Drilling stabilizer

Abstract

A stabilizer used to centralize drill pipe in the drilling of wells, such as oil and gas wells, having a replaceable member with a contoured outer surface and specifically designed flow paths.

Description

CROSS REFERENCES TO RELATED APPLICATIONS

None

FEDERALLY SPONSORED RESEARCH

Not Applicable

SEQUENCE LISTING OF PROGRAM

Not Applicable

BACKGROUND OF INVENTION

1. Field of Invention

This invention relates to an apparatus utilized to stabilize and centralize drill pipe and/or other tubular goods during the drilling of wells, such as oil and gas wells. More particularly, this invention pertains to a drilling stabilizer having a removable stabilizing member having a contoured outer surface and at least one flow path.

2. Description of Related Art

During the drilling of wells, such as oil and gas wells, a drill bit is typically located at the distal end of a length of drill pipe known as a “drill string,” and rotated to penetrate into the earth's crust. The drill string generally comprises a number of individual joints of drill pipe and/or down hole tools joined end-to-end to form a continuous length of pipe. In many cases, the outer diameter of the drill bit is considerably larger than the outer diameter of the drill string. As a result, when a section of well bore (which is formed by the drill bit) is drilled, the inside diameter of such well bore is typically larger than the outside diameter of the drill string.

In most instances, the upper portion of a well is typically drilled to define a relatively large inside diameter. After the well has been drilled to a predetermined depth, a length of pipe known as casing is introduced into the well and cemented into place. Drilling then continues at a diameter less than the inside diameter of the casing to a predetermined depth beyond the bottom of the casing. Thereafter, a second string of casing, somewhat smaller than the previous casing and approximately the diameter of the extended well bore, is introduced into the well and cemented in place. The process is repeated until a well is drilled and cased to a desired depth. A section of a well not having casing is commonly referred to as “open hole”. During drilling operations, a slurry known as drilling mud is pumped down the internal bore of the drill string and up the annular space between the outer surface of the drill string and the inner surface of the well bore (or casing, where appropriate). Among other purposes, the drilling mud lubricates the drill bit, offsets formation pressure encountered down hole, and transports the rock cuttings generated by the drilling operation to the surface. When drilling in open hole, the drill string may be forced against the wall of the well bore by the pressurized drilling mud with sufficient force that the drill string and down hole tools become stuck and cannot be withdrawn from the well.

Two existing technologies are commonly used to rotate a drill bit during drilling operations. One technology involves application of rotational torque to drill pipe at the surface. Such torque is transferred by the drill string to the drill bit. During drilling operations, drill strings are frequently loaded in torsion and compression, thereby making such drill strings subject to buckling. For this reason, it is frequently desirable that the drill string remain centralized within the larger diameter defined by the well bore.

Another technology involves use of a tubular-shaped “mud motor” attached to the lower end of the drill string immediately above the drill bit. Drilling mud or other fluid pumped through the drill string activates the mud motor, which in turn rotates the drill bit. Both drilling technologies require that an optimum axial load, commonly referred to as “weight on bit,” be applied to the down hole drill bit.

In almost all cases, the path of a given well is carefully mapped out in three dimensions. With deviated (i.e., directional) wells, the path of a well often proceeds vertically downward for some distance, and then turns horizontally in a predetermined direction. In order to accurately and efficiently control the direction of the drill bit, it is critical that axial and rotational drag be minimized during the drilling operation. In addition to other problems, such drag can prevent weight from being transferred to a down hole drill bit.

Drilling tools, commonly known as stabilizers, are frequently included in drill strings to centralize and stabilize such drill strings while drilling. Most existing stabilizers known in the art comprise a tubular member having a plurality of elongate blades extending radially outward from the outer surface of said tubular member. The outside surfaces of the said elongate blades contact the inner surface of the well bore, thereby centralizing and stabilizing the drill string. In many cases, such centralizing blades are welded directly onto the tubular body of the stabilizer.

Because the outside diameter of the blades (known as “ring gauge”) of the stabilizer must correspond to the inner diameter of the casing (or the open hole, where no casing is present,) and because the drilling process typically takes place though sections of casing and open hole having different inside diameters, numerous different sizes of stabilizers must be available on a drilling rig. However, space on drilling rigs is usually limited, especially on offshore drilling rigs. Therefore, maintaining a large inventory of stabilizers is both expensive and inefficient. Furthermore, because the blades of stabilizers of the existing art are integral to such stabilizers, such stabilizers must be completely removed from the drill string, and another stabilizer must be installed when a different ring gauge is required.

Elongate stabilizer blades of the existing art create significant resistance to rotation and to axial “sliding” of the drill string, thereby reducing the efficiency of the drilling process. Elongate stabilizer blades are also subject to becoming stuck against the wall of a well bore. Further, if a well bore is deviated, elongate stabilizer blades may present resistance to sliding past curves in the well bore path. Moreover, drill cuttings generated during the drilling operation tend to “ball up” between the blades of the stabilizer as they are carried up the annulus, thereby restricting the flow of mud up the annulus.

Prior art welded stabilizer blades also present various problems. The welding process can be expensive and requires heat treatment procedures which, if done improperly, may reduce the integrity of the tubular body member. Further, welded members must be inspected periodically using an approved method of non-destructive testing; such inspection can be expensive and must be performed by highly trained personnel.

SUMMARY OF THE INVENTION

In the preferred embodiment, the stabilizer of the present invention comprises a tubular body member. Said body member can be incorporated into a drill string; in the preferred embodiment, said body member has threaded connections for this purpose. A centralizing member having a central bore is received on the outer surface of said tubular member and secured in place. The tubular body member has threads on its outer surface terminating at a shoulder. The centralizing member has matching threads on the inner surface of its central bore, thereby permitting the centralizing member to be threaded onto the tubular body member and tightened against the shoulder of the tubular body member.

In this manner, the centralizing member is replaceable. As a result, when a different ring gauge is required, the centralizing member may be exchanged without removing tubular body member from the drill string. Safety and efficiency are improved by eliminating the need to remove the tubular body member from the drill string. Because only the centralizing members, and not the entire stabilizer assemblies, must be maintained in inventory, transportation costs, storage costs and space requirements are greatly reduced.

In the preferred embodiment, the centralizing member is machined from a single piece of stock, thereby eliminating the need for welding. The outer surface of the centralizing member has a generally convex shape. Such shape minimizes the contact surface between the stabilizer and the inner wall of the well bore or casing. As such, rotational and axial drag is reduced compared to prior art stabilizers. Further, because the stabilizer of the present invention passes through bends and “doglegs” in well bores, the risk of the centralizing member becoming stuck to the inner surface of a well bore is eliminated. Axial slots are formed in the outer surface of the centralizing member to allow for the passage of mud and drill cuttings. Such axial slots are designed to optimize the flow of mud, and balling up of chips is reduced or eliminated.

It is an object of the stabilizer of the present invention to provide a stabilizer which can be manufactured without the need for welding and heat treatment.

It is another object of the present invention to reduce the inventory requirements associated with stabilizers by having centralizing members of various ring gauge diameters which may be quickly and easily attached to a single tubular body member.

It is yet another object of the present invention to provide a stabilizer wherein the flow of mud and drill cuttings is optimized and the incidence of balling up of chips is reduced.

It is a yet another object of the present invention to provide a stabilizer wherein stabilizer bodies having different ring gauge sizes can be easily and efficiently changed without the need to remove a tubular member from a drill string.

It is yet another object of the present invention to improve drilling efficiency by reducing rotational and sliding friction between a stabilizer and the well bore.

It is a further object of the present invention to provide a stabilizer which easily negotiates curves and bends in the path of the well bore, and reduces the incidence of sticking in a well bore.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 depicts the stabilizer assembly of the present invention installed in a drill string.

FIG. 1A depicts an exploded view of FIG. 1.

FIG. 2 depicts a partial section view of the stabilizer assembly of the present invention.

DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT

Referring to the drawings, FIG. 1 depicts the stabilizer assembly 10 of the present invention installed in a conventional drill string. Stabilizer assembly 10 comprises tubular body member 12 and centralizing member 14. In FIG. 1, stabilizer assembly 10 is incorporated in a conventional drill string between upper drill pipe section 20 and lower drill pipe section 34.

Still referring to FIG. 1, tubular body member 12 has external shoulder 24 around as the outer surface of said member 12. In the preferred embodiment, said shoulder 24 is situated a sufficient distance from the top of body member 12 to accommodate drill pipe tongs, which are large wrench-like devices used to tighten and loosen threaded drill pipe connections on drilling rigs.

Referring to FIG. 1A, which depicts an exploded view of FIG. 1, body member 12 has a female “box” threaded connection 23 at its upper end and male “pin” threaded connection 33 at its lower end. Box connection 23 mates with the threaded pin connection of upper drill pipe section 20, and pin connection 33 mates with the threaded box connection of lower drill pipe section 34. In the preferred embodiment, such pin and box threaded connections 23 and 33 are standardized threaded connections commonly used in existing prior art oilfield tubular goods.

Still referring to FIG. 1A, body member 12 also has threads 27 on its outer surface. In the preferred embodiment, threads 27 are located immediately below shoulder 24. Also in the preferred embodiment, threads 27 are sized such that the major diameter of threads 27 is less than the diameter of shoulder 24 and the minor diameter of threads 27 is greater than the outside diameter of body member 12.

Centralizing member 14 has a central bore 36. Internal threads 29 are located within central bore 36 near the upper end of said central bore 36. Internal threads 29 of centralizing member 14 engage threads 27 of body member 12 when stabilizer assembly 10 is assembled as part of a conventional drill string. Centralizing member 14 also has top shoulder 26. Thus, when stabilizer assembly 10 is assembled and threads 27 and 29 are fully engaged, shoulder 26 of centralizing member 14 engages against shoulder 24 of body member 12.

In the preferred embodiment, centralizing member 14 is an ellipsoid having an enlarged convex outer surface 30 disposed about its outer periphery. In most applications, the outside diameter of convex outer surface 30 is ideally sized to match the desired ring gauge for that particular application. Further, in most (but not necessarily all) applications, the outside diameter of convex outer surface 30 is approximately equal to, or slightly less than, the inside diameter of a well bore in which stabilizer assembly 10 will be used. Flow channels 28 form flow paths or passageways which permit drilling mud, drill cuttings and/or other debris to flow up the annulus of a well bore.

Referring to FIG. 3, which is a partial cross-section cut away view of stabilizer assembly 10 of the present invention, centralizing member 14 of a desired ring gauge is slidably received on the outer surface of body member 12. Said centralizing member 14 is threaded onto body member 12 by engaging threads inner threads 29 of centralizing member 14 with outer threads 27 of body member 12. When said threads are engaged, shoulder 26 of centralizing member 14 engages against shoulder 24 of body member 12.

In operation, stabilizer assembly 10 is “made up” into a drill string. That is, the threaded connections of body member 12 engage the connections of the drill pipe 20, 34 above and below said body member 12. During operation, if it is desired to change the size of centralizing member 14 or swap said centralizing member for any reason, lower drill pipe 34 can be easily disengaged from lower connection 33 of body member 12. Thereafter, centralizing member 14 can be easily removed from body member 12 by disengaging threads 27 from threads 29. A replacement for centralizing member 14 can be quickly and easily installed on body member 12 as described above. Lower drill pipe 34 can then be connected to bottom connection 33 of body member 12, and the entire assembly can then be run back in a well bore.

Although the present invention is described herein primarily as a stand-alone apparatus that can be incorporated in a conventional drill string, it is to be observed that centralizing member 14 can also be beneficially utilized in connection with other down hole tools and/or devices—that is, said centralizing member 14 can be used without requiring tubular body member 12. By way of example, but not limitation, it is possible said centralizing member 14 could be slidably received on the outer housing of a mud motor or other down hole tool and secured in place using mating threads or other suitable connection means. In this manner, centralizing member 14 can provide the numerous benefits described herein, even though the mud motor housing (or other down hole tool) provides the mounting surface for said centralizing member instead of body member 12.

Whereas the invention is herein described with respect to a preferred embodiment, it should be realized that the above described and other various changes may be made without departing from the essential contributions to the art made by teachings hereof.

Claims

1. An apparatus introduced into a wellbore on a tubular having a passage therethrough, comprising:

a. a body having a flow path therethrough, said flow path in fluid communication with the passage of the tubular;

b. a stabilizing member having a convex outer surface and a bore extending through said stabilizing member, slidably received on said body; and

c. means for securing said stabilizing member on said body.

2. The apparatus of claim 1, wherein said stabilizing member is an ellipsoid.

3. The apparatus of claim 1, wherein said stabilizing member has at least one flow path along the outer surface of said stabilizing member.

4. The apparatus of claim 3, wherein said flow path comprises a channel disposed along the outer surface of said stabilizing member.

5. The apparatus of claim 1, wherein said means for securing said stabilizing member on said body comprises:

a. threads on the outer surface of said body; and

b. mating threads along the central bore of said centralizing member.

6. The apparatus of claim 5, further comprising a shoulder disposed on the outer surface of said body.

7. An drilling stabilizer apparatus comprising:

a. a body having a length, a first end having threads, a second end having threads, and a flow path through said body;

b. a ellipsoid stabilizing member having a bore extending therethrough, slidably received on said body;

c. means for securing said stabilizing member on said body.

8. The apparatus of claim 7, wherein said stabilizing member has at least one flow path along the outer surface of said stabilizing member.

9. The apparatus of claim 8, wherein said flow path comprises a channel disposed along the outer surface of said stabilizing member.

10. The apparatus of claim 7, wherein said means for securing said stabilizing member on said body comprises:

a. threads on the outer surface of said body; and

b. mating threads along the central bore of said centralizing member.

11. The apparatus of claim 10, further comprising a shoulder disposed on the outer surface of said body.