Novel bits and cutting structures

Abstract

This invention provides an improved cutting element for downhole cutting tools including a support element and a beveled shearing element disposed on the support element and a drill bit including the cutting element; a cutting element including a support element and a shearing element disposed on the support element, wherein the shearing element includes TSP, a sharpened cutting edge, and at least one blended edge that forms part of an interface with the support element and a drill bit including the cutting element. Cutting inserts including an insert body and the shearing elements disclosed above are provided. Also provided are methods for forming the cutting elements and drill bit inserts and a method for drilling mixed earth formations using the improved downhole cutting tools of the present invention.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS [0001] This application is a continuation-in-part of U.S. patent application Ser. No. 11 / 154,284 filed on Jun. 16, 2005, which is a continuation-in-part of U.S. patent application Ser. No. 10 / 696,535, filed on Oct. 29, 2003, which claims priority of U.S. Provisional Application Ser. No. 60 / 446,967, filed on Feb. 12, 2003, and U.S. patent application Ser. No. 10 / 967,584, filed on Oct. 18, 2004, which is a continuation of U.S. patent application Ser. No. 10 / 738,629. All these parent applications are hereby incorporated by reference in their entirety.BACKGROUND OF INVENTION [0002] 1. Field of the Invention [0003] The present invention relates generally to downhole cutting tools used in the oil and gas industry. More specifically, the present invention relates to improved cutting structures. [0004] 2. Background Art [0005] Rotary drill bits with no independently moving elements on them are typically referred to as “drag” bits in the art. Drag bits...

AI Technical Summary

Benefits of technology

The present invention relates to cutting elements for downhole cutting tools, such as drill bits, that use thermally stable polycrystalline diamond for improved performance. The cutting elements can have a beveled shearing element or a sharpened cutting edge, and may also have a retaining element, a sharpened cutting edge, at least one blended edge, at least one tapered surface, or at least one perturbation on at least one surface. The invention also includes methods for forming the cutting elements and diamond-impregnated inserts. The technical effects of the invention include improved cutting performance, durability, and reduced wear and tear on the cutting tools.

Problems solved by technology

It has been found, however, that the life of both natural and synthetic diamond is shortened by the lifetime thermal exposure experienced in the furnace during the infiltration process.

The materials used to form PDC bit bodies, in order to be resistant to wear, are very hard and difficult to machine.

Although PDC cutting elements offer the benefit of being able to tailor a particular cutting element to a particular formation, they are also subject to thermal degradation at the high temperatures often encountered within the wellbore during the drilling process.

), the metallic binder expands much more rapidly than the diamond, resulting in fracturing of the diamond table and degradation of the PDC cutting element.

These sharp edges 402, 404 that contact the support have been shown to create stress risers within the support, leading to cracking of the support and delamination of the TSP cutting element.

However, many formations have mixed characteristics (i.e., the formation may include both hard and soft zones), which may reduce the rate of penetration of a bit (or, alternatively, reduces the life of a selected bit) because the selected bit is not preferred for certain zones.

In this type of formation, if a conventional diamond-impregnated bit is used, because the diamond table exposure of this type of this bit is small, the shale can fill the gap between the exposed diamonds and the surrounding matrix, reducing the cutting effectiveness of the bit (i.e., decreasing the rate of penetration (ROP)).

In contrast, if a PDC cutter is used, the PDC cutter will shear the shale, but the abrasive sand will cause rapid cutter failure (i.e., the ROP will be sufficient, but wear characteristics will be poor).

Moreover, increasing the diameter of the wellbore may be necessary if, for example, the formation being drilled is unstable such that the wellbore diameter decreases after being drilled by the drill bit.

Moreover, it is difficult to directionally drill a wellbore with a large diameter bit because, for example, larger diameter bits have an increased tendency to “torque-up” (or stick) in the wellbore.

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