An earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. With weight applied to the drill string, the rotating drill bit engages the earthen formation and proceeds to form a borehole along a predetermined path toward a target zone. The borehole formed in the drilling process will have a diameter generally equal to the diameter or "gage" of the drill bit.
A typical earth-boring bit includes one or more rotatable cutters that perform their cutting function due to the rolling movement of the cutters acting against the formation material. The cutters roll and slide upon the bottom of the borehole as the bit is rotated, the cutters thereby engaging and disintegrating the formation material in its path. The rotatable cutters may be described as generally conical in shape and are therefore sometimes referred to as rolling cones. Such bits typically include a bit body with a plurality of journal segment legs. The rolling cone cutters are mounted on bearing pin shafts that extend downwardly and inwardly from the journal segment legs. The borehole is formed as the gouging and scraping or crushing and chipping action of the rotary cones remove chips of formation material which are carried upward and out of the borehole by drilling fluid which is pumped downwardly through the drill pipe and out of the bit.
The earth-disintegrating action of the rolling cone cutters is enhanced by providing the cutters with a plurality of cutter elements. Cutter elements are generally two types: inserts formed of a very hard material, such as cemented tungsten carbide, that are press fit into undersized apertures or similarly secured in the cone surface; or teeth that are milled, cast or otherwise integrally formed from the material of the rolling cone. Bits having tungsten carbide inserts are typically referred to as "TCI" bits, while those having teeth formed from the cone material are known as "steel tooth bits."
The cutting surfaces of inserts are, in some instances, coated with a very hard "superabrasive" coating such as polycrystalline diamond (PCD) or cubic boron nitride (PCBN). Superabrasive materials are significantly harder than cemented tungsten carbide. As used herein, the term "superabrasive" means a material having a hardness of at least 2,700 Knoop (kg/mm.sup.2). Conventional PCD grades have a hardness range of about 5,000-8,000 Knoop, while PCBN grades have a hardness range of about 2,700-3,500 Knoop. By way of comparison, a typical cemented tungsten carbide grade used to form cutter elements has a hardness of about 1475 Knoop. Similarly, the teeth of steel tooth bits may be coated with a hard metal layer generally referred to as hardfacing. In each case, the cutter elements on the rotating cutters functionally breakup the formation to create new borehole by a combination of gouging and scraping or chipping and crushing.
The cost of drilling a borehole is proportional to the length of time it takes to drill to the desired depth and location. In oil and gas drilling, the time required to drill the well, in turn, is greatly affected by the number of times the drill bit must be changed in order to reach the targeted formation. This is the case because each time the bit is changed, the entire string of drill pipe, which may be miles long, must be retrieved from the borehole, section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string, which again must be constructed section by section. As is thus obvious, this process, known as a "trip" of the drill string, requires considerable time, effort and expense. Accordingly, it is always desirable to employ drill bits which will drill faster and longer and which are usable over a wider range of formation hardness.
The length of time that a drill bit may be employed before it must be changed depends upon its rate of penetration ("ROP"), as well as its durability or ability to maintain an acceptable ROP. The form and positioning of the cutter elements (both steel teeth and TCI inserts) upon the cone cutters greatly impact bit durability and ROP and thus are critical to the success of a particular bit design.
Bit durability is, in part, measured by a bit's ability to "hold gage", meaning its ability to maintain a full gage borehole diameter over the entire length of the borehole. To assist in maintaining the gage of a borehole, conventional rolling cone bits typically employ a heel row of hard metal inserts on the heel surface of the rolling cone cutters. The heel surface is a generally frustoconical surface and is configured and positioned so as to generally align with and ream the sidewall of the borehole as the bit rotates. The inserts in the heel surface contact the borehole wall with a sliding motion and thus generally may be described as scraping or reaming the borehole sidewall.
In addition to the heel row inserts, conventional bits typically include a primary "gage" row of cutter elements mounted adjacent to the heel surface but oriented and sized so as to cut the corner as well as the bottom of the borehole. Conventional bits can also contain a secondary gage trimming row or a nestled gage row with lesser extension to assist in trimming the bore hole wall. Conventional bits also include a number of additional rows of cutter elements that are located on the cones in rows disposed radially inward from the gage row. These cutter elements are sized and configured for cutting the bottom of the borehole and are typically described as primary "inner row" cutter elements. Together, the primary gage and primary inner row cutter elements of the bit form the "primary rows." Primary row cutter elements are the cutter elements that project the most outwardly from the body of the rolling cone for cutting the bore hole bottom.
A review of post run bit performance data from 1991 through 1995 indicated that most aggressive roller cone cutting structures from both milled tooth and tungsten carbide insert bits were sub-optimal at addressing very soft rock formations (i.e. less than 2000 psi unconfined rock compressive strength). Ultra-soft to soft formations typically consist of clays, claystones, very soft shales, occasionally limy marls, and dispersed or unconsolidated sands, typically exhibit plastic behavior. Very soft or weak clays/shales vary in their mechanical response from more competent (harder) shales, under the same compression loads, as applied in rotary rock bit drilling. Soft shales respond plastically, or simply deform under the applied load, as opposed to a brittle failure or rupture (crack) formed in more competent rocks to create the cutting or chip. In these very soft/plastic formation applications, we cannot rely on conventional brittle rock failure modes, where cracks propagate from the loaded tooth penetration crater to the adjacent tooth craters, to create a chip or cutting. For this reason, the cutting structure arrangement must mechanically gouge away a large percentage of the hole bottom in order to drill efficiently. In these types of formations, maximum mechanical efficiency is accomplished by maximizing the bottom hole coverage of the inserts contacting the hole bottom per revolution so as to maximize the gouging and scraping action.
USPTO Backgrounds
USPTO Backgrounds