A two-stage drill bit

THE PRESENT INVENTION relates generally to downhole cutting tools. More specifically, the present invention relates to a downhole drill bit which includes both a first cutting section and a second cutting section.

Conventional downhole drill bits are usually characterised by a body which defines, at its proximal end, a shank for attachment to a drill string and a distal end which terminates in a cutting face on which are disposed a plurality of cutting elements. Such conventional drill bits operate by boring a hole slightly larger than their maximum outside diameter. This borehole is achieved as a combination of the cutting action of the rotating bit and the weight on the bit created as a result of the mass of the drill string.

When a bore has been formed through a given formation, the rock immediately surrounding the borehole is, in many instances, quite frangible as a result of the decompression of this surrounding rock. Such a decompression of the surrounding rock has traditionally been viewed as a nuisance, necessitating casing of the borehole.

Some prior drill bits may rotate eccentrically, giving rise to so-called "whirl". This is undesirable as the drill bits can become damaged, and the borehole has undesirable properties.

US-A-5678644 relates to a bi-centre bit. The bit is a two-stage bit having a proximal end adapted for connection to a drill string. The distil end of the bit defines a pilot section, in which upsets are distributed around the entire circumference of the bit, and a reamer section, where upsets are provided which extend only over part of the circumference of the bit. The upsets of the reamer section are such that the upper part of each upset defines a gauge pad, but the gauge pads have, in total, a very small angular extend around the 360° periphery of the bit.

US-A-4515227 discloses a diamond rotating bit including a pilot bit. The bit is a two-stage bit having a body defining a proximal end for connection to a drill string, and a distil end which defines a pilot section of relatively small diameter and an intermediate reamer section of greater diameter. The pilot section is provided with cutter elements formed in an under face of the pilot section and is not provided with clearly identifiable upsets or cutter arms which are provided with a series of cutting elements.

In the reamer section there are three upsets or cutter arms which are provided with cutter elements, and these arms are provided with a main gauge (20) formed with a plurality of nature diamonds or kickers.

US-A-4887677 discloses a low pressure drill bit having a cutting member and a fluid course extending from the front of the cutting member, the fluid course including a progressively widening diffuser.

The present invention seeks to provide an improved two-stage drill bit.

According to this invention there is provided a two-stage bit having a body defining a proximal end adapted for connection to a drill string and a distal end, where said distal end defines a pilot section and an intermediate reamer section, where said pilot section includes a first cutter face defining a first diameter, and where said reamer section includes a second cutter face defining a second diameter, the second diameter being greater than the first diameter, and where the first and second cutter faces each include upsets or cutter arms distributed around the entire circumference of the bit, where each upset defines an upper portion and a lower portion, where said lower portion is provided with a series of cutting elements and said upper portion is provided with a surface adapted to extend to gauge into substantially non-cutting contact with the formation wherein the upper portion of each upset of cutter arm of the second cutter face (14) is a gauge pad inclined to the axis of the bit to be part helical, the proportion of the 360° circle of the reamer section of the bit provided with the gauge pad being at least 120°.

Conveniently the upper portion of each upset or cutter arm of the first cutter face is a gauge pad inclined to the axis of the bit to the part helical.

Preferably the proportion of the 360° circle of the pilot section of the bit provided with a gauge pad is at least 220°.

Advantageously the total proportion of the 360° circle of the bit provided with at least one gauge pad is between 240° and 360°.

Preferably each gauge pad is inclined at an angle within the range 25°-35° relative to a line parallel to the axis of the bit.

Conveniently each gauge pad is inclined at a angle of 30° relative to a line parallel to the axis of the bit.

Advantageously cutting elements (17, 32) are formed of polycrystalline diamond.

Preferably the upsets or cutter arms (19, 30) extends substantially parallel with the axis of the bit.

Conveniently the upsets or cutter arms (19) of the pilot are angularly off-set or mis-aligned relative to the upsets or cutter arms (30) of the reamer.

The preferred drill bit of this invention offers a number of advantages. One such advantage is enhanced stability of operation. The second advantage is increased rate of penetration as a result of the decompression of the rock effected by the first smaller cutter face. Thus the larger, second cutter face will act, in many cases, on decompressed, or frangible rock, which cuts easily.

In order that the invention may be more readily understood, an embodiment will now be described by way of example with reference to the accompanying drawings in which:

• FIGURE 1 is a bottom view of one embodiment of the drill bit of the invention, and
• FIGURE 2 is a side view of the embodiment illustrated in Figure 1.

A drill bit of the present invention may be seen by reference to Figures 1 and 2.

With reference to the figures, a drill bit 2 has a body 4 including an upper proximal end 6 and a lower distal end 8. The proximal end 6 defines a threaded shank for attachment to a drill string (not shown), while the distal end 8 defines a first (or pilot) cutting face 12, and a second (or reamer) cutting face 14. The first cutting face is a pilot cutting face and describes a selected outside diameter defined by cutters 17 positioned on one or more "upsets" or cutter arms 19 and associated gauge pads 23 provided to stabilise the bit 2 during operation. The gauge pads 23 are positioned above the cutters 17. The upsets or cutter arms 19 are distributed around the entire circumference of the bit body 4. Each upset or cutter arm 19 is in the form of a radially projected rib, each rib being spaced from the adjacent rib. The cutters 17 are mounted on the front or leading edge of the relevant rib. The gauge pads 23 form extensions of the ribs. While the ribs are substantially parallel with the axis of the bit, thus being vertical as shown in Figure 2, the gauge pads are inclined to the axis, and are thus almost part-helical.

Proximate to and separated from the first cutting face 12 is the second cutting face 14 which is a reamer and which also includes a corresponding series of upsets or cutter arms 30 on which are positioned a plurality of cutting elements 32. The cutting elements 32 describe an outside diameter which is larger than that of the first cutting face 12. The upsets or cutter arms 30 of this second cutting face 14 are also distributed around the entire circumference of the bit 2. Again the upsets 30 are vertical, or parallel with the axis of the bit. Above the upsets 30 are positioned a second set of gauge pads 37 to further stabilise the bit during operation in a borehole. The gauge pads form extensions of the ribs forming the upsets. The gauge pads are inclined to the axis of the bit and are thus almost helical. The diameter defined by the second set of gauge pads 37 is greater than the diameter defined by the first, lower, set of gauge pads 23.

Each of the first 12 and second 14 cutting faces is associated with one or more fluid nozzles 40 which are situated between upsets 19 and 30 as illustrated. Fluid is pumped down the drill string and out of said nozzles 40 to assist in cleaning cutting faces 12 and 14 as well as maintaining said faces in a preferred temperature range.

Thus each set of upsets 19,30 have lower portions provided with the cutting elements, and upper portions associated with the gauge pads which extend to gauge and which are adapted to be in non-cutting contact with the formation being drilled, thus stabilising the drill bit and preventing "whirl".

The two-stage drill bit of the present invention is constructed in the following manner. An evaluation is made of the formation of application for the tool. If the formation is comparatively hard, e.g. a 2.4 to 4.5 metres/hour (8- 15 ft/hr) penetration rate is predicted, a two-stage bit is selected which employs a large number of upsets with reduced spacing between upsets. On a 21.59 cm (8 ½" ) bit, this might entail incorporating six upsets on the first stage and nine upsets on the second stage. If a softer formation is encountered, e.g. a projected penetration rate of 24.4 to 36.6 metres/hour (80-120 ft/hr), fewer upsets will be employed to aid in cleaning the tool during operation. For a 16.5 (6 ½") bit, this might entail incorporating four upsets on the first stage and four upsets on the second stage. These upsets are oriented about the respective cutting faces 12 and 14 in a uniform manner.

The upsets themselves are configured to employ a relatively flattened upper region (extending generally parallel with the bit axis) with a rounded inwardly curving mid section and a substantially flattened bottom area which is transverse to the axis of the tool (see Figure 2). In such a fashion, the upsets define an arc which has slightly flattened end points. A line is drawn perpendicular to this arc at a point along its length to determine the placement of specifically shaped cutting elements 50. Where the line is normal to the axis "A" drawn through the tool (towards the top of the flattened upper region in the embodiment illustrated) a special shaped cutter 50, such as that described in US-A-5,803,196 is placed on each upset. Typically, one such shaped cutter will be placed on each upset of the first stage cutting face 12 and two shaped cutters 50 are positioned on each upset of the second stage cutting face 14. Conventional cutting elements 17 are then positioned about the remaining areas of the upsets in accordance with conventional force balancing procedures. Such conventional cutting elements 17 are formed as circular discs of cutting material, such as polycrystalline diamond, or tungsten carbide.

The relative juxtaposition of the first and second stages of the bit 2 are determined so as to allow a substantially complete angular off-set or misalignment (when considered in the direction of the axis of the tool) between the upsets comprising the first stage cutting face 12 and the upsets comprising the second stage cutting face. Such misalignment also serves to off-set nozzles 40 on both stages to further aid in cleaning the bit during operation in the borehole.

Gauge pads 23 and 37 are provided at the upper ends of the ribs forming the upsets 19 and 30 in a manner illustrated in Figures 1 and 2. Gauge pads 23 and 37 define a length "L" and a width "W" and an angulation "O" as measured relative to a line parallel to the axis A. The angulation "O" is typically 30°, but may be within the range of 25-35°.

Thus the side edges of the gauge pads are inclined to the axis A by an angle "O". When affixed on bit 2 the gauge pads define arc segments of a 360° circle when the bit is viewed axially from one end. The total proportion of the 360° circle that is provided with at least one gauge pad, either on the pilot section or on the reamer section, is preferably between 240° and 360°. The proportion that is provided with a gauge pad of the reamer section is preferably at least 120°, and the proportion that is provided with the gauge pad of the pilot is preferably at least 220°. Because of the partial overlap (when viewed axially) of the upsets and gauge pads, the total proportion provided with at least one gauge pad may be much less than the sum of the proportions of the pilot and reamer sections taken individually.

EXAMPLE 1

A two-stage drill bit of the invention having a pilot with six upsets, a 17.1 cm (6 ¾") outer diameter having six shaped cutters (such as the shaped cutter 50) and gauge pads having 240° of wall contact area, and having a reamer with a 21.6 cm (8 ½") cutter diameter with nine upsets having nine shaped cutters (such as the cutters 50) and gauge pads having 270° of wall contact area, having a total wall contact area, when viewed axially, of 330°, was inserted into a borehole formed in a sandstone formation at 4,105 metres (13,460 feet). The tool was operated for 36.5 hours with an average WOB of between 5,436 and 6,975 kg (12-15,000 lbs) at 230 r.p.m. 196.3 metres (561 feet) were drilled while the tool was in the hole with an average rate of penetration of 4.69 metres/hour (15.4 ft/hr). When pulled from the hole the cutters were in very good condition and only demonstrated minor wear.

The rate of penetration for the bit of the invention compared with an average rate of penetration of 3.17 metres/hour (10.4 ft/hr) for a conventional one-stage drill bit in the same formation.

EXAMPLE 2

A bit of the invention having a pilot with four upsets, a 12.7 cm (5 inch) outer diameter containing four shaped cutters (such as the cutter 50) and having gauge pads with 220° of wall contact area and having a reamer with four upsets, a 16.5 cm (6 ½") outer diameter and having eight shaped cutters (such as the cutter 50) and having gauge pads with 256° of wall contact area - the total wall contact area for the bit when viewed axially being 360° - was inserted into a borehole formed in sandy shale at a depth of 3,224 metres (10,572 ft). The tool was operated for 129 hours with an average WOB of between 906 and 1,359 kg (2,000-3,000 lbs) at a minimum of 80 rpm. 351.7 metres (1,186 ft) were drilled while the tool was in the hole with an average rate penetration of 4.45 metres/hour (14.6 ft/hr).

This compares with a rate of penetration for a conventional bit of 3.29 metres/hour (10.8 ft/hr) for the identical formation and operating parameters for 109.5 hours of drilling.

EXAMPLE 3

A bit of the invention having a pilot with five upsets, a 17.8 cm (7 inch) outer diameter containing five shaped cutters (such as the cutters 50) and having gauge pads with 240° of wall contact area, and having a reamer with ten upsets, a 25 centimetre (9 7/8 ^th inch) outer diameter and containing ten shaped cutters (such as the cutters 50) and having gauge pads with 120° of wall contact area - the total wall contact area for the bit when viewed axially being 240° - was inserted in a borehole found in a sand shale formation at a depth of 1,697 metres (5,566 ft). The tool was operated for 118.5 hours with an average WOB of between 6,795 and 8,154 kg (15,000-18,000 lbs) at a minimum of 65 r.p.m. 1,163 metres (3,814 ft) were drilled while the tool was in the hole with an average penetration rate of 9.30 metres/hour (30.5 ft/hr).

The rate of penetration of the bit of the invention compared with a rate of penetration of 6.45 metres/hour (21.16 ft/hr) for a comparative bit.

EXAMPLE 4

A bit of the invention having a pilot with four upsets, a 17.1 centimetre (6 ¾") outer diameter containing four shaped cutters (such as the cutters 50) and gauge pads with 196° of wall contact area, and having a reamer with eight upsets, a 21.6 centimetre (8 ½") outer diameter and containing eight shaped cutters (such as the cutters 50) and having gauge pads with 240° of outer wall contact area - the total wall contact area for the bit when viewed axially being 304° - was inserted in a borehole formed in a mixed sand/limestone shale formation at a depth of 4,317 metres (14,157 ft). The tool was operated for 25.6 hours with an average WOB of between 5,889-9,966 kg (13,000-22,000 lbs) at a minimum of 70 r.p.m. and a maximum of 140 r.p.m. 174 metres (571 ft) were drilled while the tool was in the hole with an average penetration rate of 6.8 metres/hour (22.3 ft/hr). This rate of penetration compares with the rate of penetration of 3.56 metres/hour (11.7 ft/hr) for a comparative bit.

The preferred bit 2 of the present invention is capable of enhanced rates of penetration when compared to conventional downhole drilling bits. This rate of penetration is a result of the increased penetration rate made possible as a result of smaller initial contact area. When the initial borehole has been created, the rock surrounding the borehole is stress-relieved. As a result of what is referred to as "the edge effect", the second, larger diameter drilling face 14 is able to easily widen the borehole to a desired borehole diameter.

The presence of gauge pads both in the small diameter pilot section of the bit and in the large diameter reamer section of the bit enhances stability.

Although particular detailed embodiments of the apparatus have been described herein, it should be understood that the invention is not restricted to the details of the preferred embodiment. Many changes in design, composition, configuration and dimensions are possible without departing from the scope of the present invention.

The features disclosed in the foregoing description, in the following Claims and/or in the accompanying drawings may, both separately and in any combination thereof, be material for realising the invention in diverse forms thereof.