Patent Application
20150368978
None
This disclosure relates generally to methods and apparatus for drilling wellbores. More specifically, this disclosure relates to methods and apparatus for increasing the diameter of a wellbore through reaming operations. Still more specifically, this disclosure relates to increasing the diameter of a wellbore without rotating the drill string.
In drilling a wellbore into the earth, such as for the recovery of hydrocarbons, a drill bit is connected onto the lower end of an assembly of drill pipe sections known as a drill string. The drill string is rotated so that the drill bit progresses downward into the earth to create the desired wellbore. In certain applications, such as the drilling of deviated or horizontal wellbores, the drill string is not rotated and downhole motors are used to rotate the drill bit. The downhole motors are often powered by pressurized drilling fluid pumped through the drill string. In addition to providing a conduit for the supply of pressurized fluid, the drill string may not rotate but can be used to transfer torque to lower end of the drill string, known as the bottom hole assembly, to help guide the path of the drill bit as it forms the wellbore.
During drilling, cuttings produced from the formation are carried away from the drill bit by the upward velocity of the drilling fluid. As the wellbore becomes more deviated from vertical, gravitational forces decrease the ability of the drilling fluid to carry cuttings out of the wellbore and the cuttings may settle along the bottom side of the wellbore. Settled cuttings, and the friction generated by the drill string contacting the bottom side of the wellbore can significantly increase the drag forces on the drill string.
In many drilling applications, the wellbore may need to be enlarged after it is initially drilled. This process is known as reaming. Reaming may be used to enlarge a section of the hole that was drilled too small, to open a section of wellbore, to remove an obstruction or dogleg from the wellbore, or any number of other operational reasons. Most conventional reamers are operated by rotating the drill string and therefore cannot be used in highly deviated wellbores or with systems that don't allow for rotating the drill string.
Thus, there is a continuing need in the art for methods and apparatus for methods and apparatus to enlarge a wellbore using a reamer.
A powered reamer comprising a stationary assembly having a flow bore therethrough. A rotating assembly is disposed about the stationary assembly and one or more cutting structures are coupled to an outer surface of the rotating assembly. A flow restriction is disposed within the flow bore so as to divert a portion of fluid flowing through the flow bore through an outlet from the flow bore into an annulus between the stationary assembly and the rotating assembly. A power section is formed in the annulus between the stationary assembly and the rotating assembly. The power section operates to eccentrically rotate the rotating assembly about the stationary assembly in response to fluid flowing through the annulus between the stationary assembly and the rotating assembly.
For a more detailed description of the embodiments of the present disclosure, reference will now be made to the accompanying drawings, wherein:
It is to be understood that the following disclosure describes several exemplary embodiments for implementing different features, structures, or functions of the invention. Exemplary embodiments of components, arrangements, and configurations are described below to simplify the present disclosure; however, these exemplary embodiments are provided merely as examples and are not intended to limit the scope of the invention. Additionally, the present disclosure may repeat reference numerals and/or letters in the various exemplary embodiments and across the Figures provided herein. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various exemplary embodiments and/or configurations discussed in the various figures. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact. Finally, the exemplary embodiments presented below may be combined in any combination of ways, i.e., any element from one exemplary embodiment may be used in any other exemplary embodiment, without departing from the scope of the disclosure.
Additionally, certain terms are used throughout the following description and claims to refer to particular components. As one skilled in the art will appreciate, various entities may refer to the same component by different names, and as such, the naming convention for the elements described herein is not intended to limit the scope of the invention, unless otherwise specifically defined herein. Further, the naming convention used herein is not intended to distinguish between components that differ in name but not function. Additionally, in the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to.” All numerical values in this disclosure may be exact or approximate values unless otherwise specifically stated. Accordingly, various embodiments of the disclosure may deviate from the numbers, values, and ranges disclosed herein without departing from the intended scope. Furthermore, as it is used in the claims or specification, the term “or” is intended to encompass both exclusive and inclusive cases, i.e., “A or B” is intended to be synonymous with “at least one of A and B,” unless otherwise expressly specified herein.
Referring initially to
As the powered reamer 20 operates the lower stabilizer 18 and upper stabilizer 22 act to center the powered reamer 20 within the wellbore 10 so as to provide circumferential stability to the wellbore 10. In order to center the powered reamer 20, the lower stabilizer 18 is sized so as to closely engage the first gauge diameter 26 of the un-reamed wellbore portion 24. Similarly, the upper stabilizer 22 is sized so as to closely engage the second gauge diameter 30 of the wellbore 10. This close engagement allows the powered reaming assembly 14 to move axially through the wellbore 10 while minimizing radial movement within the wellbore 10.
Referring now to
Referring now to
Referring back to
In operation, fluid flows through the flow bore 42 into the power mandrel 36. A portion of the fluid flows through outlets 52 into the annulus between the rotating assembly 32 and the power mandrel 36. The flow that moves into the annulus moves through the power section 48, causing the rotating assembly 32 to eccentrically rotate about the stationary assembly 34. Once the fluid passes through the power section 48, it re-enters the flow bore 42 through inlets 54. The power section 48 may be configured such that the rotating assembly 32 rotates either clockwise or counterclockwise about the stationary assembly 34. In certain embodiments, the rotation of the powered reamer 20 may be configured to rotate in a direction opposite the rotation of a drill bit disposed below the powered reaming assembly 14. The counter-rotation may be useful in decreasing the torque load on the drill string above the powered reaming assembly 14.
As can be seen in
Seal assemblies 40 limit the loss of fluid as it moves through the annulus between the rotating assembly 32 and the stationary assembly 34. In certain embodiments, seal assemblies 40 allow a certain portion of the fluid to bypass the seal assemblies 40 and flow into the annulus between the powered reaming assembly 14 and the surrounding wellbore 10 so as to provide lubrication and/or help in the removal of cuttings from the wellbore. In other embodiments, the seal assemblies 40 may retain substantially all of the fluid within the powered reaming device 14, which may allow other fluid powered tools to operated downstream of the powered reaming assembly 14. The seal assemblies 40 may be elastomeric seals, brush seals, tortuous flow seals, face seals, combinations thereof, or other seal configurations that allows eccentric rotation. Seal assemblies 40 may also act as bearings to support the axial thrust load on the rotating assembly 32 during reaming.
In certain embodiments, the upper stabilizer 22 may be omitted to allow the powered reaming assembly 14 to pass through a smaller inside diameter section of the wellbore before reaming a larger diameter section of the wellbore below. Alternatively, the upper stabilizer 22 can have a variable or adjustable gauge and be activated once the powered reaming assembly 14 is placed in position within the wellbore before the reaming operation commences and the variable gauge stabilizer can be extended to closely engage the wellbore from a clearance position immediately prior to the reaming operation. In other embodiments, upper stabilizer 22 may not be used at all and the powered reaming assembly 14 could be run with only the powered reamer 20 and the lower stabilizer 18.
While the disclosure is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and description. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the disclosure to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present disclosure.
