Patent Publication Number: US-7708088-B2

Title: Vibrating downhole tool

Description:
BACKGROUND 
   1. Field of the Disclosure 
   Embodiments disclosed herein relate generally to apparatus and methods for creating a vibration within a wellbore. Specifically, the present disclosure relates to a vibrating downhole tool configured to vibrate equipment located within a wellbore. 
   2. Background Art 
   An earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. When weight is applied to the drill string, the rotating drill bit engages the earth formation and proceeds to form a borehole along a predetermined path toward a target zone. As the drill bit creates the wellbore, the drill string and/or the drill bit may become stuck within the wellbore. This may be due to the drill string contacting a wall of the wellbore, particles collapsing on and surrounding the drill bit, or any other situation known in the art. 
   Typically, when the drill bit and/or drill string becomes stuck, a jar that is coupled to the drill string may be used to free the drill bit and/or the drill string. The jar is a device used downhole to deliver an impact load to another downhole component, especially when that component is stuck. There are two primary types of jars, hydraulic and mechanical. While their respective designs are different, their operation is similar. Energy is stored in the drillstring and suddenly released by the jar when it fires, thereby imparting an impact load to a downhole component. 
   Additionally, during certain oil and gas operations, downhole components (e.g., packers, anchors, liners, etc.) may become stuck within a wellbore. Typically, a fishing tool that may include a jar, a drill collar, a bumper sub, and an overshot is used to retrieve a downhole component that is stuck. During the retrieval operation, the fishing tool is lowered into a wellbore to a depth near the downhole component. Typically, the overshot is then used to grapple the downhole component. Next, a force (e.g., an impact load) is applied to the downhole component through the use of the jar, which may free the stuck downhole component. The fishing tool may then transport the downhole component to the surface of the wellbore. 
   Accordingly, there exists a need for methods and apparatuses for improving drilling and retrieval operations in the oil and gas industry. 
   SUMMARY OF THE DISCLOSURE 
   In one aspect, embodiments of the present disclosure relate to a vibrating downhole tool comprising a housing, an inner mandrel disposed within the housing and configured to receive a drilling fluid, a mass coupled to the inner mandrel, and a plurality of turbine blades configured to receive the drilling fluid and to rotate the inner mandrel and the mass, thereby causing the vibrating downhole tool to vibrate. 
   In another aspect, embodiments of the present disclosure relate to a drilling tool assembly comprising a drill string, a drill bit coupled to the drillstring, and at least one vibrating downhole tool coupled to the drill string, the vibrating downhole tool comprising a housing, an inner mandrel configured to receive a drilling fluid, a mass coupled to the inner mandrel, and a plurality of turbine blades configured to receive the drilling fluid and to rotate the inner mandrel and the mass, thereby causing the vibrating downhole tool to vibrate. 
   In yet another aspect, embodiments of the present disclosure relate to a method of activating a vibrating downhole tool comprising pumping a fluid downhole through a drill string to the vibrating downhole tool, and selectively activating the vibrating downhole tool by actuating a flow control device proximate the vibrating downhole tool, thereby allowing the fluid to flow through the vibrating downhole tool. 
   Finally, embodiments of the present disclosure relate to a method of freeing drilling equipment stuck within a wellbore comprising pumping a fluid downhole through a drill string, diverting the fluid to flow through a plurality of turbine blades of the vibrating downhole tool, rotating a inner mandrel and a mass through the use of the plurality turbine blades, and vibrating at least one component of the drill string. 
   Other aspects and advantages of the invention will be apparent from the following description and the appended claims. 

   
     BRIEF DESCRIPTION OF DRAWINGS 
       FIG. 1  shows a drilling system in accordance with embodiments of the present disclosure. 
       FIG. 2A  shows a cross-sectional view of a vibrating downhole tool in accordance with embodiments of the present disclosure. 
       FIG. 2B  shows a top view of a vibrating downhole tool in accordance with embodiments of the present disclosure. 
       FIG. 3  shows a cross-sectional view of a vibrating downhole tool in accordance with embodiments of the present disclosure. 
       FIG. 4  shows a drilling system in accordance with embodiments of the present disclosure. 
       FIG. 5  shows a fishing system in accordance with embodiments of the present disclosure. 
   

   DETAILED DESCRIPTION 
   In one aspect, embodiments disclosed herein relate to apparatuses and methods for creating a vibration within a wellbore. Specifically, the present disclosure relates to a vibrating downhole tool configured to vibrate equipment within a wellbore. During operation, the vibrating downhole tool may divert the flow of a drilling fluid through a device that may be configured to rotate at least one component of the vibrating downhole tool, which may cause the vibrating downhole tool to vibrate. Subsequently, the equipment that may be coupled to the vibrating downhole tool may also vibrate. 
   Referring now to  FIG. 1 , a drilling system  100  in accordance with embodiments of the present disclosure is shown. The drilling system  100  includes a drill string  200 , a vibrating downhole tool  300 , and a drill bit  400 . The drilling system  100  is configured to drill a wellbore  20  and create a vibration that may be transferred into the drill string  200  and/or the drill bit  400  located below a surface of the wellbore  10 . One of ordinary skill in the art will appreciate that the drill system  100  may include other tools, such as stabilizer, motors, etc. 
   The drill string  200  is coupled to the vibrating downhole tool  300  and the drill bit  400 . As known to one skilled in the art the vibrating downhole tool  300  and the drill bit may be coupled to the drill string  200  through the use of threads, bolts, welds, or any other attachment feature known in the art. Further, the drill string  200  is configured to transfer a drilling fluid downhole to the vibrating downhole tool  300  and the drill bit  400 . For example, the drill string  200  may include at least one drill pipe (not shown) having a bore (not shown) that allows the drilling fluid to pass through the drillstring  200 . 
   The drill bit  400  is configured to crush or shear particles located at the bottom of the wellbore  20 , thereby increasing the depth of the wellbore  20 . In one embodiment, the drill bit  400  may include a fixed cutter drill bit configured to shear the particles at the bottom of the wellbore  20 . In another embodiment, the drill bit  400  may include a roller cone bit configured to crush particles at the bottom of the wellbore  20 . 
   Referring now to  FIG. 2A , a cross-sectional view of the vibrating downhole tool  300  is shown. The vibrating downhole tool  300  is configured to receive the drilling fluid and create a vibration. The vibrating downhole tool  300  includes a housing  310  with connections  312 , which allows the vibrating downhole tool  300  to be coupled to the drill string  200  and/or the drill bit  400 . Further, the vibrating downhole tool  300  includes an inner mandrel  320 , bearings  330 , a mass  340 , and a flow control device  350 . 
   The inner mandrel  320  extends through a bore  314  of the housing  310  and is configured to receive and transfer a drilling fluid through the vibrating downhole tool  300 . Additionally, in one embodiment, the inner mandrel  320  may include a plurality of turbine blades  322  disposed on an outer surface  324  of the inner mandrel  320 . Furthermore, in certain embodiments, the inner mandrel  320  may include an opening  326  that allows at least a portion of the drilling fluid flowing through the inner mandrel  320  to flow through the plurality of turbine blades  322 , thereby causing the inner mandrel  320  to rotate around axis A. 
   As depicted, the housing  310  is configured to protect and contain components (i.e., bearings, inner mandrel, mass, etc.) of the vibrating downhole tool  300 . Furthermore, the housing  310  may also include at least one annular port  316  that provides a path for at least a portion of the drilling fluid to be released from the vibrating downhole tool  300 . For example, during operation, at least a portion of the drilling fluid may pass through the opening  326  in the inner mandrel  320  and through the plurality of turbine blades  322 . Once the drilling fluid has passed through the plurality of turbine blades  322 , it may then pass through the annular port  316  and into the wellbore  20 . 
   As shown, the bearings  330  are disposed between the inner mandrel  320  and the housing  310 . The bearings  330  are configured to allow the inner mandrel  320  to rotate independently from the housing  310 . The bearings  330  may include ball bearings, fluid bearings, jewel bearings, or other bearings known in the art. 
   Further, as shown, the mass  340  is coupled to the inner mandrel  320  of the vibrating downhole tool  300 . The mass  340  may be coupled to the inner mandrel  320  by bolts, welding, or any other attachment method known in the art. As such, the mass  340  is configured to be rotated around axis A by the inner mandrel  320 . In one embodiment, the mass  340  may be eccentric. As used herein, “eccentric” refers to a mass having a center of gravity that is offset from an axis that the mass is rotated around (e.g., axis A). As the eccentric mass  340  is rotated by the inner mandrel  320 , a centrifugal force created by a rotation of the eccentric mass  320  may cause the vibrating downhole tool  300  to be displaced. In one embodiment, the rotation of the eccentric mass causes the vibrating downhole tool to be displaced in an outward direction R, as shown in  FIG. 2B . Consequently, the displacement of the vibrating downhole tool  300  creates a radial and/or axial vibration, which may be used to vibrate the drill string  200  or other components disposed within the wellbore  20 , such as, the drill bit  400 . In certain embodiments, the mass  340  may include at least one aperture (not shown) that will allow inserts (not shown) to be added and removed from the mass  340 , thereby allowing a weigh to the mass  340  to be increased. 
   Referring now to  FIG. 3 , in select embodiments, the mass  340  may include a sleeve  342  configured to translate in an upward direction U and a downward direction D as the mass  340  is rotated. The upward and downward translation of the sleeve  342  may cause the vibrating downhole tool  300  to be displaced in the upward and downward direction U, D. Accordingly, the displacement of the vibrating downhole tool  300  creates a vibration that may be used to axially vibrate the drill string  200  and/or other components within the wellbore  20 . 
   Referring back to  FIG. 2A , the flow control device  350  is configured to control the flow of the drilling fluid through the inner mandrel  320  and through the plurality of turbine blades  322 . Accordingly, during operation, the flow control device  350  may be used to selectively activate the vibrating downhole tool. In one embodiment, the flow control device  350  may include a ball drop nozzle (not shown) configured to receive a neoprene ball or a ball of any other material known in the art. During operation, the neoprene ball may be pumped down the drill string  200  and seated in the ball drop nozzle. Consequently, the drilling fluid may flow through the opening  326  in the inner mandrel  320  and through the plurality of turbine blades  322 . 
   In another embodiment, the flow control device  350  may include a valve (not shown) configured to control the flow of the drilling fluid through the inner mandrel  320  and the opening  326  in the inner mandrel  320 . For example, the valve may be positioned proximate the opening  326  and actuated to direct at least a portion of the drilling fluid in the inner mandrel  320  through the opening  326 . The drilling fluid may then flow through the plurality of turbine blades  322  and through at least one annular port  316  of the housing  310 . 
   In certain embodiments, the flow control device  350  may include an RFID Tag (not shown) that may be used to control the flow control device  350 . For example, a controller (not shown) may be electronically coupled to the RFID tag. Further, the controller may send a signal to the flow control device  350  that may be received by the RFID tag and used to actuate the flow control device  350 , thereby diverting at least a portion of the drilling fluid through the opening  326  in the inner mandrel  320 . Additionally, in some embodiments, the flow control device  350  may include a sensor that receives a signal from the RFID tag that may be used to actuate the flow control device  350 . 
   Referring to  FIGS. 1 and 2A , during operation of the drilling system  100 , the drilling fluid is pumped through the drill string  200  to the vibrating downhole tool  300  located below the surface  10 . The drilling fluid then flows into the inner mandrel  320  of the vibrating downhole tool  300 . Next, the inner mandrel  320  transfers the drilling fluid through the vibrating downhole tool  300 . While the drilling fluid is being transferred through the vibrating downhole tool  300 , the flow control device  350  may be selectively actuated to divert a portion of the drilling fluid through the opening  326  of the inner mandrel  320 . The diverted portion of drilling fluid will then flow through the plurality of turbine blades  322 , thereby causing the inner mandrel  320  and mass  340  to rotate. Consequently, the vibrating downhole tool  300  will be displaced, which will cause the vibrating downhole tool  300  to vibrate. One skilled in the art will appreciate that the vibration created by the vibrating downhole tool  300  may be used to vibrate the drillstring  200  and/or other components, such as the drill bit  400 . After the diverted portion of drilling fluid has passed through the plurality of turbine blades  322 , the diverted portion of drilling fluid flows through the annular port  316  of the housing  310  and into the wellbore  20 . In one embodiment, the drilling fluid that is allowed to pass through the vibrating downhole tool  300  flows into the drill string  200  below the vibrating downhole tool  300  and onto the drill bit  400  located at the bottom of the wellbore  20 . In an alternate embodiment, the drilling fluid that is allowed to pass through the vibrating downhole tool  300  flows directly into the drill bit  400 . 
   In certain embodiments, during operation, the flow control device  350  may control a flow rate of the portion of the drilling fluid passing through the plurality of turbine blades  322 . In one embodiment, the flow control device  350  may be further actuated to increase the flow rate of the portion of the drilling fluid passing through the plurality of turbine blades  322 . In another embodiment, the flow control device  350  may be de-actuated to decrease the flow rate of the portion of drilling fluid passing through the plurality of turbine blades  322 . 
   As known by one skilled in the art, controlling the flow rate of the portion of drilling fluid passing through the plurality of turbine blades  322  may allow a frequency of the vibration created by the vibrating downhole tool to be controlled. For example, as the flow rate of the portion of the drilling fluid passing through the plurality of turbines  322  increases, a rotational speed of the mass  340  coupled to the inner mandrel  320  increases. As the rotational speed of the mass  340  increases, the vibrating downhole tool  300  may be displaced more often over a certain period of time, thereby increasing the frequency of vibrations created by the vibrating downhole tool  300 . 
   Further, in certain embodiments, the vibrating downhole tool  300  may include a motor (not shown), such as a positive displacement motor (PDM), an electric motor, or any other motor known in the art. The motor may configured to selectively rotate the inner mandrel  320  and the mass  340 , thereby selectively activating the vibrating downhole tool  300  during operation. In one embodiment, the motor may be coupled to the inner mandrel  320  and the mass  340  and a power supply (not shown). As such, the power supply may selectively provide the motor with an electric power, which may be used to rotate the motor, thereby causing the vibrating downhole tool  300  to vibrate. 
   Furthermore, in certain embodiments, the drilling system  100  may include a plurality of vibrating downhole tools  300  coupled to the drill string  200  and positioned at various depths within the wellbore  20 , as shown in  FIG. 4 . This may allow the drilling system  100  to selectively vibrate various sections of the drill string  200 . Additionally, one skilled in the art will appreciate that when at least one of the plurality of vibrating downhole tools  300  is inoperable, another of the plurality of vibrating downhole tools  300  may be used to vibrate the drill string  200 , thereby increasing the reliability of the drilling system  100 . 
   During oil and gas operations, downhole components (e.g., packers, anchors, liners, etc.) may become stuck within the wellbore. Accordingly, one skilled in the art will appreciate that the vibrating downhole tool  300  may be incorporated within a fishing system to retrieve a downhole component that is stuck. For example, referring now to  FIG. 5 , a fishing system  110  in accordance in with embodiments of the present disclosure is shown. In one embodiment, the fishing system  110  includes a fishing tool  500 , a drill string  200 , and a vibrating downhole tool  300 . The drill string  200  is configured to transport a fluid downhole to the fishing tool  500  and/or the vibrating downhole tool  300 . Generally, as known to one skilled in the art, the fishing tool  500  includes a jar (not shown), a drill collar (not shown), a bumper sub (not shown), and an overshot (not shown) configured to retrieve at least one piece of downhole equipment  600 . As described above, the vibrating downhole tool  300  is configured to receive the fluid from the drill string  200  and create a vibration. During operation, the vibrating downhole tool  300  may be configured to receive the fluid pumped downhole through the drill string  200 . Further, the vibrating downhole tool  300  may vibrate the drill string  200  and/or the at least one piece of downhole equipment  600  that is stuck to assist the fishing tool  500  in freeing and retrieving the at least one piece downhole equipment  600 . 
   Advantageously, embodiments of the present disclosure may improve movement of equipment within a wellbore during operations. The vibration created by the vibrating downhole tool may displace the drillstring away from the wall of the wellbore, thereby reducing the friction between the wall of the wellbore and the drill string. Because the friction between the wall of the wellbore and the drill string is reduced the drill string may move more easily within the wellbore. Further, the vibration may also displace the downhole component attached to the drill string. In one example, this may prevent the downhole components (i.e., drill bit, stuck pieces of equipment) from getting stuck during operation. 
   Additionally, embodiments of the present disclosure provide a system configured to retrieve a downhole component stuck within a wellbore. The vibration created by the vibrating downhole tool of the system may displace the downhole component, which may assist in freeing the downhole equipment stuck within the wellbore. 
   Furthermore, embodiments of the present disclosure may provide a vibrating downhole tool configured to be selectively activated during operation. The vibrating downhole tool may include a device (e.g., flow control device) configured to be actuated, thereby activating the vibrating downhole tool. 
   While the present disclosure has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments may be devised which do not depart from the scope of the disclosure as described herein. Accordingly, the scope of the disclosure should be limited only by the attached claims.