Title:
System and method for reducing wear in drill pipe sections
Kind Code:
A1


Abstract:
A system and method is provided for protecting the exterior surface of drill pipe bodies from abrasion and wear during drilling operations alternatively using a hardbanded pipe collar inserted into a drill pipe body; a hardbanded pipe sleeve slid over a section of the drill pipe body; or a hardbanded circumferential built up section of the drill pipe body.



Inventors:
Arnoldy, John S. (Houston, TX, US)
Application Number:
11/714653
Publication Date:
09/13/2007
Filing Date:
03/06/2007
Assignee:
ATT Technology Trust, Ltd. d/b/a Arnco Technology Trust, Ltd. (Houston, TX, US)
Primary Class:
Other Classes:
175/325.1
International Classes:
E21B17/10
View Patent Images:
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Primary Examiner:
ANDREWS, DAVID L
Attorney, Agent or Firm:
STRASBURGER & PRICE, LLP (Attention of: Richard D. Fladung Suite 2200 1401 McKinney, Houston, TX, 77010, US)
Claims:
I claim:

1. A drill pipe, comprising: a first tool joint and a second tool joint; a pipe body having an outer diameter; and a pipe collar having an outer diameter greater than said pipe body outer diameter and positioned between said first tool joint and said second tool joint.

2. The drill pipe of claim 1, wherein said collar is spin welded at its two ends to the pipe body.

3. The drill pipe of claim 1, wherein said collar is fabricated from forged steel.

4. The drill pipe of claim 1, wherein a portion of said collar is covered with a wear resistant alloy.

5. The drill pipe of claim 1, wherein said collar is substantially in the center of the pipe body.

6. A drill pipe comprising: a first tool joint and a second tool joint; a pipe body having an outer diameter; and a wear resistant alloy built up on said pipe body outer surface said first tool joint and said second tool joint so that the outer diameter of said built up alloy is greater than said pipe body outer diameter.

7. The drill pipe of claim 6, wherein said alloy is built up substantially in the center of the pipe body.

8. A drill pipe comprising: a first tool joint and a second tool joint; a pipe body having an outer diameter; and a pipe sleeve having an outer diameter greater than said pipe body outer diameter and positioned between said first tool joint and said second tool joint.

9. The drill pipe of claim 8, wherein said sleeve is fabricated from forged steel.

10. The drill pipe of claim 8, wherein a portion of the outer surface of said sleeve is covered with a wear resistant alloy.

11. The drill pipe of claim 8, wherein said sleeve is substantially in the center of the pipe body.

12. The drill pipe of claim 8, wherein said sleeve is fixed to the pipe body by welding.

13. A method of manufacturing a drill pipe comprising the steps of: providing a first section of a drill pipe body and a second section of a drill pipe body, each having an outer diameter; positioning a pipe collar having an outer diameter greater than the outer diameter of either of said drill pipe body sections and between said drill pipe body sections; and fixing the pipe collar to said drill pipe body sections.

14. The method of claim 13 wherein a portion of the outer surface of said collar is covered with a wear resistant alloy.

15. A method of manufacturing a drill pipe comprising the steps of: sliding a pipe sleeve over a drill pipe body; and fixing the pipe sleeve with the drill pipe body.

16. The method of claim 15 wherein a portion of the outer surface of said sleeve is covered with a wear resistant alloy.

17. The method of claim 15, further comprising the steps of: cooling the drill pipe body before the step of sliding; heating a pipe sleeve before the step of sliding; and sliding said heated sleeve over said cooled body.

18. A method for drilling a wellbore having a first wellbore axis and a second wellbore axis deviated from the first axis, comprising the steps of: positioning a drill pipe section having an increased diameter section between the ends of the drill pipe section with a drill string; deviating the drill pipe section from the first wellbore axis to the second wellbore axis; moving the drill pipe section in the wellbore so that the increased diameter section of the drill pipe section contacts the surface of the wellbore; and reducing wear to said drill pipe section during the step of moving.

19. The method of claim 18, wherein the step of reducing wear comprises applying a wear resistant alloy to a portion of the increased diameter section.

20. The method of claim 18, further comprising the step of: reducing friction forces between the surface of the wellbore and the increased diameter section.

Description:

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No. 60/780,118 filed Mar. 8, 2006, of the same title, which is incorporated herein by reference for all purposes in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

N/A

REFERENCE TO MICROFICHE APPENDIX

N/A

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates to the field of oilfield drilling equipment, and in particular to a system and method for the protection of the exterior surface of tubulars, such as drill pipe, from abrasion and wear during a drilling operation.

2. Description of the Related Art

Drilling operations for oil, gas, and other natural resources typically use a plurality of assembled drill sections that vary in length from several hundred feet to several miles. A drill string consists of a plurality of discrete drill pipe sections that are threaded together as the drill sting is advanced into the wellbore. Drill pipe section central bodies come in at least three ranges of lengths: Range 1 varies from 18 to 22 feet (5.5 to 6.7 m), Range 2 varies from 27 to 30 feet (8.2 to 9.1 m), and Range 3 varies from 38 to 45 feet (11.6 to 13.7 m). Range 2 is the most commonly used for a drill pipe section. Drill pipe section body outside diameters typically range from approximately 3 V2 inches to approximately 6¾ inches but other diameters have been used. The referenced pipe body lengths do not include the tool joints, which make the drill pipe sections approximately one foot (30 cm) longer.

Because most of the drill pipe body walls are not thick enough to cut threads into, tool joints are spin welded to each end of the pipe body. The tool joints are threaded so the drill pipe sections can be made up or connected together to form the drill string. Each drill pipe section has one male tool joint, referred to as the pin end, and one female tool joint, referred to as the box end. The outside diameter of the tool joint is typically greater than the outside diameter of the pipe body. Before the tool joints can be welded to the drill pipe body, upsets (an increase in outside diameter) are created at both ends of the pipe body using heat and force. The upset thickens the last 3 or 4 inches of the pipe body walls. Most drill pipe sections are fabricated from steel.

Drill collar sections are heavy walled pipe generally installed on and below the drill string. Generally, drill collar sections are heavier than a drill pipe body per linear distance, and are used to put weight on the drill bit for drilling. Drilling fluid or mud is pumped through the drill collar sections and the drill pipe sections. Drill collar sections or joints are either 30 feet (9.1 m) or 31 feet (9.4 m) long. Unlike drill pipe sections, the walls of drill collar sections are thick enough that it is not necessary to add tool joints. Instead, threads can be cut directly into each drill collar section. The drill collar sections can have box and pin ends.

A wellbore is normally drilled vertically with a drill bit positioned on the end of the drill string. There has been a long history of wear problems with downhole drilling equipment because approximately 95 percent of the earth's surface is composed of siliceous materials. Siliceous earth particles are very abrasive, with a hardness of about 800 Brinell hardness number (bhn), which causes considerable wear on prone surfaces. Drilling operations are usually periodically interrupted to place casing in the wellbore to stabilize the walls. As a result, the drill string commonly operates both in the open wellbore and in the casing.

In normal vertical drilling operations, the shoulders of the tool joints undergo or experience considerable wear when the drill string is rotated through underground formations. The shoulder of the tool joint is that part of the tool joint where there is a transition from the drill pipe body outside diameter to the tool joint outside diameter. The tool joints typically come in contact with the sides of the wellbore or casing because the tool joints have the largest outside diameter of the drill string. The wear is amplified when the drilling mud contains abrasive formation particles being flushed out of the borehole. The wear resulting from this amplified wear also usually occurs on the shouldered areas of the tool joints.

There have been numerous attempts to hardband tool joints. Hardfacing or hardbanding is the placement of a thickened band of hardened wear resistant alloy, that is harder than siliceous earth materials, over a surface subject to wear. Tool joints have typically been hardbanded at the bottom (near the shoulder) of the box end. Tungsten carbide has typically been used as the hardbanding alloy. For a description of the prior art of hardbanding tool joints, reference is made to U.S. Pat. Nos. 4,665,996; 4,256,518; and 3,067,593. The '996 patent proposes placement of the alloy on the “principal bearing surface of the drill pipe,” which is defined in the specification as “that part of the pipe having the largest diameter,” which on a standard drill pipe is “at the ends of the pipe joint.” For a description of the prior art of hardbanding alloys, such as tungsten carbide particles, used on tool joints, reference is made to U.S. Pat. Nos. 4,942,059; 4,431,902; 4,277,108; 3,989,554; 2,262,211; and 2,259,232.

U.S. Pat. No. 5,224,559 proposes a hardfacing alloy and a method for application to tool joints in which the alloy contains primary carbides that have a hardness of about 1700 bhn. Hardfacing materials that are harder than siliceous earth materials are brittle and usually crack during application. Although the alloy proposed in the '559 patent still cracks during application, it is satisfactory for use on tool joints by providing longer wear life, and reducing damage to casing. Prior to the '559 patent, no hardfacing material that cracked during application was used. U.S. Pat. No. 6,375,895 B1 proposes a hardfacing alloy suited for wear prone surfaces of tool joints, drill collars, and stabilizers that remains crack free while reducing casing wear.

More recently, directional drilling has evolved to provide deviation of drilling from a vertical axis towards a horizontal axis over large bending radiuses of curvature. Directional drilling makes it possible to reach subsurface areas laterally remote from the point where the bit enters the earth. The drill string can follow an angled or curved path that deviates anywhere from a few degrees off the vertical axis to a substantially horizontal axis. In directional drilling, Range 3 bodies are sometimes used in drill pipe sections, along with larger pipe body diameters that are still less than the tool joint diameter. As a result of this relatively larger diameter and longer drill pipe body, the tool joints do not always protect the drill pipe body from contact with the open wellbore and/or the casing. The consequence is exposure of the drill pipe body to wear mechanisms that can affect its integrity to a significant degree. Further, when individual drill pipe sections within the drill string are caused to bend during directional drilling, the middle portions of the drill pipe sections often come in contact with the sides of the wellbore or the casing. It has recently been found that in many types of directional drilling, particularly where there is a substantial change in the direction of the wellbore, the exterior body of the drill pipe sections experience significant wear. Also, frictional and torsional forces resisting the rotation of the drill string are increased, making drilling more difficult and costly.

Pub. No. U.S. 2006/0102354 proposes a thermal spraying process in combination with an iron based alloy to provide a protective wear resistant layer on downhole drilling equipment.

The above discussed U.S. Pat. Nos. 2,259,232; 2,262,211; 3,067,593; 3,989,554; 4,256,518; 4,277,108; 4,431,902; 4,665,996; 4,942,059; 5,224,559; and 6,375,895 B1; and Pub. No. U.S. 2006/0102354 are incorporated herein by reference for all purposes in their entirety. The '559 and '895 patents have been assigned to the assignee of the present invention.

A need exists to protect drill pipe bodies, particularly in directional drilling operations, where significant wear can occur.

BRIEF SUMMARY OF THE INVENTION

A system and method for protecting the exterior surface of drill pipe bodies is disclosed that alternatively uses a hardbanded pipe collar that is inserted and welded into a drill pipe body; a hardbanded pipe sleeve that is slid over a portion of the drill pipe body; or a hardbanded circumferential section of the drill pipe body. The present invention can be implemented in alternative methods, which include cutting the pipe body and inserting and fixing in place a hardbanded pipe collar; hardbanding a circumferential section of the exterior surface of the pipe body; sliding a hardbanded pipe sleeve over a section of the drill pipe body and fixing it in place; and/or sliding a heated hardbanded pipe sleeve over a cooled pipe body, and then allowing the temperatures of each component to equalize.

The system and method could be implemented with typical drill pipe sections using welding methods currently in use. The system and method would minimize wear to the drill pipe bodies, particularly when used in directional drilling. The system and method would minimize torsional and frictional forces that resist rotation of the drill pipe bodies, particularly when used in directional drilling. The system and method would preferably use known tool joint hardfacing alloys.

BRIEF DESCRIPTION OF THE DRAWINGS

A better understanding of the present invention can be obtained with the following detailed descriptions of the various disclosed embodiments in the drawings:

FIG. 1 is a cut away side view of a drill pipe section with the pipe body cut and a hardbanded pipe collar positioned for welding thereon.

FIG. 2 is a cut away side view of a drill pipe section that has been hardbanded circumferentially in a center of the drill pipe body.

FIG. 3 is a cut away side view of a drill pipe section with a hardbanded pipe sleeve that has been slid into place on the drill pipe body and welded into position.

FIG. 4 is a side view of a drill pipe section and a cut away side view of a hardbanded pipe sleeve.

FIG. 5 is an elevational view of the present invention used in directional drilling.

FIG. 6 is an enlarged elevational view illustrating the present invention used to reduce wear when in contact with the wellbore surface.

DETAILED DESCRIPTION OF THE INVENTION

Generally, the present invention involves a system and method for the protection of the exterior surface of a drill pipe body 2 from wear during drilling operations using a hardbanded pipe collar 12, hardbanded pipe sleeves 16 or 16A, or a section of the drill pipe body 2 that has been hardfaced 14. Turning to FIGS. 1-4, the present invention can be implemented by alternative methods, which include cutting the drill pipe body 2 to provide two end locations (8, 10) and fixing a hardbanded pipe collar 12 therebetween using welding (FIG. 1); hardbanding 14 a circumferential section of the exterior surface of the pipe body 2 (FIG. 2); sliding a hardbanded pipe sleeve 16 over a section of the drill pipe body 2 and then fixing it in place using welding (FIG. 3); and/or sliding a heated hardbanded pipe sleeve 16A over a cooled pipe body 2, and then allowing the temperatures of the sleeve 16A and the body 2 to equalize (FIG. 4). The pipe collar 12, pipe sleeves (16, 16A) and hardbanded 14 pipe body section are preferably positioned substantially in the center of the drill pipe body 2 where they can provide the most benefit in protection of the drill pipe body 2 during directional drilling or other operations. However, other placement locations anywhere between the tool joints (4, 6) are contemplated. The location in the center of the drill pipe body 2 also minimizes the frictional and torsional forces resisting the rotation of the drill string. A hardened wear resistant alloy 14 with a low coefficient of friction can be selected if desired.

FIG. 1 illustrates the drill pipe body 2 cut in two locations (8, 10) substantially near the center of its length, creating three sections: two pipe body sections (3, 5) that are attached to the tool joints (4, 6), and a center pipe body section (not shown). The center pipe section is removed. A forged steel pipe section 11, preferably having a length similar to the removed center pipe section, is attached between the two pipe body sections (3, 5) and their respective tool joints (4, 6). The pipe section 11 is preferably welded into place at locations (8, 10) using the same spin weld procedure used to attach the tool joints (4, 6) onto the ends of the drill pipe body 2. It is contemplated that other materials besides forged steel can be used for the pipe section 11. It is also contemplated that other attachment methods besides spin welding can be used to attach the pipe section 11 to the pipe body sections (3, 5). The forged steel pipe 11 is then welded or hardbanded with a hardened wear resistant alloy 14, such as described in the '559 and '895 patents. One such hardened wear resistant alloy is 300XT, available from ATT Technology, Ltd. d/b/a Arnco Technology Trust, Ltd. and/or Triten Alloy Products Group, a subsidiary of the Triten Corporation, both of Houston, Tex. Alternatively, the pipe section 11 can be hardbanded with a hardened wear resistant alloy 14 before the pipe section 11 is attached to the drill pipe body 2. It should be understood that a collar 12 means both the pipe section 11 with no hardened wear resistant alloy 14 welded to it, and also means the pipe section 11 with hardened wear resistant alloy 14 welded circumferentially on all or a portion of the exterior surface of the pipe section 11.

The collar 12 could be approximately three feet (0.91 m) in length, although other lengths are contemplated. Although the collar 12 is preferably the same length as the aforementioned center pipe section that was removed, it is also contemplated that the collar 12 may be a different length than the center pipe section that was removed. It is contemplated that the outside diameter and wall thickness of the pipe section 11 before hardbanding 14 will be substantially the same as pipe body sections (3, 5). However, other pipe section 11 thicknesses and outside diameters are contemplated, including thicknesses and outside diameters that are greater and/or less that the respective thicknesses and outside diameters of the pipe body sections (3, 5). It is contemplated that the aforementioned hardbanding alloy 14 may either completely or only partially circumferentially cover the outer surface of the collar 12. It is also contemplated that the hardbanding alloy 14 may be placed by welding on the shouldered transitional area between the pipe body sections (3, 5) and the collar 12.

FIG. 2 illustrates a hardened wear resistant alloy 14, such as described in the '559 and '895 patents, circumferentially welded on the exterior surface of a portion of the pipe body 2. The hardbanding 14 is substantially in the center of the drill pipe body 2. It is contemplated that the hardbanding 14 will be approximately three feet (0.91 m) in length, although other lengths are contemplated.

FIG. 3 illustrates a pipe section 15 hardbanded with a hardened wear resistant alloy 14, such as described in the '559 and '895 patents. The pipe section 15 can be made of forged steel, although other materials are contemplated. The inside diameter of the pipe section 15 is slightly greater than the outside diameter of the drill pipe body 2 so that the pipe section 15 can then be slid over the drill pipe body 2, and fixed in place substantially in the center of the drill pipe body 2 length. If the pin end 6 outside diameter is greater than the inside diameter of the pipe section 15, then the pipe section 15 can be slid into place before the increased diameter pin end 6 is fixed to the pipe body 2. Alternatively, the increased diameter pin end 6 can be removed before the pipe section 15 is positioned on the body 2. The pipe section 15 can be fixed in place by welding, although other methods are contemplated. Alternatively, it is also contemplated that the pipe section 15 can be hardbanded with the hardened wear resistant alloy 14 after the pipe section 15 is positioned or fixed in place on the pipe body 2. It should be understood that a sleeve 16 means both the pipe section 15 with no hardened wear resistant alloy 14 welded to it, and also means the pipe section 15 with hardened wear resistant alloy 14 welded circumferentially on all or a portion of the exterior surface of the pipe section 15. It is contemplated that the sleeve 16 will be approximately three feet (0.91 m) in length, although other lengths are contemplated. It is contemplated that the aforementioned hardbanding alloy 14 may either completely or only partially circumferentially cover the outer surface of the sleeve 16. It is also contemplated that the hardbanding alloy may be placed by welding on the shouldered transitional area between the pipe body 2 and the sleeve 16. It is also contemplated that the sleeve could be fabricated completely from a hardbanding alloy, i.e., without a separate pipe section.

FIG. 4 illustrates a pipe section 17 hardbanded with a hardened wear resistant alloy 14, such as described in the '559 and '895 patents. The pipe section 17 can be made of forged steel, although other materials are contemplated. The pipe section 17 can then be heated to expand its internal diameter. The drill pipe body 2 can be chilled to reduce its external diameter. The pipe section 17 can then be slid over the drill pipe body 2, and positioned at substantially the center of the drill pipe body 2 length. The temperatures of the pipe section 17 and the pipe body 2 can then be allowed to equalize. The friction or interference fit between the pipe section 17 and the pipe body 2 should secure the pipe section 17 in place to a predetermined force. Alternatively, the pipe section 17 can be further fixed in place with welding. Alternatively, the hardened wear resistant alloy 14 can be welded to the pipe section 17 after the pipe section 17 is positioned on the pipe body 2. Other methods are also contemplated. If the pin end 6 outside diameter is greater than the inside diameter of the pipe section 17, then the pipe section 17 can be slid into place before the pin end 6 is fixed to the pipe body 2. Alternatively, the increased diameter pin end 6 can be removed before the pipe section 17 is placed. It should be understood that a sleeve 16A means both the pipe section 17 with no hardened wear resistant alloy 14 welded to it, and also means the pipe section 17 with hardened wear resistant alloy 14 welded circumferentially on all or a portion of the exterior surface of the pipe section 17. It is also contemplated that the sleeve could be fabricated completely from a hardbanding alloy, i.e., without a separate pipe section.

It is contemplated that the sleeve 16A will be approximately three feet (0.91 m) in length, although other lengths are contemplated. It is contemplated that the aforementioned hardbanding alloy 14 may either completely or only partially circumferentially cover the outer surface of the sleeve 16A. It is also contemplated that the hardbanding alloy 14 may be placed by welding on the shouldered transitional area between the pipe body 2 and the sleeve 16A.

It should be understood that even though FIGS. 1-4 show exemplary drill pipe sections, the present invention can also be used with drill collars. It should also be understood that even though FIGS. 1-4 show only one pipe collar 12, pipe sleeve (16, 16A), or hardbanded 14 section per drill pipe body, it is contemplated that more than one could be used per drill pipe body 2. It is also contemplated that any one of the four could be used in combination with any other of the four. Further, it should be understood that the present invention can be used with new drill pipe or be retrofitted to used drill pipe.

Method of Use

Protecting drill pipe section bodies 2 and reducing frictional forces thereon during directional drilling uses the pipe collar 12, pipe sleeve (16, 16A), or section of drill pipe body 2 that has been hardbanded 14 of the present invention. A wellbore W created by directional drilling is shown in FIG. 5. In typical directional drilling, the drill bit on the end of the drill string DS initially enters the borehole B below the derrick D and proceeds downward along a vertical axis, represented by A1. At some point after entering the borehole B, the drill string DS deviates or changes direction from the vertical wellbore axis A1 to at least one other direction, represented by wellbore axis A2 in FIG. 5, which other axis A2 intersects with the vertical axis A1 at one point. It should be understood that the wellbore axis of the drill string DS can change many times while drilling a well, as is shown in FIG. 5. It should be understood that although FIG. 5 shows a land drilling rig D, the present invention is equally applicable for offshore drilling.

FIG. 6 shows one complete drill pipe section in the drill string DS. The pipe sleeve 16 is in contact with the wellbore W surface S during the directional drilling. While the drill string DS is rotating, the pipe sleeve 16 protects the drill pipe body 2 from wear, and reduces frictional forces on the drill string DS. Although a pipe sleeve 16 is shown in FIG. 6, it should be understood that a pipe collar 12, pipe sleeve 16A, or section of pipe body 2 that has been hardbanded 14 could be used either alternatively or in combination. It should also be understood that even thought FIGS. 5-6 show drilling in an open wellbore W, the present invention is equally applicable for rotation of the drill string DS inside a cased wellbore W.

The foregoing disclosure and description of the invention are illustrative and explanatory thereof, and various changes in the details of the illustrated apparatus and system, and the construction and the method of operation may be made without departing from the spirit of the invention.