal pressure and external pressure unless otherwise denoted. Pressure pulsation tool  30  may be positioned above or below downhole vibration tool  100 . 
     In some embodiments, as shown in  FIGS.  2 ,  3   , downhole vibration tool  100  may include body  101 . Body  101  may be generally tubular. In some embodiments, body  101  may include first coupler  103  positioned at an end of body  101  to allow downhole vibration tool  100  to couple to drill string  10  or other tools of drill string  10 . In some embodiments, downhole vibration tool  100  may include mandrel  105 . Mandrel  105  may be tubular and may be positioned at least partially within body  101 . In some embodiments, mandrel  105  may include second coupler  107  positioned at an end of mandrel  105  opposite body  101  and adapted to allow downhole vibration tool  100  to couple to pressure pulsation tool  30  or other tools of drill string  10 . In some embodiments, body  101  and mandrel  105  may be tubular and may define tool bore  109 . In some embodiments, the annular space between mandrel  105  and body  101  may form one or more chambers as discussed below. 
     In some embodiments, with respect to  FIGS.  4 ,  5   , mandrel  105  may include one or more splines  111 . Splines  111  may engage with slots  113  formed on an inner surface of body  101  as shown in  FIG.  5   . The engagement of splines  111  with slots  113  may allow for longitudinal motion of mandrel  105  relative to body  101  while transmitting torque between body  101  and mandrel  105 . In some embodiments, with reference to  FIG.  3   , the area within body  101  within which splines  111  and slots  113  are located may define spline chamber  115 . 
     In some embodiments, with reference to  FIG.  3   , mandrel  105  may include lower mandrel spring stop  117  and upper mandrel spring stop  119 . Body  101  may correspondingly include lower body spring stop  121  and upper body spring stop  123 . Spring  125  may be positioned about mandrel  105  within body  101  between lower mandrel spring stop  117  lower body spring stop  121  and upper mandrel spring stop  119  and upper body spring stop  123 . Spring  125  may, for example and without limitation, be one or more of a coil spring or Belleville spring. Spring  125  may operate such that longitudinal movement of mandrel  105  relative to body  101  causes compression of spring  125  in both directions, such that spring  125  biases mandrel  105  to a neutral position as shown in  FIG.  3   . In some embodiments, the area within body  101  within which spring  125  is located may define spring chamber  127 . 
     In some embodiments, downhole vibration tool  100  may include balance piston chamber  129 . Balance piston chamber  129  may be formed in an annular space between mandrel  105  and body  101 . In some embodiments, balance piston  131  may be positioned within balance piston chamber  129  and may be fluidly sealed against mandrel  105  and body  101 . In some embodiments, balance piston  131  may divide balance piston chamber  129  into two chambers, referred to herein as oil-filled chamber  133  and internal pressure chamber  135 . Balance piston  131  may be able to move longitudinally within balance piston chamber  129  due to force applied on balance piston  131  maintaining an approximately equal pressure differential between oil-filled chamber  133  and internal pressure chamber  135 . In some embodiments, balance piston  131  may, by moving longitudinally within balance piston chamber  129 , transfer internal pressure from internal pressure chamber  135  to oil-filled chamber  133  such that the pressure in oil-filled chamber  133  is approximately equal to the pressure in internal pressure chamber  135 . 
     In some embodiments, oil-filled chamber  133  may be fluidly coupled to spring chamber  127  and spline chamber  115 . In some such embodiments, oil-filled chamber  133 , spring chamber  127 , and spline chamber  115  may be filled with oil. In some embodiments, one or more seals may be positioned between mandrel  105  and body  101  such that oil-filled chamber  133 , spring chamber  127 , and spline chamber  115  are fluidly isolated from other chambers of downhole vibration tool  100  and the surrounding wellbore by, for example and without limitation, mandrel seal  137 . 
     In some embodiments, internal pressure chamber  135  may be fluidly coupled to the bore of mandrel  105  by balance ports  139 . Internal pressure chamber  135  may thereby remain at or substantially at internal pressure. In some embodiments, internal pressure chamber  135  may be fluidly isolated from other chambers of downhole vibration tool  100  and the surrounding wellbore by, for example and without limitation, body seal  141 . 
     In some embodiments, downhole vibration tool  100  may include actuation chamber  143 . Actuation chamber  143  may be divided into external pressure actuation chamber  145  and internal pressure actuation chamber  147  by piston  149 . Piston  149  may be mechanically coupled to mandrel  105  and may be fluidly sealed against body  101  by piston seal  151 . In some embodiments, external pressure actuation chamber  145  may be fluidly coupled to wellbore annulus  23  by one or more external ports  153  formed in body  101  and may therefore be at external pressure. Internal pressure actuation chamber  147  may be at internal pressure directly. 
     Because piston  149  is mechanically coupled to mandrel  105 , differential pressure acting across piston  149  due to the difference between internal pressure and external pressure may result in a force acting on piston  149  referred to herein as an extending force. The internal pressure may act on pump-open area  150  of piston  149 . Where the internal pressure is above the external pressure, the extending force may bias mandrel  105  into an extended position as shown in  FIGS.  6  and  6 A . As mandrel  105  extends, the extending force may act against spring  125 , such that spring  125  is compressed between lower body spring stop  121  and upper mandrel spring stop  119 . In some embodiments, the extension of mandrel  105  due to the positive pressure differential or, for example and without limitation, where drill bit  16  is out of contact with the formation may damp axial tensile forces extending through downhole vibration tool  100 . 
     In some embodiments, with reference to  FIG.  1   , the downward force exerted between drill string  10  and the bottom of wellbore  20 , known as weight-on-bit, may be transmitted at least partially through downhole vibration tool  100 . This weight may therefore exert a compressive force across downhole vibration tool  100 . The compressive force may tend to bias mandrel  105  to retract into body  101  as shown in  FIGS.  7 ,  7 A . The compressive force may act against spring  125 , such that spring  125  is compressed between upper body spring stop  123  and lower mandrel spring stop  117 . In some embodiments, the retraction of mandrel  105  due to increases in compressive force may damp axial forces extending through downhole vibration tool  100 . 
     In some embodiments, the amount of extension or retraction of mandrel  105  may be determined by the differential pressure, the cross-sectional area of piston  149 , the strength and geometry of spring  125 , the pump open force, and the compressive force acting on downhole vibration tool  100 . As mandrel  105  extends or is retracted, the length of downhole vibration tool increases or decreases accordingly. This extension and retraction may, for example and without limitation, be used to generate vibrations in drill string  10  in both tension and compression in response to pressure pulses generated by pressure pulsation tool  30 . Vibrations may be used, for example and without limitation, to allow for the drilling of horizontal or highly deviated wells in which drill string  10  may otherwise be subject to sticking during rotary or sliding-mode drilling operations. In some embodiments, the pressure pulses and thus the vibration induced by downhole vibration tool  100  may be generated at, for example and without limitation, between 4 Hz and 20 Hz. In some embodiments, the pressure pulses generated by pressure pulsation tool  30  may be, for example and without limitation, between 200 and 600 psi above the baseline internal pressure. 
     In some embodiments, as mandrel  105  is extended or retracted, the volume of spline chamber  115  and spring chamber  127  may change. To account for this change in volume, balance piston  131  may move within balance piston chamber  129 , such that the total volume of oil-filled chamber  133 , spring chamber  127 , and spline chamber  115  remains constant and substantially at internal pressure due to internal pressure chamber  135  being fluidly coupled to the bore of mandrel  105  by balance ports  139 . 
     In some embodiments, as shown in  FIGS.  3 - 6 ,  6 A,  7 , and  7 A , splines  111  and slots  113  may be formed substantially longitudinally along mandrel  105  and body  101 , respectively. In such an embodiment, changes in differential pressure and compressive force may cause mandrel  105  to extend axially relative to body  101 , such that axial vibrations are produced in response to pressure pulses. 
     In other embodiments, as shown in  FIG.  8 - 12   , splines  111 ′ and slots  113 ′ may be formed helically along mandrel  105 ′ and body  101 ′. In such an embodiment, extension or retraction of mandrel  105 ′ may both elongate downhole vibration tool  100  and exert a torsional force on drill string  10 . Additionally, vibrations produced in response to pressure pulses generated by pressure pulsation tool  30  may cause both axial and torsional vibration of drill string  10  due to the helical motion of mandrel  105 ′ relative to body  101 ′, which may further reduce friction on drill string  10 . In some such embodiments, downhole vibration tool  100  may operate as a torsional absorber while included in drill string  10  when pressure pulsation tool  30  is not engaged. In such an embodiment, both torsional loads and axial loads acting on drill string  10  across downhole vibration tool  100  may be absorbed by the resulting extension or retraction of mandrel  105 ′. 
     In some embodiments, as discussed above, downhole vibration tool  100  may include a single piston  149  in a single actuation chamber  143  having pump open area  150 . In other embodiments, downhole vibration tool  100  may include multiple pistons and actuation chambers to, without being bound to theory, increase the longitudinal force imparted by the pressure differential by increasing the overall pump open area above that of pump open area  150 . 
     For example,  FIG.  13    depicts downhole vibration tool  200  that includes first piston  249  coupled to mandrel  205  positioned in first actuation chamber  243  formed between mandrel  205  and body  201 . First actuation chamber  243  may be divided into first external pressure actuation chamber  245  and first internal pressure actuation chamber  247  by first piston  249 . First piston  249  may be mechanically coupled to mandrel  205  and may be fluidly sealed against body  201  by first piston seal  251 . In some embodiments, first external pressure actuation chamber  245  may be fluidly coupled to wellbore annulus  23  by one or more first external ports  253  formed in body  201  and may therefore be at external pressure. First internal pressure actuation chamber  247  may be at internal pressure and may act directly on pump open area  250  of first piston  249 . 
     Downhole vibration tool  200  may further include second piston  249 ′ coupled to mandrel  205  positioned in second actuation chamber  243 ′ formed between mandrel  205  and body  201 . Second actuation chamber  243 ′ may be divided into second external pressure actuation chamber  245 ′ and second internal pressure actuation chamber  247 ′ by second piston  249 ′. Second piston  249 ′ having pump open area  250 ′ may be mechanically coupled to mandrel  205  and may be fluidly sealed against body  201  by second piston seal  251 ′. In some embodiments, second external pressure actuation chamber  245 ′ may be fluidly coupled to wellbore annulus  23  by one or more second external ports  253 ′ formed in body  201  and may therefore be at external pressure. Second internal pressure actuation chamber  247 ′ may be fluidly coupled to the bore of mandrel  205  by internal ports  254 ′ and may therefore be at internal pressure. 
     By including second piston  249 ′ in addition to first piston  249 , the cross-sectional area against which the differential pressure may act may be increased, such that a greater extension force may act on downhole vibration tool  200  for a given differential pressure as compared to an embodiment of a downhole vibration tool that includes only a single piston  149 , such as shown and discussed with respect to downhole vibration tool  100 . 
     In other embodiments, additional pistons may be included. For example,  FIG.  14    depicts downhole vibration tool  300  that includes first piston  349  coupled to mandrel  305  positioned in first actuation chamber  343  formed between mandrel  305  and body  301 . First actuation chamber  343  may be divided into first external pressure actuation chamber  345  and first internal pressure actuation chamber  347  by first piston  349 . First piston  349  may be mechanically coupled to mandrel  305  and may be fluidly sealed against body  301  by first piston seal  351 . In some embodiments, first external pressure actuation chamber  345  may be fluidly coupled to wellbore annulus  23  by one or more first external ports  353  formed in body  301  and may therefore be at external pressure. First internal pressure actuation chamber  347  may be at internal pressure directly. 
     Downhole vibration tool  300  may further include second piston  349 ′ coupled to mandrel  305  positioned in second actuation chamber  343 ′ formed between mandrel  305  and body  301 . Second actuation chamber  343 ′ may be divided into second external pressure actuation chamber  345 ′ and second internal pressure actuation chamber  347 ′ by second piston  349 ′ having pump open area  350 ′. Second piston  349 ′ may be mechanically coupled to mandrel  305  and may be fluidly sealed against body  301  by second piston seal  351 ′. In some embodiments, second external pressure actuation chamber  345 ′ may be fluidly coupled to wellbore annulus  23  by one or more second external ports  353 ′ formed in body  301  and may therefore be at external pressure. Second internal pressure actuation chamber  347 ′ may be fluidly coupled to the bore of mandrel  305  by internal ports  354 ′ and may therefore be at internal pressure. 
     Downhole vibration tool  300  may further include third piston  349 ″ coupled to mandrel  305  positioned in third actuation chamber  343 ″ formed between mandrel  305  and body  301 . Third actuation chamber  343 ″ may be divided into third external pressure actuation chamber  345 ″ and third internal pressure actuation chamber  347 ″ by third piston  349 ″ having pump open area  350 ″. Third piston  349 ″ may be mechanically coupled to mandrel  305  and may be fluidly sealed against body  301  by third piston seal  351 ″. In some embodiments, third external pressure actuation chamber  345 ″ may be fluidly coupled to wellbore annulus  23  by one or more third external ports  353 ″ formed in body  301  and may therefore be at external pressure. Third internal pressure actuation chamber  347 ″ may be fluidly coupled to the bore of mandrel  305  by internal ports  354 ″ and may therefore be at internal pressure. 
     By including third piston  349 ″ in addition to first piston  349  and second piston  349 ″, the cross-sectional area against which the differential pressure may act may be increased, such that a greater extension force may act on downhole vibration tool  300  for a given differential pressure as compared to an embodiment of a downhole vibration tool that includes only a single piston  149 , such as shown and discussed with respect to downhole vibration tool  100 , or an embodiment of a downhole vibration tool that includes two pistons  249 ,  249 ′ such as shown and discussed with respect to downhole vibration tool  200 . 
     Adding additional pistons may, for example and without being bound to theory, increase total pump open area which when subject to a positive pressure differential and may increase the extension force. Such an increase in extension force may, when subject to positive pressure differential pulses, generate vibrations of stronger force. However, should the extension force exceed the maximum operating limits of spring  125 , such as to fully compress spring  125 , axial stroking movement may be prevented or reduced, which may prevent or reduce vibrations. Should downhole vibration tool  100  be configured in a rotary application such that drilling torque is transferred through helical splines  111 ′, the drilling torque may generate a compressive jacking force which may be transferred to spring  125 , which may allow additional pistons to be installed, increasing total pump open area to generate increased extension vibration force whilst operating within limits of spring  125 . 
     Alternatively, with relation to rotary applications comparing a straight splined downhole vibration tool  100  with a helical splined downhole vibration tool  100 , wherein the helical splined vibration tool is set-up with pressure pulses of smaller magnitude than the pulses set-up with the straight splined tool, the additional pump open area available to the helical splined tool may produce a pulsing extension force of similar or greater magnitude than the straight splined tool despite utilizing a smaller pulsing pressure. 
     Downhole vibration tool  100  configured with a helical spline may provide improvements for non-rotary sliding applications. In such applications a tool configured with a straight spline may produce longitudinal axial stroking vibrations as depicted  FIG.  15 A , a tool configured with a helical spline may produce a compound of axial and rotational stroking vibrations or torsional vibrations as depicted  FIG.  15 B . 
     Furthermore, downhole vibration tool  100  configured with a helical spline for rotary applications taking advantage of maximum pump open area, may generate torsional vibrations of magnitude such as to have a percussive effect on the bit, which may increase rate of penetration. In some embodiments, increased stroking force that is cyclically downward and torsional and downhole vibration tool  100  is positioned within the lower region of BHA  17 , a percussive action may be applied to drill bit  16 . 
     In some embodiments, if pressure pulsation tool  30  is configured with a control mechanism that is configured such that the pulses can be switched on or off as desired, downhole vibration tool  100  may be selectively switched between a torsional pulsing tool or a torsional absorber tool. 
     The foregoing outlines features of several embodiments so that a person of ordinary skill in the art may better understand the aspects of the present disclosure. Such features may be replaced by any one of numerous equivalent alternatives, only some of which are disclosed herein. One of ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. One of ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure and that they may make various changes, substitutions, and alterations herein without departing from the spirit and scope of the present disclosure.