A borehole is typically drilled using a drill bit which is attached to an end of a drill string. Rotary drilling is performed by rotating the drill bit. The drill bit may be rotated by rotating the drill string, by rotating the drill bit with a downhole drilling motor, or in some other manner.
A roller cone drill bit includes cones which rotate as the drill bit is rotated. Teeth which are positioned on the cones roll along the bottom of the borehole as the cones rotate. The teeth impact the bottom of the borehole as they roll and thereby crush and disintegrate rock in order to advance the borehole.
A fixed cutter drill bit typically includes no moving parts, but includes cutters which are attached to the body of the drill bit and which rotate with the drill bit as the drill bit is rotated. The cutters scrape the borehole as the drill bit rotates, thereby shearing rock in order to advance the borehole.
A cutter on a fixed cutter drill bit is typically comprised of a cutter element, such as an “abrasive” or “superabrasive” cutter element, which performs the shearing action. An abrasive cutter element may be comprised of tungsten carbide, another carbide material, ceramic and/or some other material. A superabrasive cutter element may be comprised of natural diamond, a synthetic diamond material such as polycrystalline diamond compact (PDC) or thermally stable diamond (TSP), or may be comprised of some other material such as cubic boron compact or diamond grit impregnated substances.
A cutter on a fixed cutter drill bit may be further comprised of a substrate to which the cutter element may be affixed. For example, a PDC or TSP cutter element may be comprised of a disc or cylinder shaped “diamond table” which may be affixed to a substrate such as tungsten carbide in order to provide the complete cutter. The diamond table typically comprises a substantially flat and circular cutting face which contacts the borehole in order to perform the shearing action.
A PDC or TSP cutter element may typically be affixed to a substrate by applying high temperature and high pressure to the cutter element and substrate in the presence of a catalyst so that the materials of the cutter element and the substrate bond with each other.
Fixed cutter drill bits are therefore typically comprised of a bit body and a plurality of cutters which are attached to the bit body. The bit body is typically constructed of steel or of a matrix containing an erosion resistant material such as tungsten carbide. The cutters are typically attached to the bit body by an adhesive or by brazing. The cutters may be received in cutter pockets in the bit body in order to facilitate the attachment of the cutters to the bit body.
The bit body and the cutters are configured to provide an overall design for the drill bit, having regard to considerations such as rate of penetration of the drill bit, drill bit stability, drill bit steerability, drill bit durability and hydraulic performance of the drill bit.
For example, the bit body typically includes a plurality of blades to which the cutters are attached and between which fluids and cuttings may pass. Because the cutters are typically attached to the blades of the drill bit, increasing the number of blades on a fixed cutter drill bit will generally increase the number of cutters which may be attached to the bit body, thereby increasing the “cutter count” and the “cutter density” on the drill bit.
Generally, the rate of penetration which can be achieved by a fixed cutter drill bit is inversely proportional to the number of blades and cutters which are included in the drill bit. In other words, the greater the number of blades and the greater the number of cutters, the lower the rate of penetration which may be expected from the drill bit.
Generally, the durability of the drill bit is proportional to the number of blades and cutters which are included in the drill bit. In other words, the greater the number of blades and the greater the number of cutters, the longer the drill bit may be expected to function without experiencing excessive wear.
Generally, the hydraulic performance of the drill bit is inversely proportional to the number of blades which are included in the drill bit. In other words, the greater the number of blades, the less area which is available between the blades for the passage of fluids and cuttings, and the more resistance which is provided to the passage of fluids and cuttings past the drill bit.
As a result, the design of a fixed cutter drill bit typically represents a compromise amongst the rate of penetration, stability, steerability, durability, and hydraulic performance which can be achieved with the drill bit. Various design strategies have been proposed for achieving an appropriate balance of these considerations.
U.S. Pat. No. 6,283,233 (Lamine et al) describes a drilling and/or coring tool which includes PDC cutting elements and/or secondary cutting elements and at least one associated cutting element which is situated behind at least one of the PDC or secondary cutting elements, wherein the associated cutting element is “hidden” behind the PDC or secondary cutting element and is unused unless or until the PDC or secondary cutting element with which it is associated wears down, is torn away, or is broken.
U.S. Pat. App. Pub. No. US 2006/0070771 A1 (McClain et al), U.S. Pat. App. Pub. No. US 2007/0079995 A1 (McClain et al), and U.S. Pat. App. Pub. No. US 2008/0149393 A1 (McClain et al) all describe a drill bit for drilling through a casing bit which is disposed at the end of a casing. The drill bit includes a first type of cutting element and a second type of cutting element. The first type of cutting element is comprised of a superabrasive material and the second type of cutting element may be comprised of either a superabrasive material or an abrasive material. The second type of cutting element is positioned behind the first type of cutting element but exhibits a “relatively greater exposure” than the first type of cutting element so as to engage the interior of the casing bit and drill through the casing bit. The second type of cutting element then wears quickly upon engagement with the subterranean formation, after which the first type of cutting element continues to drill through the subterranean formation.
U.S. Pat. App. Pub. No. US 2007/0199739 A1 (Schwefe et al) describes a cutter insert for a fixed cutter drill bit which may be used to secure a backup cutter in a recess behind a primary cutter on the drill bit. The backup cutter may be configured to be underexposed, overexposed or to have a substantially equal exposure relative to the primary cutter.
U.S. Pat. App. Pub. No. US 2008/0179106 A1 (Gavia et al) and U.S. Pat. App. Pub. No. US 2008/0179108 A1 (McClain et al) both describe a rotary drag bit which includes a primary cutter and at least two additional cutters which are positioned on a single blade of the drill bit and which are configured relative to each other. In particular, the additional cutters are configured to follow the primary cutter.
U.S. Pat. App. Pub. No. US 2008/0179107 A1 (Doster) describes a rotary drag bit which includes a plurality of blades and at least one split cutter set. The split cutter set includes a plurality of cutters, where at least two of the cutters are primary and/or kerfing cutters located on different blades of the bit, and where at least one of the cutters is a backup cutter. The cutters in the split cutter set all follow substantially a common cutting path upon rotation of the bit body about its central axis.
PCT International Publication No. WO 2008/095005 A1 (Chen et al) describes a rotary drill bit with cutting elements which are operable to control the depth of cut and rate of penetration during drilling of a wellbore. The cutting elements may be arranged in sets of a primary cutting element and an associated secondary cutting element, wherein the secondary cutting element is disposed in a leading position relative to the primary cutting element, and wherein the cutting face of the primary cutting element is exposed a greater distance from the bit face profile than the cutting face of the secondary cutting element. The sets of cutting elements may also be comprised of a “protector” which is operable to control the depth of the cut of the cutting elements.
There remains a need for fixed cutter drill bits which facilitate reasonable compromises with respect to the rate of penetration, stability, steerability, durability, and hydraulic performance which can be achieved with the drill bit.
USPTO Backgrounds
USPTO Backgrounds