Patent Publication Number: US-7219726-B2

Title: Method and apparatus to vibrate a downhole component

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
   This application is a Continuation Application of U.S. Ser. No. 10/393,285 filed Mar. 20, 2003, now granted as U.S. Pat. No. 6,907,927, which is a Divisional Application of U.S. Ser. No. 09/797,157 filed Mar. 1, 2001, now granted as U.S. Pat. No. 6,571,870. 

   TECHNICAL FIELD 
   The invention relates to method and apparatus to vibrate a downhole component. 
   BACKGROUND 
   To prepare a well for production of hydrocarbons, various operations are performed, including drilling and completion operations. In drilling a well, a drill bit is carried on the end of a drill pipe. In completing a well, various operations may be performed by carrying tools down on a tubing string (e.g., a coiled tubing or jointed tubing). As used here, the term “tubing string” is used to denote a rigid conveyance mechanism or structure, such as a coiled tubing or drill pipe, that can be used to carry tools or fluids into a wellbore. 
   More recently, many deviated or extended reach wells have been drilled to facilitate the recovery of hydrocarbons. Extended reach wells have proven to be able to increase the recovery rate of hydrocarbons while reducing the operational cost. Generally, the deeper an extended reach well can be drilled or serviced, the higher the economic benefit. Despite many technical advances in the area of extended reach technology, challenges remain in drilling or servicing extended reach wells. 
   For a given extended or deviated well, the reach of a tool carried on a tubing string is limited by the propensity of the tubing string to lock up. As a tubing string is run into a wellbore, it has to overcome the frictional force between the tubing string and the wall of the wellbore. The longer the length of the tubing string that is run into the wellbore, the greater the frictional force that is developed between the tubing string and the wellbore wall. When the frictional force becomes large enough, it will cause the tubing string to buckle, first into a sinusoidal shape and then into a helical shape. After helical buckling occurs, continuing to run the tubing string into the wellbore will eventually lead to a stage where further pushing of the tubing string will not result in further advancement of the tubing string. Such a stage is referred to as tubing string lockup. The depth of tubing string lockup defines the maximum depth a tool or fluid can be delivered in the well. 
   Various factors affect (directly or indirectly) the maximum depth that a tubing string can be run into a wellbore. One factor is the friction coefficient between the tubing string and the wellbore. Another factor is the normal contact force between the tubing string and the wellbore, which is dependent on the weight of the tubing string and the stiffness of the tubing string. Generally, a lower friction coefficient or lower tubing string weight usually indicates that the tubing string can extend further into the wellbore. Also, higher bending stiffness tends to delay the occurrence of buckling, which extends the reach of the tubing string into the wellbore. 
   Various solutions have been attempted or implemented to extend the reach of a tubing string in a wellbore. One is to reduce the contact force between the tubing and the wellbore, such as by using different fluids inside and outside the tubing to reduce the buoyancy weight of the tubing or by using a more light-weight material for the tubing. Another technique is to delay or prevent the onset of helical buckling, which can be achieved by using larger diameter tubing. However, this increases the weight of the string and reduces flexibility in operation. Yet another approach uses a tractor to pull tubing into the well by applying a tractor load at the lower end of the tubing. Other approaches employ vibration to aid in friction reduction. 
   However, despite the various solutions that have been proposed or implemented, a need continues to exist for an improved method and apparatus to improve the reach of a string in a wellbore. 
   SUMMARY 
   In general, according to one embodiment, an apparatus for use in a wellbore comprises a housing having a longitudinal axis and a mechanism having one or more impact elements adapted to move along the longitudinal axis in an oscillating manner to impart a back and forth force on the housing to vibrate the housing. 
   In general, according to another embodiment, an apparatus for use in a wellbore comprises a housing and at least one impact element rotatably mounted in the housing. The at least one impact element is rotatable to oscillate back and forth to impart a vibration force to the housing. 
   Other or alternative features and embodiments will become apparent from the following description, from the drawings, and from the claims. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
       FIG. 1  illustrates an embodiment of a tool attached to a conveyance or carrier structure in a wellbore, the conveyance or carrier structure including one or more vibration devices. 
       FIGS. 2A-2C  illustrate the effect of longitudinal vibration caused by the vibration device according to one embodiment. 
       FIG. 3  illustrates generally a vibration device for creating a bi-directional longitudinal vibration. 
       FIGS. 4A-4B  is a longitudinal sectional view of a vibration device for generating a bi-directional longitudinal vibration according to one embodiment. 
       FIGS. 5A-5C  are a longitudinal sectional view of a vibration device for generating a bi-directional vibration according to another embodiment. 
       FIG. 6  illustrates a valve mechanism used in the vibration device of  FIGS. 5A-5C . 
       FIG. 7-10  illustrates an apparatus to generate a rotational or torsional vibration in the tubing string of  FIG. 1 , in accordance with another embodiment. 
   

   DETAILED DESCRIPTION 
   In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those skilled in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible. Although described embodiments refer to vibration apparatus and methods for enhancing drilling or other services in extended reach or deviated wells, the same or modified vibration apparatus and method can be used in other applications, such as freeing stuck pipe, assisting the installation of a liner, placement of sand control screens, activating downhole mechanisms (e.g., valves, nipples, etc.), and other applications. As used here, the terms “up” and “down”; “upward” and downward”; “upstream” and “downstream”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly described some embodiments of the invention. However, when applied to apparatus and methods for use in wells that are deviated or horizontal, such terms may refer to a left to right, right to left, or other relationship as appropriate. 
   Referring to  FIG. 1 , a string includes a tool  18  carried on a tubing or pipe  14  (hereinafter referred to as “tubing” or “tubular conduit” or “tubular structure”) into a wellbore  10 . In another embodiment, the structure that carries the tool  18  into the wellbore does not need to be tubular, but rather can be any other shape that is suitable for use in the wellbore as a rigid carrier structure. As used here, a carrier structure is considered to be “rigid” if a compressive force can be applied at one end of the carrier structure to move it downwardly into the wellbore. A rigid carrier structure is contrasted to non-rigid carrier structures such as wirelines or slicklines. 
   The wellbore  10  is lined with a casing  12 , and has a generally vertical section as well as a deviated or horizontal section  20 . In other embodiments, the wellbore  10  can be a generally vertical well, a deviated well, or a horizontal well. 
   In accordance with some embodiments of the invention, one or more vibration devices  16  are mounted on the string. In the illustrated example of  FIG. 1 , two vibration devices  16 A and  16 B are illustrated. In other examples, a single vibration device or more than two vibration devices can be used. 
   In one embodiment, the vibration device includes one or more impact elements that are able to oscillate back and forth along a longitudinal axis of the string to impart a back and forth force on the string. The back and forth forces applied by the one or more impact elements in the vibration device causes vibration along other portions of the string. Alternatively, instead of bi-directional repeated impacts, the impacts may occur only in a single direction to provide unidirectional impacts. In another embodiment, instead of longitudinal oscillation of the impact elements in the vibration device  16 , the one or more impact elements can be rotatably mounted in a housing of the vibration device to oscillate in a rotational back and forth manner to impart a rotational or torsional vibration force on the tubing string. 
   Thus, in the first embodiment, longitudinal vibration (due to bi-directional or unidirectional impacts) is introduced on the tubing string, while in the second embodiment, rotational or torsional vibration (due to bi-directional or unidirectional rotational impacts) is imparted on the tubing string. Longitudinal vibrations and rotational vibrations are able to reduce the frictional force between the tubing string and the wellbore wall. In yet another embodiment, both longitudinal and rotational vibration devices can be used in combination with a single tubing string. 
   In accordance with some embodiments of the invention, the bi-directional or unidirectional impact oscillation can be achieved without the need of tension or compression on the tubing string. In other words, an upward force applied on the tubing string or a compression force applied on the tubing string is not needed for operation of the vibration device  16 . In one embodiment, the energy to actuate the back-and-forth axial oscillation is provided by fluid pressures. In other embodiments, other types of energy can be used, such as electrical energy. The mechanism to actuate the vibration device  16  operates independently of any tension or compression force applied to the string, in accordance with some embodiments. 
   Generally, the mechanism to operate the vibration device actuates at least one impact element to repeatedly create a longitudinal or rotational jarring force (at generally a given frequency) on a housing of the vibration device. The jarring force can be bi-directional or unidirectional. 
   Although tension or compression on the tubing string is not needed for operation of the vibration device in some embodiments, other embodiments may employ tension or compression forces to enable actuation of the vibration device, particularly to generate unidirectional, oscillation impact forces. 
   When longitudinal vibration is introduced in a tubing string, the velocity of the vibration may be superimposed on the translational velocity (the velocity of the tubing string as it is being run into the wellbore). As long as the vibration velocity is larger than that of the running speed of the tubing string, at any instantaneous moment, some portions of the tubing string will have velocity in one direction while other portions of the tubing string will have velocity in the opposite direction. As a result, the frictional force on the tubing string will be in one direction for some portions of the string and in the opposite direction for other portions of the string. Consequently, the overall frictional force between the string and the wellbore wall is reduced, enabling the tubing string to be run deeper into the wellbore. In addition to the frictional benefits offered by the introduced vibration, the motion imparted by the vibration device also aids in extending the reach of the tubing string into the wellbore. 
   The frequency of vibration can be selected based on the characteristics of the tubing string and the well  10 . For example, the length of the deviated or horizontal section  20  of the well and the corresponding tubing string may dictate the vibration frequency and peak impact forces to be imparted by the vibration devices  16 . Generally, the longer the deviated or horizontal section  20 , the greater the vibration forces needed to extend the reach of the tubing string. The vibration frequency and magnitude may be controlled to provide effective extended reach characteristics while avoiding excessive vibrations that may cause damage to instruments or other tools attached to the tubing string. The frequency of oscillation of the impact element(s) in the vibration device can be selected to match the resonance frequency and/or maximize the transmissibility of the tubing string or to maximize the transmissibility of vibration along the tubing string. 
   Shock absorbers  20 A,  20 B ( FIG. 1 ) may also be positioned to protect instruments or other tools in the tubing string that may be damaged by vibration caused by the vibration devices  16 . 
   The effect of longitudinal vibration on a tubing string is illustrated in connection with  FIGS. 2A-2C . In  FIG. 2A , a structure  100  that is run into the wellbore at velocity V is illustrated. The structure  100  can be represented as a number ( 5  in the illustrated example) of masses  102 A,  102 B,  102 C,  102 D, and  102 E that are connected by respective springs  104 A,  104 B,  104 C, and  104 D. Without vibration, the velocity of each of the masses is substantially equal (with the velocity represented as V). The frictional force at each mass  102  is also substantially equal (with the frictional force represented as f). As a result, the net frictional force on the structure  100  in the example of  FIG. 2A  is +5f, the direction of this frictional force being in the opposite direction of the velocity V. 
   If longitudinal vibration is applied, then the velocities at different masses  102 A- 102 E will be different.  FIG. 2B  illustrates the velocity pattern at each mass at an instantaneous moment in time. The velocity at mass  102 A is −5V, at mass  102 B −3V, at mass  102 C 0V, at mass  102 D +3V, and at mass  102 E +5V. The longitudinal vibration is applied while the tubing string is being run at velocity V, as shown in  FIG. 2A . The resulting velocity pattern on the tubing string is the superposition of the translational velocity V ( FIG. 2A ) and the instantaneous vibration velocity ( FIG. 2B ), as discussed below. 
   As shown in  FIG. 2C , by superimposing the velocity patterns of  FIGS. 2A and 2B , the net velocity at mass  102 A is −4V, at mass  102 B −2V, at mass  102 C +1V, at mass  102 D +4V, and at mass  102 E +6V. At the masses where the velocities are in the negative direction, the frictional forces are also negative (from left to right in the diagram). Thus, at  102 A and  102 B, the frictional force is −f. On the other hand, at masses where the velocities are in the positive direction, the resulting frictional forces are positive (from right to left in the diagram). The frictional force at each mass is shown in  FIG. 2C . As a result, the net frictional force in this arrangement is approximately +f, as compared to the +5f when longitudinal vibration is not applied ( FIG. 2A ). 
   As seen from the illustration of  FIGS. 2A-2C , for longitudinal vibration to reduce frictional force, the peak vibration velocity should be higher than the translational speed of the tubing string as it is being run into the wellbore. The higher the peak vibration velocity over the translational velocity, the greater the friction reduction. 
   Referring to  FIG. 3 , a vibration device  16  according to one embodiment for imparting longitudinal vibration is illustrated. Generally, the vibration device  16  includes a housing  200  that defines a chamber  202 . A projectile  204  (an impact element) is located in the chamber  202 . Instead of a single projectile, plural projectiles may also be present in the chamber  202  in another embodiment. Two pressure control ports  206  and  208  are provided in the housing  200 . The first control port  206  communicates or releases fluid (gas, liquid, or a combination thereof) pressure to or from the chamber  202  on the first side  210  of the projectile  204 , while the second control port  208  communicates or releases fluid pressure to or from the second side  212  of the projectile  204 . 
   The projectile  204  is powered by a fluid pressure difference between the two sides of the projectile  204 . Thus, one side of the projectile  204  can be in communication with the hydrostatic pressure of wellbore fluid, while another side of the projectile  204  is in communication with an elevated pressure. The pressure difference accelerates the projectile  204  to some velocity before it impacts the wall (which is one example of a target) of the chamber  200 . The length of the chamber  202  is designed so that greater than a predetermined amount of velocity can be generated for the projectile  204  before it impacts the target in the housing  200 . Upon impact, a shock wave is generated in the housing  200  and transmitted to the tubing string. By reversing the pressure difference across the projectile  204 , the projectile  204  can be accelerated in the other direction after impact. By repeatedly reversing the pressure differences across the projectile  204 , the projectile  204  is oscillated back and forth in the chamber  204  to impart an oscillating force on the housing  200 . As the shock wave is repeatedly generated from the impact and passed to the tubing string, the tubing string will vibrate, leading to friction reduction between the tubing string and the inner wall of the wellbore. 
   In general, the effectiveness of a vibration tool is directly related to the maximum energy the vibrator can provide. A vibrator&#39;s output energy (E) is proportional to the mass (M) and the square of the vibrator speed (V) (E∝MV 2 ). Unlike some other vibrators (denoted hereafter as “mass-based vibrators”), which rely on a heavy mass (M) to generate the vibration energy, some embodiments of the present invention use a more effective way to generate vibration energy by high impact velocity (denoted hereafter as “velocity-based vibrator”). For mass-based vibrators, the mass may be quite large (from several hundred pounds to several thousand pounds) to create an adequate amount of vibration for oilfield applications. This may cause logistic difficulty for the operators to move heavy mass into the wells, and mass-based vibrations may be prone to failure (e.g., getting stuck downhole). The velocity-based vibrator, on the other hand, uses a much smaller mass (from tens of pounds to hundreds of pounds). To create comparable amount of vibration energy, the velocity-based vibrator uses only a fraction of the mass that is needed by the mass-based vibrator. Instead of depending on a heavy mass to achieve a desired output energy, the velocity-based vibrator uses high velocity of a smaller mass to generate the desired output energy. As used here, “high velocity” refers to instantaneous velocity greater than or equal to about 2 meters per second (m/s) prior to impact. One range that can be used for the impact element is between about 2 m/s and 50 m/s. Also, a frequency of more than about 2 impacts per second may be sufficient to generate a desired output energy. One range that can be used is between about 2 impacts per second and 60 impacts per second. The significant reduction in mass for velocity-based vibrators provides better operational efficiency and safety, as it is easier to mobilize and less likely to be stuck. Although use of a heavy mass is undesirable in some instances, other embodiments may utilize the velocity-based vibrator in conjunction with a mass-based vibrator. 
   In the embodiment of  FIG. 3 , and also in the embodiments described below, the repeated impact of a projectile against targets in the vibration device generates substantial amounts of heat energy. This may raise the temperature to a level (particularly in a deep wellbore environment where temperatures may be relatively high) that may adversely affect performance of the vibration device. One way to decrease possible adverse effects of high temperature is to use components formed of a material having low coefficients of expansion with temperature, particular components within the vibration device. A further issue associated with increased temperature is build-up of fluid pressure within the vibration device, which may cause fluid to become more viscous. Pressure compensator devices may be provided in the vibration device to relieve elevated pressure conditions. 
   The impact force provided by the vibration device can be made to be independent of an attached heavy mass and/or the weight of the tubing string. In the embodiment of  FIG. 3 , the impact force is supplied by the projectile  204  in response to fluid pressure difference, and is independent of the weight of the tubing string. By adjusting the travel distance of the impact element or the fluid pressure difference, the weight of the impact element can be adjusted (in other words, the larger the distance traveled or the higher the fluid pressure difference, the lighter the impact element has to be to generate the same impact force). Also, an external anchor is not necessary in accordance with some embodiments to provide the desired vibration. 
   In some embodiments, the impact element, such as projectile  204 , is formed of an impact-resistant and corrosion-resistant material. Examples include tungsten carbide, monel K500, Inconel 718, and the like. Additionally, in some embodiments, the impact element and a housing or container in which the impact element is located are formed of materials having similar thermal expansion coefficients. 
   One embodiment of the device  16  shown in  FIG. 3  is illustrated in greater detail in  FIGS. 4A-4B . In the  FIGS. 4A-4B  embodiment, the vibration device  16  includes a housing  300  that defines a chamber in which an upper annular piston  304  and a lower annular piston  312  are located. As described below, the upper and lower pistons are used as projectiles to impart longitudinal vibration within the housing  300 . 
   The outer surface  311  of the upper piston  304  is sealably engaged to a protruding portion  318  of the housing  300  by an O-ring seal  316 . The inner portion  309  of the upper piston  304  is sealably engaged to a sleeve  308  by one or more O-ring seals  320 . The upper portion of the piston  304  is located in a chamber  305 , which can be in communication with wellbore fluids that are at hydrostatic pressure. 
   The sleeve  308  is moveable along the longitudinal axis of the device  16  (indicated by the arrow X). Although not shown in  FIGS. 4A-4B , the sleeve  308  is operably coupled to an actuator that is adapted to move the sleeve  308  back and forth along the longitudinal axis X. The actuator can be a mechanical, electrical, or hydraulic actuator. 
   The lower portion of the upper piston  304  is shaped to provide an annular cylinder  322  that defines a space  324  in which a valve mechanism  310  is positioned. The valve mechanism  310  is basically a ring-shaped block that includes a release mechanism including an upper release port  380 , a lower release port  382 , and a side release port  384 . A chamber in the block contains an upper ball  386 , a lower ball  388 , and a spring  390 . The spring  390  pushes the balls  386  and  388  against respective upper and lower release ports  380  and  382  to block fluid flow through the release ports. However, if pressure on one side or the other is greater than pressure in the chamber  394 , then the corresponding one of the balls  386  and  388  is pushed away from the respective release port to enable release of fluid pressure. 
   The outer surface of the ring-shaped block  310  is sealably engaged to the inner surface of the cylinder  322  by an O-ring seal  326 . The inner surface of the ring-shaped block  310  is sealably engaged to the sleeve  308  by O-ring seals  330  and  332 . Also, the valve mechanism  310  is fixedly attached to the sleeve  308  by an attachment element  334  (e.g., a screw, pin, etc.). Thus, when the sleeve  308  moves, the valve mechanism  310  moves along with the sleeve  308 . 
   In the position illustrated in  FIG. 4A , a chamber  306  is defined between the valve mechanism  310  and a surface  368 . The space  306  is initially filled with atmospheric pressure. The atmospheric chamber  306  is sealed by seals  326 ,  332 , and  320 . 
   A chamber  314  below the valve mechanism  310  is filled with fluid under pressure. For example, the fluid can be pumped down a channel  338  in the housing  300 . The fluid can be from a source at the well surface to provide an elevated pressure for activating the vibration device  16 . The fluid in the chamber  314  is also in communication with a shoulder  340  of the upper piston  304  below the protruding portion  318  of the housing  300 . Thus, if elevated pressure is applied in the chamber  314 , then a pressure difference is developed across the upper piston  304  (the difference between the pressure applied on the shoulder  340  and the atmospheric pressure in the chamber  306 ) that tends to apply a downward force on the upper piston  304 . However, if the sleeve  308  is fixed in position by the actuator, then this pressure difference does not move the upper piston  304 . 
   In similar arrangement, an outer surface of the lower piston  312  is sealably engaged with a protruding portion  344  of the housing  300  by an O-ring seal  346 . Also, the inner surface of the lower piston  312  is sealably engaged to the sleeve  308  by O-ring seals  348 . The lower portion of the piston  312  is located in a chamber  315  that is in communication with wellbore fluids at hydrostatic pressure. 
   The upper portion of the piston  312  defines a cylinder  350 , which defines a chamber  356  that is able to receive the valve mechanism  310  when the valve mechanism is moved downwardly. 
   In operation, to activate the vibration device  16 , the actuator is activated to move the sleeve  308  downwardly, which moves the valve mechanism  310  downwardly. Because of the downward force applied on the shoulder  340  of the upper piston  304 , the upper piston  304  moves downwardly with the valve mechanism  310 . After the sleeve  308  has traversed a sufficient distance, the valve mechanism  310  enters the chamber  356  defined by the cylinder  350  of the lower piston  312 . When the lower end  364  of the cylinder  322  of the upper piston  304  contacts the upper end  366  of the cylinder  350  of the lower piston  312 , further downward movement of the upper piston  304  is prevented even as the sleeve  308  continues its downward movement. The sleeve  308  continues to move downwardly until the lower end  360  of the valve mechanism  310  contacts the bottom surface  362  of the cylinder  350 . 
   Continued downward movement of the valve mechanism  310  when the cylinder  322  has stopped will cause the valve mechanism  310  to carry the O-ring seal  326  past the lower end  364  of the cylinder  322 . This causes fluid pressure in the chamber  314  to be communicated to the upper surface  368  of the cylinder  322  to cause a sudden upward force to be applied against the upper piston  304 . The pressure in the chamber  314  is set at a level that is greater than the pressure in the chamber  305  (e.g., at hydrostatic wellbore pressure), thereby creating a pressure difference and an upward force on the upper piston  304  when the pressure in the chamber  314  is communicated to the upper surface  368  of the cylinder  322 . The applied force causes the upper piston  304  to be accelerated upwardly until the upper end  370  of the upper piston  304  impacts a target surface  372  defined by the housing  300 . More generally, the target can be some other type of object that is fixedly attached to the housing  300 . When impact occurs, a compressive wave is generated and passed to the tubing string, resulting in a vibrational motion of the tubing string. 
   Once the valve mechanism  310  enters the chamber  356  and the seal  326  carried by the valve mechanism  310  engages the inner wall of the cylinder  350 , the buildup of pressure in the chamber  356  is relieved through the check valve provided by the ball  388  and the release port  382 . 
   At this point, the valve mechanism  310  is sitting in the chamber  356 . The actuator is then activated to move the sleeve  308  upwardly, which causes the valve mechanism  310  to move upwardly along with the sleeve  308 . As a result, a pressure difference is developed across the lower piston  312  (between the elevated pressure in chamber  314  and the wellbore fluid pressure in the region of the chamber  356  between the valve mechanism  310  and the bottom surface  362 ). The differential pressure applies a net upward force against a shoulder  374  of the lower piston  312 . Thus, as the valve mechanism  310  is moved upwardly, the lower piston  312  follows due to the force applied on the shoulder  374 . The upward movement of the valve mechanism  310  and lower piston  312  continues until the upper end  366  of the cylinder  350  contacts the lower end  364  of the upper cylinder  322 , which stops further upward movement of the lower piston  312 . However, the valve mechanism  310  continues its upward motion until the seal  326  clears the upper end  366  of the lower cylinder  350 . Again, any pressure buildup in the chamber  306  is relieved through the check valve provided by the ball  386  and the release port  380 . 
   When the seal  326  clears the upper end  366  of the lower cylinder  350 , the elevated fluid pressure in the chamber  314  rushes into the chamber  356  of the lower cylinder  350  to apply downward pressure on the bottom surface  362 . A pressure differential is created across the lower piston  312  (difference between the pressure applied on the surface  362  and the wellbore fluid pressure applied against the lower piston  312  in the chamber  315 ). As a result, the downward force accelerates the lower piston  312  downwardly until the lower end  376  of the lower piston  312  impacts a target surface  378  attached to the housing  300 . As a result of the impact, a tensile wave is generated in the housing  300 . The tensile wave is propagated to the tubing string, resulting in a vibrational motion of the tubing string. 
   Continued up and down motion of the sleeve  308  by the actuator will cause the upper and lower pistons to be accelerated in opposite directions to provide oscillating back and forth impact forces to provide the desired bi-directional longitudinal vibration. 
   The effectiveness of the impact induced vibration on tubing string is directly related to the frequency spectrum of the impact force. In order to maximize the impact induced vibration on the tubing string, the frequency spectrum of the impact force should be adjusted according to tubing length and downhole conditions. The tubing length and downhole conditions affect the transmissibility of the tubing string into the wellbore. There are several ways to change the impact force frequency spectrum. For example, the impact force spectrum can be changed by altering the back pressure in the chamber  314  of  FIG. 4A . Increasing the back pressure in chamber  314  will lead to lower frequency components of the impact force spectrum, a condition that is favorable for better transmissibility. Another way to change the frequency spectrum is by adjusting the movement of sleeve  308 . Adjustments to the movement of the sleeve  308  that alter the frequency spectrum include adjusting the speed of the up and down movement of the sleeve  308 , and introducing a time delay at the end of upward movement or downward movement of the sleeve  308  (e.g., at the end of the upward movement, the sleeve  308  stops for a certain amount of time before moving downward). Another way to change the frequency spectrum of the impact force is by adjusting the traveling distance of the impacting elements, such as by adjusting the length of chamber  314 . Still another way to change the frequency spectrum of the impact force is by choosing suitable materials for impact surfaces. 
   It should be noted that all of the above-mentioned ways (except material selection) of changing the frequency spectrum can be employed dynamically as conditions downhole necessitate. 
   Referring to  FIGS. 5A-5C , another embodiment of the vibration device  16  that provides for bi-directional longitudinal vibration is illustrated. In this embodiment, an upper spring  402  ( FIG. 5A ) and a lower spring  406  ( FIG. 5C ) provides the force for accelerating an upper hammer  404  and a lower hammer  408 , respectively, to cause an impact force between the hammers  404  and  408  and a corresponding target that is fixedly attached to a housing  400  of the vibration device  16 . 
   The upper hammer  404  has a sleeve  472  that extends downwardly inside the housing  400 . An inwardly protruding portion is formed on the sleeve  472 . The lower end of the sleeve  472  is integrally attached to an impact portion  475  that has an impact surface  422 . The impact surface  422  is designed to impact a shoulder  423  of the housing  400 . The space between the impact surface  422  and shoulder  423  is in communication with wellbore fluid pressure through one or more side ports  424 . 
   The lower hammer  408  ( FIG. 5C ) also defines an impact shoulder  480  that is designed to impact a shoulder  482  of the housing  400 . The space between the impact shoulder  480  and the shoulder  482  is also in communication with wellbore fluid pressure. A sleeve portion  481  of the lower hammer  408  extends upwardly in the housing  400  to an upper end portion  434 . 
   The vibration device  16  also includes a mandrel  410  and a valve mechanism  412 . An annular piston  430  is arranged around the mandrel  410 , with the upper end of the piston  430  having a flanged portion  432 . 
   An annular chamber  418  is defined between the lower surface of a shoulder  419  of the upper hammer  404  and the upper end  417  of the valve mechanism  412 . Another chamber  420  is defined between the upper end portion  434  of the lower hammer  408  and the lower end  421  of the valve mechanism  412 . The valve mechanism  412  selectively controls fluid flow from the inner bore  411  of the mandrel  410  to one of the chambers  418  and  420 . 
   A ball seat  436  is provided in the inner bore  411  of the mandrel  410 , with the ball seat  436  adapted to receive a ball dropped from the surface. When the ball is seated in the ball seat  436 , fluid pressure can be increased in the mandrel bore  411  to generate movement of the hammers  404  and  408  (as further described below). 
   The valve mechanism  412  is illustrated in greater detail in  FIG. 6 . The valve mechanism  412  includes a channel  442  that is in communication with the mandrel bore  411  through a port  440  in the mandrel  410 . When the ball is seated in the ball seat  436 , fluid flow in the mandrel bore  411  flows through the port  440  and channel  442  to a longitudinal channel  452  having an enlarged space  444  capable of receiving an enlarged portion  450  (forming a sealing element) of a rod  446 . The lower end of the rod  446  is fixedly or integrally attached to the flanged portion  432  of the piston  430 . 
   In the illustrated position of  FIG. 6 , fluid flowing into the space  444  goes upwardly through the channel  452  into the chamber  418 . In its down position, the sealing element  450  of the rod  446  is sealably engaged with the lower surface defining the space  444  to prevent fluid flow down the channel  452 . The seal can be created by use of an O-ring seal or coating the sealing element  450  with a suitable material. If the sealing element  450  of the rod  446  is moved upwardly to sealably engage an upper surface defining the space  444 , then fluid flows downwardly through the channel  452  into the chamber  420 . 
   Another part of the valve mechanism  412  includes a spring  454  that is placed in a chamber  456 . The spring  454  is biased to ensure that in a pressure balance situation (before the drop of a ball), the valve mechanism  412  is in a position such that fluid that enters into port  440  is in communication with chamber  418 , while fluid in chamber  420  is in communication with the wellbore through port  464 . The plate  460  has a sealing element such that when the plate  460  is in contact with upper surface  417  of the valve mechanism  412 , there is no fluid communication between chamber  418  and the channel  462 . Similarly, the flanged portion  432  also has a sealing element to ensure that when it is in contact with the lower surface  421  of the valve mechanism  412 , there is no fluid communication between the lower chamber  420  and the channel  462 . 
   A rod  458  is attached to the flanged portion  432  of the piston  430 . The upper end of the rod  458  is connected to a plate  460 . The plate  460 , rod  458 , and the flanged portion  432  can be a single integral member, or alternatively, they can be separate pieces that are fixedly attached. The rod  458  is moveable up and down in a channel  462  defined in the valve mechanism  412 . 
   In operation, a ball dropped into the mandrel bore  411  lands on the ball seat  436  to create a seal. Fluid is then flowed down the mandrel bore  411 , which enters the port  440  ( FIG. 6 ) into the channel  442  and longitudinal channel  452  and out into the upper chamber  418 . The increase in pressure in the chamber  418  creates a differential pressure with respect to the wellbore fluid pressure in the chamber  414 , which causes the upper hammer  404  to move up with respect to the mandrel  410 . As the upper hammer  404  moves upwardly, the spring  402  is compressed. The sleeve  472  extending below the upper hammer  404  has the inwardly protruding portion  470 . When the upper hammer  404  moves up a predetermined distance, a shoulder  474  on the protruding portion  470  makes contact with the flanged portion  432  of the piston  430 . Further upward movement of the hammer  404  causes the piston  430  to also move upwardly. 
   Upward movement of the hammer  404  moves the rod  458  and plate  460  ( FIG. 6 ) upwardly, thereby allowing fluid in the upper chamber  418  to flow through channel  462  and the port  464  into the mandrel bore  411  below the ball seat  436 . This flow of fluid from the upper chamber  418  causes a sudden loss of pressure in the upper chamber  418 , which allows the compressed upper spring  402  to drive the upper hammer  404  downwardly with respect to the mandrel  410 . The spring  402  drives the upper hammer  404  downwardly until the lower surface  422  of the hammer  404  impacts a shoulder  423  of the housing  400 . The impact creates a tensile wave within the housing  400 , which travels upward into the tool string. 
   When the sealing element  450  in the chamber  444  is in its up position, fluid flow through the mandrel bore  411  above the ball seat  464  is now sealed from the upper chamber  418 . The mandrel bore fluid flows through the port  440 , channel  442 , and channel  452  into the lower chamber  420 . The increase in the pressure of the chamber  420  exerts a downward force on the upper end portion  434  of the lower hammer  408 . This causes the lower hammer  408  to move downwardly, which compresses the spring  406 . When the lower hammer  408  moves down by a certain distance, a shoulder  476  defined at the lower surface of the portion  434  of the lower mandrel  408  makes contact with a shoulder  478  defined at a lower portion of the piston  430 . Further downward movement of the lower hammer  408  causes the piston  430  to also be pulled downwardly. 
   The downward movement of the piston  430  pulls along with it rods  458  and  446 . As a result, fluid flow into the lower chamber  420  stops, while fluid communication is again established between the lower chamber  420  and the channel  462  in the valve mechanism  412 . The fluid flows from the lower chamber  420  through the channel  462  and port  464  into the mandrel bore  411 . This results in a sudden loss of pressure from the lower chamber  420  into the mandrel bore  411  below the ball seat  436 . As a result, the spring  406  is able to drive the lower hammer  408  in an upwardly direction. When the lower hammer  408  moves upwardly by a predetermined distance, the impact shoulder  480  of the hammer  408  ( FIG. 5C ) impacts the shoulder  482  of the housing  400 . This impact creates a compressive wave within the housing  400 , which travels upwardly into the tubing string. 
   The process described above is repeated as long as an elevated pressure is provided by fluid flow down the mandrel bore  411  above the ball that is seated in the ball seat  436 . This enables oscillation of the upper and lower hammers and respective impacts between the upper hammer  404  and the housing  400  and the lower hammer  408  and the housing  400 . 
   In another embodiment, the vibration devices  16 A and  16 B used in the tubing string of  FIG. 1  provide rotational or torsional vibrations on the tubing string.  FIG. 7  shows a cross-sectional view of a rotational or torsional vibration device (having reference numeral  600 ). The rotational vibration is caused by impact between a pair of impactors  602 ,  604  coupled to a spindle mandrel  610  and a pair of connector members  606 ,  608 . The impactors  602 ,  604  are fixedly mounted to the spindle mandrel  610 , which is rotatable with respect to an outer housing  612  and an inner housing  614  of the rotational vibration device  600 . The connector members  606 ,  608  connect the inner and outer housings  614  and  612 . 
   In response to fluid differential pressure in a first direction, the spindle mandrel  610  rotates in a first rotational direction to impact the connector members  606 ,  608 . Then, in response to fluid differential pressure in the opposite direction, the spindle mandrel  610  rotates in the opposite rotational direction to cause the impactors  602 ,  604  to impact connector members  606 ,  608 . 
   The connector members  606  and  608  extend generally along the longitudinal axis of the vibration device  600 . As a result, the connector members  606 ,  608  define two chambers  616  and  618 . In addition, the impactor  602  divides the chamber  616  into two portions: a first portion  616 A and a second portion  616 B. Similarly, the impactor  604  divides the chamber  618  into two portions: a first portion  618 A and a second  618 B. 
   Four ports lead into the respective chamber portions. A first port  620  leads into chamber  616 A, a second port  622  leads into chamber portion  616 B, a third port  624  leads into chamber portion  618 A, and a fourth port  622  leads into chamber portion  618 B. As described below, an upper set of the ports  620 ,  622 ,  624 , and  626  are located at the upper end of the vibration device  600 , while a lower set of the ports  620 ,  622 ,  624 , and  626  are located at the lower end of the vibration device  600 . 
   The ports  620 ,  622 ,  624 , and  626  are selectably opened and closed to enable communication of fluid pressure into respective chambers  616 A,  616 B,  618 A, and  618 B. By controlling which ports are open and which ones are closed, a differential pressure in the desired rotational direction can be produced across the impactors  602 ,  604  to cause a desired rotational movement of the spindle mandrel  610 . By continuously rotating the impactors  602 ,  604  back and forth to impact the connector members  606 ,  608 , rotational vibration is imparted onto the tubing string that is connected to the vibration device  600 . 
   Ports  622  and  626  are opened and ports  620  and  624  are closed to enable communication of an elevated fluid pressure into chambers  616 B and  618 B, while chambers  616 A and  618 A remain at a lower pressure (e.g., wellbore hydrastatic pressure). The differential pressure created between chambers  616 B and  616 A and between chambers  618 B and  618 A causes the spindle mandrel  610  and the impactors  602 ,  604  to rotate in a direction indicated by arrows R 1 . 
   In contrast, to rotate the impactors  602 ,  604  in the other direction (indicated by arrows R 2 ), the ports  620  and  624  are opened while the ports  622  and  626  are closed. An elevated fluid pressure can then be pumped into the chambers  616 A and  618 A to create the differential pressures to move the impactors  602 ,  604  in direction R 2 . 
   Referring to  FIG. 8 , a perspective view of the spindle mandrel  610  and impactors  602  and  604  are illustrated. The impactors  602  and  604  are attached to the spindle mandrel  610  by respective connectors  630  and  632 . The connectors  630  and  632  may be in the form of pins or other attachment mechanisms. 
   Referring to  FIG. 9 , an exploded longitudinal sectional view of the vibration device  600  is illustrated. The inner housing  614  of the rotational vibration device  600  includes a longitudinal bore  615  into which the spindle mandrel  610  can be positioned. The pins  630  and  632  that attach the spindle mandrel  610  to respect impactors  602  and  604  are fitted through openings  640  and  642  in the inner housing  614 . As shown in  FIG. 9 , the impactors  602  and  604  are designed to fit into the space between the inner and outer housings  614  and  612 . 
   Sliders  650  and  652  are positioned at one end of the vibration device  16 , while sliders  654  and  656  are provided at the other end of the vibration device  16 . The sliders are generally semicircular in shape so that each pair of sliders are arranged in generally the same plane. Each slider is less than 180° semicircular (e.g., 170° semicircular) to provide room for the sliders to slide on the same plane. The sliders  650 ,  652 ,  654 , and  656  provide each set of ports  620 ,  622 ,  624 , and  626  at the upper and lower ends of the vibration device  600 . The ports  620 ,  622 ,  624 , and  626  are opened or closed based on the positions of the sliders. 
   In addition, a first valve mechanism  658  cooperates with the sliders  650  and  652  to communicate fluid through the sliders  650  and  652  into the first end of the vibration device  16 , while a second valve mechanism  660  cooperates with the sliders  654  and  656  to communicate fluid into the second end of the vibration device  16 . 
   In cooperation with the valve mechanism  658 , the rotational slider  652  controls the selected opening and closing of fluid communication between the chamber  616 A and the tubing string and between the chamber  616 B and the tubing string. Similarly, the rotational slider  650  controls the selective opening and closing of fluid communication between the chamber  618 B and the tubing string and between the chamber  618 A and the tubing string. 
   The valve mechanism  658  has a ball seat  662  adapted to receive a ball. The valve mechanism  658  also includes a first channel  664  and a second channel  666 . The sliders  650  and  652  have openings ( FIG. 10 ) that are selectively aligned with the channels  664  and  666  to enable communication of fluid through the valve mechanism  658  through the openings in the sliders to one of the chambers  616 A,  616 B,  618 A, and  618 B. 
   In conjunction with the valve mechanism  660 , the rotational slider  656  controls the selective opening and closing of fluid communication between the chamber  616 A and a region below the vibration device  600  (such as a tool connected below the device  600  or an annular region below the device  600 ). The slider  656  also controls the selective opening and closing of fluid communication between the chamber  616 B and the region below the vibration device  600 . Similarly, the rotational slider  654  controls the selective opening and closing of fluid communication between the chamber  618 B and the region below the vibration device  600 , and fluid communication between the chamber  618 A and the lower region. 
   The valve mechanism  660  includes a first channel  668  and a second channel  670  that are selectively alignable with the ports of the sliders  654  and  656 . The sliders  650 ,  652 ,  654 , and  656  are movable rotationally by actuation pins  680 ,  682 ,  684 , and  686 , respectively. The actuation pins  680 ,  682 ,  684 , and  686  are engageable by the impactors  602  and  604  as the impactors  602  and  604  rotate. 
   As shown in  FIG. 10 , each slider  700  (corresponding to one of sliders  650 ,  652 ,  654 , and  656 ) is generally semicircular (slightly less than semicircular) in shape. As a result, two rotational sliders can be placed side by side to form generally a circle. Each slider  700  includes a first port  702  and a second port  704 . In addition, the slider  700  includes an actuation pin  706  (corresponding to one of pins  680 ,  682 ,  684 , and  686 ) that when engaged by the impactor  602  or  604  causes the rotational slider  700  to rotate a predetermined angle. Rotation of the slider  700  causes the port  702  and  704  to move, thereby enabling the port  702  and  704  to move relative to channels in the valve mechanism  658  or  660 . 
   During normal operation, when torsional vibration is not needed, the vibration device  600  is used as a fluid conduit. Fluid flows from the tubing string through the central bore  601  of the hollow spindle mandrel  610 . However, when torsional vibration is desired, a ball is dropped into the string for landing onto the ball seat  662  in the valve mechanism  658 . The initial settings of the rotational sliders  650  and  652  are such that the top of chambers  616 A and  618 A are in fluid communication with the fluid from the tubing string through the valve mechanism  658 . However, the chambers  616 A and  618 A are isolated from the region below the vibration device  600  by the rotational sliders  654  and  656 . 
   On the other hand, the chambers  616 B and  618 B are in fluid communication with the region below the vibration device  600 , while the chambers  616 B and  618 B are isolated from the tubing string by the rotational sliders  650  and  652 . 
   When pressure is increased in the tubing string, a differential pressure is created between chambers  616 A and  616 B and between chambers  618 A and  618 B. As a result, the spindle mandrel  610  is rotationally accelerated by the differential pressure in the direction indicated by arrows R 2  ( FIG. 7 ). 
   The impactors  602 ,  604  are rotated until impact occurs between the impactors  602 ,  604  and connector members  606 ,  608 . However, just before the clockwise impact occurs, the impactors  602 ,  604  engage actuation pins  680 ,  682 ,  684 , and  686  of respective rotational sliders  650 ,  652 ,  654 , and  656  to shift their rotational positions. As a result, a different set of the openings in the sliders are aligned with the channels in the valve mechanisms  658  and  660  so that a different combination of the ports  620 ,  622 ,  624 , and  626  are opened and closed. In this second position, the increased pressure in the tubing string causes the spindle mandrel  610  to rotate in the opposite direction (indicated by arrows RI, as shown in  FIG. 7 ). This causes the impactors  602 ,  604  to impact the connector members  606 ,  608  in the opposite direction. Right before impact, the impactors  602 ,  604  engage the actuation pins of the rotational sliders  650 ,  652 ,  654 , and  656  to again shift the rotational sliders to the initial position. Thus, by maintaining the tubing pressure at an elevated level, the spindle mandrel  610  is rotated back and forth to cause back and forth impact between the impactors  602 ,  604  and the connector members  606 ,  608 . As a result, a relatively continuous, rotational vibration is imparted on the tubing string. 
   While the invention has been disclosed with respect to a limited number of embodiments, those skilled in the art will appreciate numerous modifications and variations therefrom. It is intended that the appended claims cover such modifications and variations as fall within the true spirit and scope of the invention.