FRICTION REDUCING STABILIZER

Abstract

Embodiments of the present disclosure are directed towards a friction reducing stabilizer. The friction reducing stabilizer includes an annular body and a plurality of blades, wherein each of the plurality of blades extends radially outward from the annular body and has a bearing mechanism configured to contact an annular down-hole component.

Description

FIELD OF DISCLOSURE

The present disclosure relates generally to the field of well drilling operations. More specifically, embodiments of the present disclosure relate to stabilizers for use with down-hole components in a down-hole environment.

BACKGROUND

In conventional oil and gas operations, a well is typically drilled to a desired depth with a drill string, which includes drill pipe and a drilling bottom hole assembly (BHA). Once the desired depth is reached, the drill string is removed from the hole and casing is run into the vacant hole. In some conventional operations, the casing may be installed as part of the drilling process. A technique that involves running casing at the same time the well is being drilled may be referred to as “casing-while-drilling.”

Casing may be defined as pipe or tubular that is placed in a well to prevent the well from caving in, to contain fluids, and to assist with efficient extraction of product. When the casing is properly positioned within a hole or well, the casing is typically cemented in place by pumping cement through the casing and into an annulus formed between the casing and the hole (e.g., a wellbore or parent casing). Once a casing string has been positioned and cemented in place or installed, the process may be repeated via the now installed casing string. For example, the well may be drilled further by passing a drilling BHA through the installed casing string and drilling. Further, additional casing strings may be subsequently passed through the installed casing string (during or after drilling) for installation. Indeed, numerous levels of casing may be employed in a well. For example, once a first string of casing is in place, the well may be drilled further and another string of casing (an inner string of casing) with an outside diameter that is accommodated by the inside diameter of the previously installed casing may be run through the existing casing. Additional strings of casing may be added in this manner such that numerous concentric strings of casing are positioned in the well, and such that each inner string of casing extends deeper than the previously installed casing or parent casing string.

Liner may also be employed in some drilling operations. Liner may be defined as a string of pipe or tubular that is used to case open hole below existing casing. Casing is generally considered to extend all the way back to a wellhead assembly at the surface. In contrast, a liner merely extends a certain distance (e.g., 30 meters) into the previously installed casing or parent casing string. The liner is typically secured to the parent casing string by a liner hanger that is coupled to the liner and engages with the interior of the upper casing or liner. It should be noted that, in some operations, a liner may extend from a previously installed liner or parent liner. Further, as with casing, a liner is typically cemented into the well.

As mentioned above, the drill string generally includes a drill pipe and a BHA, which includes a variety of tools. Periodically, the BHA and/or other tools connected to the drill pipe may need to be retrieved from or reset within the well. It is now recognized that retrieving or resetting the BHA and/or other down-hole tools may be difficult due to friction forces between the drill pipe and other components of the well that surround the drill pipe, such as casing, liners, strings, and so forth. Additionally, it is now recognized that friction forces between the drill pipe and other components of the well may be higher in lateral sections of the well (e.g., sections of the well that are drilled in a horizontal or partially horizontal direction).

BRIEF DESCRIPTION

In a first embodiment, a friction reducing stabilizer configured to be disposed within an annular down-hole component includes an annular body and a plurality of blades, wherein each of the plurality of blades extends radially outward from the annular body and includes a bearing mechanism configured to contact the annular down-hole component.

In a second embodiment, a system includes a drill pipe, an annular body of a friction reducing stabilizer coupled to the drill pipe, and a plurality of blades of the friction reducing stabilizer extending radially outward from the annular body, wherein each of the plurality of blades has a bearing mechanism configured to contact an annular down-hole component.

In a third embodiment, a method for limiting friction between a down-hole component and a casing or liner includes coupling a friction reducing stabilizer to the down-hole component, positioning the down-hole component coupled with the friction reducing stabilizer within a wellbore having the casing or the liner, and translating the down-hole component coupled with the friction reducing stabilizer such that at least one bearing mechanism of the friction reducing stabilizer engages with the casing or the liner during translation of the down-hole component and limits contact between the down-hole component and the casing or the liner.

DRAWINGS

These and other features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein:

FIG. 1 is a schematic representation of a well being drilled, in accordance with aspects of the present disclosure;

FIG. 2 is a schematic representation of a friction reducing stabilizer within a wellbore, in accordance with aspects of the present disclosure;

FIG. 3 is a schematic side view of an embodiment of a friction reducing stabilizer, in accordance with aspects of the present disclosure;

FIG. 4 is a schematic axial view of an embodiment of a friction reducing stabilizer, in accordance with aspects of the present disclosure;

FIG. 5 is a perspective view of an embodiment of a friction reducing stabilizer, in accordance with aspects of the present disclosure; and

FIG. 6 is a flow chart of a method for limiting friction between a down-hole component and a casing or a liner, in accordance with aspects of the present disclosure.

DETAILED DESCRIPTION

The present disclosure relates generally to the attachment of a friction reducing stabilizer (or other structure) to a down-hole component, such as a drill pipe. More specifically, certain embodiments of the present disclosure are directed to providing and using a stabilizer with a drill pipe to reduce friction between the drill pipe and surfaces surrounding the drill pipe, such as casing, liners, and so forth. In one implementation, a stabilizer includes an annular body, which may couple to and/or be disposed about the drill pipe, and a plurality of blades extending radially outward from the annular body. Each of the plurality of blades includes bearing balls disposed in a respective pocket of each of the plurality of blades, such that a portion of the bearing balls are exposed, via at least one opening in each blade, to define a radial perimeter of the stabilizer. When the stabilizer and the drill pipe are disposed within the well, the bearing balls of the stabilizer may contact a casing, liner, string, or other component of the well. As a result, the stabilizer may limit contact between the drill pipe and the casing, liner, string, or other component. As the drill pipe and the stabilizer translate within the well, the bearing balls rotate within the blades of the stabilizer and along surfaces surrounding the drill pipe (e.g., casing, liner, string, etc.). In this manner, frictional forces between surfaces surrounding the drill pipe and the drill pipe may be reduced. Additionally, the rotation of the bearing balls may reduce the torque required to rotate the stabilizer and the drill pipe within the well. Consequently, retrieval and/or resetting of a BHA and/or other tools or the rotation of a liner (for purposes of running or drilling) within the well may be simplified and/or improved.

Turning now to the drawings, FIG. 1 is a schematic representation of a well 10 using a drill pipe having friction reducing stabilizers. In the illustrated embodiment, the well 10 includes a derrick 12, wellhead equipment 14, and several levels of casing 16 (e.g., pipe). For example, the well 10 includes a conductor casing 18, a surface casing 20, and an intermediate casing 22. In certain embodiments, the casing 16 may include 30 foot segments of oilfield pipe having a suitable diameter (e.g., 13⅜ inches) that are joined as the casing 16 is lowered into a wellbore 24 of the well 10. As will be appreciated, in other embodiments, the length and/or diameter of segments of the casing 16 may be other lengths and/or diameters. The casing 16 is configured to isolate and/or protect the wellbore 24 from the surrounding subterranean environment. For example, the casing 16 may isolate the interior of the wellbore 24 from fresh water, salt water, or other minerals surrounding the wellbore 24.

The casing 16 may be lowered into the wellbore 24 with a running tool. As shown, once each level of casing 16 is lowered into the wellbore 24 of the well, the casing 16 is secured or cemented in place with cement 26. For example, the cement 26 may be pumped into the wellbore 24 after each level of casing 16 is landed in place within the wellbore 24. Furthermore, the well 10 may include a liner 28 disposed within the wellbore 24 and the casing 16 (e.g., the intermediate casing 22) and held in place by cement 26. Specifically, the liner 28 may be hung from the casing 16 (e.g., the intermediate casing 22) within the wellbore 24. With the levels of casing 16 and the liner 28 in place, a drill pipe 30 and a drilling BHA 32 may extend into the wellbore 24 for operation. For example, the drill pipe 30 and the drilling BHA 32 may complete a drilling process within the wellbore 24. In certain embodiments, the drilling BHA 32 may include a variety of tools that are used to complete the drilling process. In the illustrated embodiment, the BHA 32 includes a liner shoe 34 at the bottom of a liner string 36. Additionally, the BHA 32 includes a drill bit 38 and an under reamer 40. Once a desired depth of the wellbore 24 is reached, a liner string may be hung or set down to facilitate detachment of the drilling BHA 32. For example, a liner string may be hung from the liner 28, and the drilling BHA 32 may be detached from the liner string and pulled out of the well 10 with the drill string 30. Thereafter, the wellbore 24 and the well 10 may be further prepared for production of a production fluid (e.g., oil or natural gas).

As will be appreciated, a terminal point 42 of the wellbore 24 (e.g., a location of the subterranean minerals being recovered by the well 10) is a vertical distance 44 from a surface 46 or land formation in which the well 10 is drilled. Additionally, in certain embodiments, the terminal point 42 of the wellbore 24 may be offset a horizontal distance 48 from a location 50 in the surface 46 where the well 10 is drilled. Consequently, the wellbore 24 may include one or more lateral sections 52. As shown, the lateral section 52 is a portion of the wellbore 24 that extends at least partially in a horizontal direction. In certain embodiments, the horizontal distance 48 (e.g., horizontal offset) may be greater than the vertical distance 44 (e.g., vertical depth) of the well 10. For example, the horizontal distance 48 may be approximately twice the vertical distance 44.

As discussed in detail below, within the lateral section 52 of the wellbore 24, the drill pipe 30 may contact the down-hole components surrounding the drill pipe 30 (e.g., casing 16, liner 28, and so forth). More specifically, the drill pipe 30 may contact a lower side 54 of the down-hole components surrounding the drill pipe 30 due to gravitational forces acting on the drill pipe 30. In the illustrated embodiment, the drill pipe 30 may contact the lower side 54 of the liner 28 in the lateral section 52 of the wellbore 24. However, in other embodiments, the lateral section 52 may include casing 16 or other down-hole components having lower sides 54 that the drill pipe 30 may contact. As discussed below, the contact between the drill pipe 30 and the lower side 54 of the down-hole components surrounding the drill pipe 30 may result in frictional forces acting on the drill pipe 30 as the drill pipe 30 is translated in an axial direction and/or a rotational direction. The frictional forces may make the retrieval or resetting of the BHA 32 and other down-hole tools more difficult. Therefore, to reduce the frictional forces acting on the drill pipe 30 (e.g., within the lateral section 52 of the wellbore 24 or within other sections of the wellbore 24), the drill pipe 30 includes friction reducing stabilizers 56. The friction reducing stabilizers 56 are configured to reduce friction between the drill pipe 30 and the down-hole components (e.g., the liner 28 and/or casing 16) surrounding the drill pipe 30. In this manner, the friction reducing stabilizers 56 facilitate axial and/or rotational translation of the drill pipe 30 within the wellbore 24, which may improve processes for retrieving and/or resetting BHAs 32 and other down-hole tools within the wellbore 24. While the illustrated embodiment includes four friction reducing stabilizers 56, other embodiments may include more or fewer friction reducing stabilizers 56. Additionally, spacing between friction reducing stabilizers 56 along the drill pipe 30 may vary in different embodiments.

FIG. 2 is a schematic representation of the friction reducing stabilizer 56 within the lateral section 52 of the wellbore 24, illustrating various forces which may act on the friction reducing stabilizer 56 and the drill pipe 30. As discussed below with reference to FIGS. 3 and 4, the friction reducing stabilizer 56 has blades including bearings (not shown) which extend radially outward from an annular body of the friction reducing stabilizer 56, giving the friction reducing stabilizer 56 a larger diameter than the drill pipe 30. Consequently, the blades of the friction reducing stabilizer 56 may contact the down-hole component surrounding the drill pipe 30 and the friction reducing stabilizer 56 (e.g., the liner 28 or the casing 16).

As mentioned above, within the lateral section 52 of the wellbore 24, a gravitational force 100 may act on the drill pipe 30 and the friction reducing stabilizer 56. As the friction reducing stabilizer 56 contacts the liner 28 in the illustrated embodiment, the liner 28 exerts a normal force 102 on the friction reducing stabilizer 56. As will be appreciated, the normal force 102 is equal and opposite in magnitude to the gravitational force 100 acting on the friction reducing stabilizer 56. Due to the contact between the friction reducing stabilizer 56 and the liner 28 and the gravitational and normal forces 100 and 102, friction forces may act on the friction reducing stabilizer 56 as the friction reducing stabilizer 56 is moved or translated within the wellbore 24. For example, when the friction reducing stabilizer 56 and the drill pipe 30 are translated in a direction 104, a frictional force may act on the friction reducing stabilizer 56 in a direction 106. Similarly, when the friction reducing stabilizer 56 and the drill pipe 30 are translated in the direction 106, a frictional force may act on the friction reducing stabilizer 56 in the direction 104.

As discussed in detail below, the friction reducing stabilizer 56 is configured to reduce the frictional forces acting on the friction reducing stabilizer 56 (e.g., in the directions 104 and/or 106) relative to forces that would be exerted on the drill pipe 30 alone when the friction reducing stabilizer 56 and the drill pipe 30 are translated within the wellbore 24 (e.g., in the directions 104 and/or 106). Additionally, the friction reducing stabilizer 56 may be configured to enable improved rotation of the drill pipe 30 within the wellbore 24 by reducing friction forces acting on the friction reducing stabilizer 56. In this manner, movement of the drill pipe 30 within the wellbore 24, particularly within the lateral section 52 of the wellbore 24, may be improved. For example, in certain embodiments, removal and/or resetting of the BHA 32 and other down-hole tools within the wellbore 24 may be improved.

FIG. 3 is a schematic representation of a side view of an embodiment of the friction reducing stabilizer 56. As mentioned above, the friction reducing stabilizer 56 may be coupled between two segments of drill pipe 30 (e.g., a first segment 120 and a second segment 122). Alternatively, the friction reducing stabilizer 56 may be disposed about the drill pipe 30. That is, the friction reducing stabilizer 56 may slide onto the drill pipe 30 and be secured at a desired location along the drill pipe 30. In the illustrated embodiment, the friction reducing stabilizer 56 is coupled between first and second segments 120 and 122 of drill pipe 30 with connectors 124. For example, the connectors 124 may include threads, clamps, bolts, compression connections, and so forth.

The friction reducing stabilizer 56 includes an annular body 126 with a plurality of blades 128 that extend radially outward from the annular body 126. For example, the friction reducing stabilizer 56 may have 3, 4, 5, 6, or more blades 128. In certain embodiments, the annular body 126 may be configured to receive the drill pipe 30. That is, the annular body 126 may function as a sleeve or bands disposed about the drill pipe 30. In other embodiments, the annular body 126 may be configured to flow a drilling fluid, such as a process fluid or a production fluid. More specifically, in embodiments where the friction reducing stabilizer 56 is disposed between first and second segments 120 and 122 of drill pipe 30, the annular body 126 may be configured to flow a drilling fluid. Moreover, in certain embodiments, the annular body 126 and the blades 128 may be formed from a single piece of material. Alternatively, the blades 128 may be formed separately and subsequently coupled to the annular body 126 by a welding or brazing process, for instance. Furthermore, the annular body 126 and the blades 128 may be formed from the same material or different materials. For example, the annular body 126 and the blades 128 may be formed from steel or other metal.

Each blade 128 of the friction reducing stabilizer 56 includes a pocket 130. The pocket 130 in each blade 128 may be formed by a machining process, such as drilling, boring, grinding, and so forth. As shown, each pocket 130 includes a plurality of bearing balls 132. More specifically, the plurality of bearing balls 132 are disposed and secured at least partially within the pocket 130 of the respective blade 128. For example, in the illustrated embodiment, the bearing balls 132 are held within the pocket 130 of each blade 128 by a cap 134. The cap 134 includes an opening 136 which exposes at least a portion of the bearing balls 132 to an exterior of the friction reducing stabilizer 56. As a result, when the friction reducing stabilizer 56 is disposed within the wellbore 24, the bearing balls 132 may contact the down-hole component surrounding the drill pipe 30 and the friction reducing stabilizer 56 (e.g., the liner 28 or the casing 16). When the drill pipe 30 is translated axially or rotationally within the wellbore 24, the bearing balls 132 rotate within the respective pockets 130 of the blades 128 and roll along the down-hole component surrounding the drill pipe 30 and the friction reducing stabilizer 56 (e.g., the liner 28 or the casing 16). In this manner, the coefficient of friction (e.g., the frictional forces) between the friction reducing stabilizer 56 and the liner 28 or the casing 16 may be reduced. Consequently, movement of the drill pipe 30 within the wellbore 24 may be improved. As a result, the resetting or removal of down-hole tools, such as the BHA 32, may be simplified and/or improved.

In this illustrated embodiment, each blade 128 includes three bearing balls 132 disposed within the respective pocket 130 of each blade 128. However, other embodiments of the friction reducing stabilizer 56 may include other numbers of bearing balls 132. Furthermore, different embodiments of the friction reducing stabilizer 56 may have bearing balls 132 of different grades, materials, sizes, and so forth. During operation, in certain embodiments, the bearing balls 132 may be lubricated by a drilling fluid, process fluid, production fluid, or other lubricating fluid. For example, the bearing balls 132 may be lubricated by drilling mud or production oil. Additionally, in the illustrated embodiment, each blade 128 has chamfered surfaces 138, which may help guide the friction reducing stabilizer 56 into and/or through the wellbore 24. It should also be noted that, while the illustrated embodiment includes a single pocket 130 with multiple bearing balls 132 disposed therein, in other embodiments, the pocket 130 may be divided into multiple pockets with one or more bearing balls 132 positioned therein.

FIGS. 4 and 5 are additional views of exemplary embodiments of the friction reducing stabilizer 56. More specifically, FIG. 4 is a schematic axial view of an embodiment of the friction reducing stabilizer 56, and FIG. 5 is a perspective view of an embodiment of the friction reducing stabilizer 56. As discussed above, the blades 128 of the friction reducing stabilizer 56 extend radially outward from the annular body 126 of the friction reducing stabilizer 56. As a result, a diameter 150 of the friction reducing stabilizer 56 is greater than a diameter 152 of the annular body 126, where the diameter 152 of the annular body 126 may be substantially similar to a diameter of the drill pipe 30. Additionally, in the illustrated embodiment, the blades 128 are positioned equidistant from one another about the annular body 126 of the friction reducing stabilizer 56. It should noted that other embodiments of the friction reducing stabilizer 56 having different numbers of blades 128 (e.g., 3, 5, 6, or more) may also have equidistant spacing between the blades 128. In this manner, the friction reducing stabilizer 56 may also serve as a centralizer for the drill pipe 30. In other words, the friction reducing stabilizer 56 may also operate to keep the drill pipe 30 centered within the wellbore 24 when deployed and operated (e.g., rotated).

FIG. 6 is a flow chart of a method 150 for limiting friction between a down-hole component, such as the drill pipe 30, and the casing 16 or the liner 28. The method includes coupling the friction reducing stabilizer 56 to the down-hole component, as indicated by block 152. The method 150 also includes positioning the down-hole component (e.g., the drill pipe 30) coupled with the friction reducing stabilizer 56 within the wellbore 24 having the casing 16 or the liner 28, as represented by block 154. Further, the method 150 includes translating the down-hole component (e.g., the drill pipe 30) coupled with the friction reducing stabilizer 56 such that at least one bearing mechanism of the friction reducing stabilizer 56 engages with the casing 16 or the liner 28 during translation of the down-hole component and limits contact between the down-hole component and the casing 16 or the liner 28, as represented by block 156. In certain embodiments, the method 150 may include rotating the bearing balls 132 along an inner surface of the casing 16 or the liner 28 while translating the down-hole component (e.g., the drill pipe 30) within the wellbore 24. For example, as discussed above, the bearing balls 132 may be retained within the blades 128, which may extend radially outward from the down-hole component (e.g., the drill pipe 30).

As discussed in detail above, the disclosed embodiments include the attachment of the friction reducing stabilizer 56 to a down-hole component, such as the drill pipe 30. More specifically, the friction reducing stabilizer 56 is configured to reduce friction between the drill pipe 30 and down-hole surfaces surrounding the drill pipe 30, such as casing 16, liners 28, and so forth. For example, the friction reducing stabilizer 56 may include the annular body 126, which may couple to and/or be disposed about the drill pipe 30, and a plurality of blades 128 extending radially outward from the annular body 126. Each of the plurality of blades 128 includes bearing balls 132 disposed in the respective pocket 130 of each of the plurality of blades 128, where the bearing balls 132 are at least partially exposed via an opening each of the blades 128 to define a radial perimeter of the friction reducing stabilizer 56. When the friction reducing stabilizer 56 and the drill pipe 30 are disposed within the wellbore 24, the bearing balls 132 of the friction reducing stabilizer 56 may contact the casing 16, the liner 28, string, or other component within the wellbore 24. As the drill pipe 30 and the friction reducing stabilizer 56 translate within the wellbore 24, the bearing balls 132 rotate within the blades 128 of the friction reducing stabilizer 56 and along down-hole surfaces surrounding the drill pipe 30 (e.g., the casing 16, the liner 28, string, etc.). In this manner, frictional forces between surfaces surrounding the drill pipe 30 and the drill pipe 30 may be reduced. Additionally, the rotation of the bearing balls 132 may reduce the torque required to rotate the friction reducing stabilizer 56 and the drill pipe 30 within the wellbore 24. Consequently, retrieval and/or resetting of the BHA 32 and/or other down-hole tools within the wellbore 24 may be improved.

While only certain features of the invention have been illustrated and described herein, many modifications and changes will occur to those skilled in the art. It is, therefore, to be understood that the appended claims are intended to cover all such modifications and changes as fall within the true spirit of the invention.

Claims

1. A friction reducing stabilizer configured to be disposed within an annular down-hole component, comprising:

an annular body; and

a plurality of blades, wherein each of the plurality of blades extends radially outward from the annular body and includes a bearing mechanism configured to contact the annular down-hole component.

2. The friction reducing stabilizer of claim 1, comprising engagement features configured to couple between a first drill pipe segment and a second drill pipe segment.

3. The friction reducing stabilizer of claim 1, wherein the friction reducing stabilizer is configured to be disposed about a drill pipe.

4. The friction reducing stabilizer of claim 1, wherein the bearing mechanism comprises a plurality of bearing balls retained within a respective pocket of each of the plurality of blades, wherein each of the plurality of bearing balls is at least partially exposed to an exterior of the respective blade, and each of the plurality of bearing balls is configured to contact the annular down-hole component.

5. The friction reducing stabilizer of claim 1, wherein the bearing mechanism comprises a plurality of pockets and each of the plurality of pockets retains a bearing ball at least partially exposed to an exterior of the respective blade.

6. The friction reducing stabilizer of claim 1, wherein the bearing mechanism is lubricated by drilling mud or production oil.

7. The friction reducing stabilizer of claim 1, wherein the annular down-hole component is a casing or a liner.

8. The friction reducing stabilizer of claim 1, wherein each of the plurality of blades has at least one chamfered surface.

9. The friction reducing stabilizer of claim 1, wherein each of the plurality of blades is positioned equidistant from other blades about the annular body.

10. The friction reducing stabilizer of claim 1, wherein the annular body comprises at least one band configured to couple the plurality of blades to a drill pipe.

11. A system, comprising:

a drill pipe;

an annular body of a friction reducing stabilizer coupled to the drill pipe; and

a plurality of blades of the friction reducing stabilizer extending radially outward from the annular body, wherein each of the plurality of blades includes a bearing mechanism configured to contact an annular down-hole component.

12. The system of claim 11, wherein an outer diameter of the friction reducing stabilizer is greater than a diameter of the drill pipe.

13. The system of claim 11, wherein the friction reducing stabilizer is configured to be coupled between a first segment of the drill pipe and second segment of the drill pipe.

14. The system of claim 11, wherein the annular body of the friction reducing stabilizer is configured to be disposed about the drill pipe.

15. The system of claim 11, wherein the annular down-hole component is a casing or a liner.

16. The system of claim 11, wherein the bearing mechanism of each of the plurality of blades comprises a plurality of bearing balls.

17. The system of claim 16, wherein the bearing balls are lubricated by drilling mud or production oil.

18. A method for limiting friction between a down-hole component and a casing or liner, comprising:

coupling a friction reducing stabilizer to the down-hole component;

positioning the down-hole component coupled with the friction reducing stabilizer within a wellbore having the casing or the liner; and

translating the down-hole component coupled with the friction reducing stabilizer such that at least one bearing mechanism of the friction reducing stabilizer engages with the casing or the liner during translation of the down-hole component and limits contact between the down-hole component and the casing or the liner.

19. The method of claim 18, comprising rotating bearing balls of the at least one bearing mechanism along a surface of the casing or the liner while translating the down-hole component coupled with the friction reducing stabilizer.

20. The method of claim 18, wherein positioning the down-hole component coupled with the friction reducing stabilizer within the wellbore having the casing or the liner comprises centering the down-hole component within the casing or the liner with equidistantly spaced blades of the friction reducing stabilizer, wherein the blades extend radially outward from the down-hole component.