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Publication numberUS20060196699 A1
Publication typeApplication
Application numberUS 11/073,051
Publication dateSep 7, 2006
Filing dateMar 4, 2005
Priority dateMar 4, 2005
Also published asWO2006096495A2, WO2006096495A3
Publication number073051, 11073051, US 2006/0196699 A1, US 2006/196699 A1, US 20060196699 A1, US 20060196699A1, US 2006196699 A1, US 2006196699A1, US-A1-20060196699, US-A1-2006196699, US2006/0196699A1, US2006/196699A1, US20060196699 A1, US20060196699A1, US2006196699 A1, US2006196699A1
InventorsRoy Estes, Marvin Gearhart, Johnny Castle
Original AssigneeRoy Estes, Marvin Gearhart, Johnny Castle
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Modular kerfing drill bit
US 20060196699 A1
Abstract
A modular kerfing rock drilling bit (10) is presented. Drill bit (10) comprises a bit body (12) having a connection (14) for attachment to a drill string member. A base portion (16) below the connection (14) has an outer portion (18) and a bottom (20). Slots (22) are formed in the base portion (16). A cutter assembly (100) comprises a leg (110) insertable into the slot (22) of the bit body (16). A journal (126) extends angularly downward and inward from the leg (110) for bearing support of a cone (180) rotatably mounted on the journal (126). A plurality of cutters (182) extend outward from the surface of the cone (180). A kerfing segment (140) extends downward from the leg (110) beyond the cone (180). A plurality of kerf cutters (142) are attached to the bottom of the kerfing segment (140).
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Claims(10)
1. A modular kerfing drill bit, comprising:
a bit body comprising;
a connection for attachment to a drill string member;
a base portion below the connection means, having an outside surface, and a bottom surface; and,
at least one slot formed in the base portion;
a cutter assembly comprising;
a leg insertable into the slot of the bit body;
a journal extending angularly downward and inward from the leg;
a cone rotatably mounted on the journal;
a plurality of cutters extending outward from the surface of the cone;
a kerfing segment extending downward from the leg; and,
a plurality of kerf cutters attached to the bottom of the kerfing segment.
2. The modular kerfing drill bit of claim 1, further comprising:
a kerfing assembly comprising;
a leg insertable into the slot of the bit body;
a kerfing segment extending downward from the leg; and,
a plurality of kerf cutters attached to the bottom of the kerfing segment.
3. The modular kerfing drill bit of claim 1, further comprising:
wherein each kerf cutter on a kerfing segment is located at a unique radial position.
4. The modular kerfing drill bit of claim 1, further comprising:
wherein a kerfing segment contains kerf cutters located at radial positions substantially equal to the radial positions of the kerf cutters on another kerfing segment of another leg.
5. The modular kerfing drill bit of claim 1, the leg further comprising:
a lead face and an opposite trailing face;
a back face and an opposite center face;
a transition face angularly disposed between the center face and the kerfing segment; and,
wherein the journal extends outward substantially perpendicular to the transition face.
6. The modular kerfing drill bit of claim 5, the leg further comprising:
a contiguous mesh of flow channels and flow slots extending from the leg center face, to between the kerf cutter, and to the leg back face.
7. The modular kerfing drill bit of claim 6, the contiguous mesh of flow channels and flow slots further comprising:
alternating vertically and horizontally oriented of flow channels and flow slots.
8. A cutter assembly comprising;
a leg insertable into the slot of the bit body;
a journal extending angularly downward and inward from the leg;
a cone rotatably mounted on the journal;
a plurality of cutters extending outward from the surface of the cone;
a kerfing segment extending downward from the leg; and, a plurality of cutters attached to the bottom of the kerfing segment.
9. A kerfing assembly comprising;
a leg insertable into the slot of the bit body;
a kerfing segment extending downward from the leg; and,
a plurality of cutters attached to the bottom of the kerfing segment.
10. A modular kerfing drill bit, comprising:
a bit body comprising;
a connection for attachment to a drill string member;
a base portion below the connection means, having an outside surface, and a bottom surface; and,
a plurality of slots formed in the base portion;
a cutter assembly comprising;
a leg insertable into the slot of the bit body;
a journal extending angularly downward and inward from the leg;
a cone rotatably mounted on the journal;
a plurality of cutters extending outward from the surface of the cone;
a kerfing segment extending downward from the leg; and,
a plurality of cutters attached to the bottom of the kerfing segment; and,
a kerfing assembly comprising;
a leg insertable into the slot of the bit body;
a kerfing segment extending downward from the leg; and,
a plurality of kerf cutters attached to the bottom of the kerfing segment.
Description
CROSS REFERENCE TO RELATED APPLICATION

None.

BACKGROUND OF THE INVENTION

1. Technical Field

The present invention relates generally to drilling bits used for drilling earth formations. More specifically, the present invention relates to a novel modular design for the improved construction of kerfing type rock bits, comprised of a combination of fixed cutters and roller cone cutters.

2. Description of Related Art

In the exploration of oil, gas, and geothermal energy, drilling operations are used to create boreholes, or wells, in the earth. These operations normally employ rotary and percussion drilling techniques. In rotary drilling, the borehole is created by rotating a tubular drill string with a drill bit secured to its lower end. As the drill bit deepens the hole, tubular segments are added to the top of the drill string. While drilling, a drilling fluid is continually pumped into the drilling string from surface pumping equipment. The drilling fluid is transported through the center of the hollow drill string and into the drill bit. The drilling fluid exits the drill bit at an increased velocity through one or more nozzles in the drill bit. The drilling fluid then returns to the surface by traveling up the annular space between the borehole and the outside of the drill string. The drilling fluid carries rock cuttings out of the borehole and also serves to cool and lubricate the drill bit.

One type of rotary rock drill is a drag bit. Early designs for drag bits included hard facing applied to steel cutting edges. Modern designs for drag bits have extremely hard cutting elements, such as natural or synthetic diamonds, mounted to a bit body. As the drag bit is rotated, the hard cutting elements scrape against the bottom and sides of the borehole to cut away rock.

Another type of rotary rock drill is the roller cone bit. These drill bits have rotatable cones mounted on bearings on the body of the drill bit, which rotate as the drill bit is rotated. Cutting elements, or teeth, protrude from the cones. The angles of the cones and bearing pins on which they are mounted are aligned so that the cones essentially roll on the bottom of the hole with controlled slippage. One type of roller cone cutter is an integral body of hardened steel with teeth formed on its periphery. Another type has a steel body with a plurality of tungsten carbide or similar inserts of high hardness that protrude from the surface of the body somewhat like teeth. As the roller cone cutters roll on the bottom of the hole being drilled, the teeth or carbide inserts apply a high compressive load to the rock and fracture it. The cutting action of roller cone cutters is typically by a combination of crushing, chipping and scraping. The cuttings from a roller cone cutter are typically a mixture of moderately large chips and fine particles.

When drilling rock with a roller cone cutter, the fracture effect of loading on the teeth of the rock bed is limited due to the rock matrix surrounding the borehole. Failure of rock is prevented in a large degree by the restraint to movement offered by the surrounding rock. Thus, it appears in usual drilling operations that small cracks are created in the rock, which return to the surface of the bottom of the wellbore creating chips instead of propagating deep into the rock itself. Thus, the bit tooth of the usual rock bit presses on the rock surface tending to create small cracks which propagate downward, but by virtue of the resistance to fracture offered by the surrounding rock matrix, a crack follows the path of least resistance and emerges at the surface on the bottom of the wellbore, thus creating the small chips.

U.S. Pat. No. 3,055,443 to Edwards disclosed a combination drag bit and roller cone cutter which removes the lateral restraint on a core to be drilled. The drag bit component cuts a single annular kerf forming a core which is received within a hollow body member and drilled by multicone rolling cutters arranged within the hollow body member. Windows are provided in the bit body adjacent to the multicone cutters to provide an egress for chips formed by the destruction of the core. This bit design causes rapid failure of the drag cutters, however, since virtually all the drilling fluid escapes through the windows and results in insufficient fluid flow to cool the drag bit component.

U.S. Pat. No. 4,892,159 to Holster describes a kerf-cutting bit wherein resistance of the rock to fracture is removed or reduced by employing a drill bit which destroys the rock rapidly and efficiently. The drill bit of Holster cuts multiple annular kerfs which result in more rapid drilling rates than those achieved by cutting a singular annular kerf.

U.S. Pat. No. 5,145,017 to Holster, et al, describes a combination kerf-cutting bit and roller cone bit in which an annular kerf ring is cut in advance of rolling cutter. An inner kerf cutting structure is located internal to the annular kerf ring. Rolling cone cutter are disposed between the kerfing segments. Chipway ports are defined to improve the egress of rock cuttings as they are generated at the bottom of the wellbore.

A primary disadvantage of the prior art designs is that they are extremely difficult and expensive to manufacture. The efficiency of a drill bit is determined by a well recognized “cost per foot” equation. The equation is based on the cost of operating the drilling rig, the “trip time” need to replace the drill bit at a given depth, the rate of penetration of the drill bit, the life of the drill bit, and the cost of the drill bit. Due to the extremely high cost of manufacturing the prior art designs, they have proven to be inefficient in a cost per foot analysis.

Another disadvantage of the prior art designs is the time required for manufacturing the drill bits. In the drilling industry today, there is significant pressure to keep inventory levels very low. This is combined with the reality that drill bit selection decisions are often made while drilling, in response to the drilling rate achieved and the condition of the dull bit removed from the hole. The prior art kerf-cutting hybrid bits having combined kerf cutting segments and rolling cone cutters take far too long to manufacture, and are far too expensive to keep in inventory. The result is that they have become an impractical choice for the oilfield drilling.

Another disadvantage of the prior art designs is that they are less durable than required. The prior art designs combining inner and outer kerfing segments wherein each cover the entire circumference of the well bore. The assembly of rotating cone cutting structures within the geometrical constraints of the fully circumferential kerfing segments provides numerous challenges. For example, prior art hybrid drilling bits utilize relatively smaller bearing and seal systems which are less reliable when drilling larger diameter holes. Similarly, the smaller cones present a design constraint which require correspondingly smaller cutting elements on the cones. As with the sealed bearing system, these elements are less durable, and drill slower than the larger cutting elements conventionally used when drilling wells of the same diameter.

Another disadvantage of the prior art designs is that they lack cutting removal ability, limiting the life of cutting elements and rates of penetration at which the drill bits can operate, and subjecting the bits to balling and premature failure.

SUMMARY OF THE INVENTION

The present invention is a significant improvement over that described in the above enumerated prior art patents. The improvements of the present invention relate to both the location and relationship between cutting elements, as well as to the design, construction and manufacture of the drill bit. A principal advantage of the present invention is that it provides a drill bit capable of drilling more efficiently than prior art designs

Another advantage of the present invention is that it provides a hybrid bit design that is modular, permitting reduced inventories of component parts for assembly of multiple configurations of drill bits. Another advantage of the present invention is that it provides a hybrid bit design that can be assembled quickly, making the finished product deliverable faster than prior art designs. Another advantage of the present invention is that it provides a hybrid drill bit design that incorporates larger component cutting elements and larger bearing and seal systems which is more durable and drills faster.

Another advantage of the present invention is that it provides a hybrid drill bit design having very large flow relief area between the kerfing segments, allowing the bit to perform at very high rates of penetration without cutting build-up and balling of the bit. Other advantages of the present invention will become apparent from the following descriptions, taken in connection with the accompanying drawings, wherein, by way of illustration and example, an embodiment of the present invention is disclosed.

In carrying out principles of the present invention, in accordance with a preferred embodiment thereof, a modular kerfing drill bit is disclosed, having a bit body with a threaded connection for attachment to a drill string member at it's upper end. A base portion is provided below the connection, having an outside surface, and a bottom surface. At one or more slots are formed in the base portion. A cutter assembly is provided having a leg which is insertable into the slot of the bit body. A journal extends downward and inward from a transition portion of the leg, towards the center of the bit body. A cone is rotatably mounted on the journal. A plurality of cutters are located extending outward from the surface of the cone. A kerfing segment extends downward from the leg, beyond the journal. A plurality of cutters are positioned in the bottom of the kerfing segment.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is an isometric view of a preferred embodiment of the present invention of a modular kerfing rock drilling bit in which three cutter assemblies are employed.

FIG. 2 is an isometric view of a preferred embodiment of the bit body of the present invention, with the cutter assemblies unattached.

FIG. 3 is an isometric view of the cutter assembly disclosed in FIG. 1, viewed in the direction of the center and lead faces of the leg.

FIG. 4 is an isometric view of a cutter assembly of the preferred embodiment illustrated in FIG. 3, viewed in the direction of the back and lead faces of the leg.

FIG. 5 is a side view of the cutter assembly illustrated in FIGS. 3 and 4, viewed in the direction of the center face of the leg.

FIG. 6 is a side view of the cutter assembly illustrated FIG. 5, rotated 90° and viewed in the direction of the lead face of the leg.

FIG. 7 is a side-sectional view of the cutter assembly illustrated in FIG. 6.

FIG. 8 is a side view of the preferred embodiment of the present invention illustrated in FIG. 1, viewed in the direction of the back face of a leg.

FIG. 9 is a side view of the preferred embodiment of the present invention illustrated in FIG. 8, with the drill bit rotated 60°, and viewed in the direction between cutter assemblies.

FIG. 10 is a bottom view of the preferred embodiment illustrated in FIGS. 1-3.

FIG. 11 is a top view of the preferred embodiment illustrated in FIGS. 1-4, showing the fluid channels internal to the bit body.

FIG. 12 is an isometric view of an alternative embodiment of the present invention of a modular kerfing rock drilling bit, in which a single cutter assembly is employed in combination with two kerfing assemblies.

FIG. 13 is an isometric view of a kerfing assembly of the alternative embodiment disclosed in FIG. 12, shown disengaged from the body.

FIG. 14 is a side view of the alternative embodiment disclosed in FIG. 12, and viewed in the direction between kerfing assemblies.

FIG. 15 is a bottom view of the alternative embodiment of the present invention disclosed in FIG. 12.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 1 is an isometric view of a preferred embodiment of the present invention for a Modular Kerfing Drill Bit 10. In the embodiment shown, drill bit 10 has a body 12. Body 12 has a connection 14 for attachment to a drill string member (not shown). Body 12 has a base 16 below connection 14 and contiguous thereto. Cutter assemblies 100 are shown attached to body 12.

FIG. 2 is an isometric view of a preferred embodiment of bit body 12 of the present invention, shown with cutter assemblies 100 unattached. In this view, it is seen that base 16 has a generally cylindrical outer portion 18 and a bottom 20. Slots 22 are formed in base 16, and intersect both outer portion 18 and bottom 20. Slots 22 are formed for secure location of cutter assemblies 100. Also in body 12, ports 24 are provided, and interconnect to internal passage 26 (dashed line).

FIG. 3 is an isometric view of a preferred embodiment of a cutter assembly 100. Cutter assembly 100 has a leg 110. Leg 110 has a lead face 112 and an opposite trailing face 114 (best seen in FIG. 8). Leg 110 has a center face 116 and an opposite back face 118 (best seen in FIG. 4). Leg 110 has a bottom face 120 and a transition face 122. A journal 126 (not visible in this view) extends downward, substantially perpendicular to transition face 122.

FIG. 4 is another isometric view of cutter assembly 100 illustrated in FIG. 3, viewed in the direction of back face 118 and lead face 112 of leg 110. In this view, it is seen that a reservoir cap 128 is located on back face 118 of leg 110. In the preferred embodiment, reservoir cap 128 encloses an internal lubrication system 130 (best seen in FIG. 7). Also in the preferred embodiment illustrated, a plurality of gage buttons 132 are located on back face 118. Also in the preferred embodiment illustrated, a stabilizer pad 134 is provided below back face 118 on leg 110.

Still referring to FIG. 4, an external junk channel 136 is disposed circumferentially above stabilizer 134. Cutter assembly 100 has a kerfing segment 140 extending downward from junk channel 136. In a less preferred embodiment, kerfing segment 140 extends downward from stabilizer 134.

Kerfing segment 140 supports a plurality of kerf cutters 142 mounted in cutter supports 144. Referring to FIG. 4, in the preferred embodiment, annular junk slots 146 are vertically disposed between cutter supports 144, and merge with junk channel 136.

In a specifically preferred embodiment, kerf cutters 142 are synthetic diamond cutting elements. Specific examples of these types of cutting elements include polycrystalline diamond compacts (PDC's) and thermally stable diamond compacts (TSP's). There are numerous material and geometric variations of these products that are well known and readily available in the drilling industry. In a less preferred embodiment, kerf cutters 142 are natural diamonds.

FIG. 5 is a side view of cutter assembly 100 illustrated also in FIG. 3 and 4. In FIG. 5, cutter assembly 100 is viewed from the center of drill bit 10. Referring to FIG. 5, (see also FIG. 3), an internal flow channel 150 is disposed circumferentially above transition face 122. Kerfing segment 140 extends downward from flow channel 150. Internal flow slots 152 are vertically disposed between cutter supports 144, and merge with flow channel 150.

As can be seen in FIG. 5, cutter supports 144 support kerf cutters 142 in an angular deployment. This configuration provides a flow passage 154 between kerf cutters 142, and connects internal flow slots 152 to external junk slots 146.

FIG. 6 is a side view of cutter assembly 100 illustrated FIG. 5, rotated 90° and viewed in the direction of lead face 112 of leg 110. FIG. 7 is a side-sectional view of cutter assembly 100 illustrated in FIG. 6. As seen in FIG. 6 and FIG. 7, a cone 180 is rotatably mounted on journal 126. Cone 180 has a plurality of teeth 182 attached to it. In the preferred embodiment, teeth 182 are interference fit within holes predrilled in cone 180. Also in the preferred embodiment, teeth 182 are made of a material substantially harder than the formation to be drilled, such as sintered tungsten carbide.

As can also be inferred from FIG. 7, internal lubrication system 130 is contiguous to the external surface of journal 126 and the internal surface of cone 180, so as to provide lubrication between journal 126 and cone 180.

FIG. 8 is a side view of drill bit 10, viewed in the direction of back face 118 of leg 110. From this view, it can be seen that a large clearance is provided between trailing face 114 of one cutter assembly 100 and lead face 112 of the adjacent cutter assembly 100. FIG. 9 is a side view of the preferred embodiment of drill bit 10, as illustrated in FIG. 8, with drill bit 10 rotated 60°, and viewed in a direction between cutter assemblies 100. FIG. 10 is a bottom view of the preferred embodiment illustrated in FIGS. 1-3. In the preferred embodiment, interchangeable nozzles 28 are removably connectable to ports 24.

FIG. 11 is a top view of the preferred embodiment of drill bit 10. In this view, it is seen that cones 180 have dissimilar cutting structures such that combined, they can rotate without interfering, and can best cover the bottom of the wellbore. This is noted by the designation of each cone 180 with a different alphanumeric suffix a through c.

Similarly, in the preferred embodiment, each kerf cutter 142 on a given cutter assembly 100 is located at a different radial distance to the center of drill bit 10. This is noted by the designation of each kerf cutter 142 with a different alphanumeric suffix a through c, with a designating the innermost kerf cutter 142 and c designating the outermost kerf cutter 142. In this manner, drill bit 10 can be specifically designed so that the combined physical forces acting on the combined cutters 142 and 182 on any given cutter assembly 100 are collectively, substantially equal. This provides a drill bit 10 that operates more efficiently.

FIG. 12 is an isometric view of an alternative embodiment of the present invention for a modular kerfing rock drilling bit 11, in which drill bit 11 incorporates a single cutter assembly 100 having a rotating cone 180 with teeth 182. In this embodiment shown, drill bit 10 has a body 12. Body 12 has a connection 14 for attachment to a drill string member (not shown). Body 12 has a base 16 below connection 14 and contiguous thereto. Unique to this embodiment, a single cutter assembly 100 is shown attached to body 12. A pair of kerfing assemblies 200 are attached to bit body 12 in place of cutter assemblies 100.

FIG. 13 is an isometric view of kerfing assembly 200 disclosed in FIG. 12, shown detached from bit body 12 of drill bit 11. Kerfing assembly 200 has a leg 210. Leg 210 has a lead face 212 and an opposite trailing face 214 (best seen in FIG. 14). Leg 210 has a center face 216 and an opposite back face 218 (best seen in FIG. 14). Leg 210 has a bottom face 220 and a transition face 222. Unlike cutter assemblies 100, there is no journal 126 extending from transition face 222, and no cone 182 having teeth 184 mounted thereon.

Referring back to FIG. 2, bit body 12 of previously disclosed can readily serve as bit body 12 of the alternative embodiment, shown with cutter assembly 100 and kerfing assemblies 200 unattached. In this view, it is seen that base 16 has a generally cylindrical outer portion 18 and a bottom 20. Slots 22 are formed in base 16, and intersect both outer portion 18 and bottom 20. Slots 22 are formed for secure locations of cutter assembly 100 and kerfing assemblies 200. Also, in body 12, ports 24 are provided, and interconnect to internal passage 26 (dashed line).

FIG. 14 is a side view of the alternative embodiment of drill bit 11 disclosed in FIG. 12, viewed in the direction between kerfing assemblies 200, and having cutter assembly 100 and kerfing assemblies 200 attached in slots 22 of bit body 12. From this view, it can be seen that a large clearance is provided between trailing face 214 of one kerfing assembly 200 and lead face 212 of the adjacent kerfing assembly 200.

FIG. 15 is a bottom view of the embodiment of drill bit 10 disclosed in FIG. 12. In this view, it can be seen that cone 180 has teeth 182, and is the only rolling cutting element on drill bit 11.

The foregoing detailed description is to be clearly understood as being given by way of illustration and example, the spirit and scope of the present invention being limited solely by the appended claims.

OPERATION OF THE INVENTION

As seen in FIG. 1, the preferred embodiment of Modular Kerfing Drill Bit 10 of the present invention is unique and vastly different from the prior art kerfing bit designs. Prior art designs are consistent in having fully circumference kerfing rows with cutters uniformly distributed thereon. The present design departs radically from this concept.

As seen in FIG. 2, body 12 is comprised of base 16 extending from bottom 20. Bottom 20 is preferable a threaded connection such as an API connection as is well known in the drilling industry. Bottom 20 is thus suitable for secure connection to a drill collar, bit sub, or other drilling tool. The inside of body 12 provides internal passage 26 which is connected to ports 24 located on bottom surface 20 of body 12.

Internal passage 26 and ports 24 provide a passageway for drilling fluid. Since drilling fluid is most advantageously provided at high velocity, in the preferred embodiment, ports 24 are receivable of interchangeable nozzles 28 made of a hard metal, such as tungsten carbide, or titanium carbide (see FIG. 10 and FIG. 15). The hardness of the hard metal nozzles provides wear resistance to the abrasive forces associated with the high-velocity flow of the drilling fluid through the constricted diameter of the nozzles. In this embodiment, nozzles 28 can be interchangeably selected based on known operating parameters to optimize the hydraulic benefit of the drilling fluid on the performance of drill bit 10.

Body 12 has at least one slot 22 formed on base 16. Slots 22 intersect outer portion 18 and bottom 20. Slots 22 provide a secure location for cutter assemblies 100, and/or kerfing assemblies 200.

Cutter assembly 100 is shown in FIGS. 3-6, unattached to body 12. Cutter assembly 100 has a leg 110. Leg 110 has a lead face 112 (FIG. 3) and an opposite trailing face 114 (best seen in FIG. 8). The reference to lead and trailing indicate the normal direction of rotation of the drill string and drill bit 10. Leg 110 also has a center face 116 (FIG. 5) and an opposite back face 118 (FIG. 4). Leg 110 also has a bottom face 120 and a transition face 122. Lead face 112, trailing face 114, and bottom face 120 are dimensionally and geometrically configured to fit in close tolerance within slots 22 of body 12. This is seen in FIG. 1.

As seen in FIG. 1, and also in FIGS. 8-10, legs 10 of cutter assemblies 100 extend radially outwards from outer portion 18 of base 16. As is clearly visible in FIG. 10, this provides a very large annular opening for the vertical passage of cutting laden drilling fluid between cutter assemblies 100, body 12 and the side wall of the well bore. The size of this passage far exceeds the passage found in conventional kerfing bit designs, and thus resolves a principal disadvantage of the prior designs which rely on full circumference bit bodies and kerf cutter configurations.

In the paragraph above, and herein below, the terms “vertical” and “horizontal” used in reference to the direction of drilling fluid flow are made in reference to the central axis of a vertically drilled well. This reference is made by way of example only, for the purpose of understanding the operation of the invention. The reference is not intended as a limitation. The present invention is capable of directional drilling operations in any direction, including horizontally.

The preferred embodiment illustrated discloses drill bit 10 having three slots 22 in body 12, for accommodation of three cutter assemblies 100. In another preferred embodiment not shown, drill bit 10 has two slots 22 in body 12 for accommodation of two cutter assemblies 100. In another preferred embodiment not shown, drill bit 10 has four slots 22 in body 12 for accommodation of a combination of cutter assemblies 100 and kerfing assemblies 200. In still another preferred embodiment, drill bit 10 has one slot 22 in body 12 for accommodation of one cutter assembly 100.

Each cutter assembly 100 has a cylindrical journal 126 extending from transition face 122. In the preferred embodiment, journal 126 extends downward, substantially perpendicular to transition face 122. A cone 180 is mounted to each journal 126. Cone 180 may be mounted to journal 126 in the manner known for mounting cones to journal in conventional rotary drilling bits, using legs 110 in exchange for rotary drill bit sections, which normally include the base 16 and connection 14 portions as well. Cones 180 have teeth 182 located about the outer surface of cone 180.

As seen in FIG. 7, a lubrication system 130 may be located in leg 110 to provide a lubricant between rotatable cone 180 and journal 126. Lubrication system 130 may include a lubricant reservoir and pressure compensation means beneath a reservoir cap 128. In the preferred embodiment, reservoir cap 128 is located on back face 118 of leg 110. As drill bit 10 experiences increases in pressure at deeper well depths, or in response to increases in drilling fluid density, the pressure compensation means adjusts the pressure of the lubricant between rotatable cone 180 and journal 126, to prevent drilling fluid from entering between rotatable cone 180 and journal 126, and causing failure of the bearing relationship between them.

In the preferred embodiment illustrated, teeth 182 are tungsten carbide inserts, press fit into cone 180. Teeth 182 may be made of other materials and may be otherwise attached to cones 180. As an example, teeth 182 may be machined from the cone material. Teeth 182 may include a hard material deposited on them to increase their wear resistance. In the preferred embodiment, a plurality of gage buttons 132 are located on back face 118 to protect leg cutter assembly 100 from abrasive wear resulting from contact with side of the well bore. This location of gage buttons 132 provides particular protection to reservoir cap 128.

Beneath gage buttons 132, a stabilizer section 134 extends outward from back face 118 of leg 110. Stabilizer 134 acts to stabilize and center drill bit 10 in the well bore during rotary drilling operations, increasing drilling rate and drill bit life by assisting drill bit 10 to drill a true and centered well bore. Since the present invention lacks full circumference kerfing sections, stabilizer 134 can extend the full width of leg 110, and still provide vertical passage for cutting laden drilling fluid. This capability substantially simplifies the manufacturing process of drill bit 10.

As seen in FIG. 4, external junk channel 136 is disposed circumferentially above stabilizer 134 providing horizontal passage for cutting laden drilling fluid, interlaced with the vertical passage provided between cutter assemblies 100.

Referring to FIG. 4, kerfing segment 140 extends downward from junk channel 136. Kerfing segment 140 supports a plurality of kerf cutters 142 mounted in cutter supports 144. Annular junk slots 146 are vertically disposed between cutter supports 144. Annular junk slots 146 provide vertical passage for cutting laden drilling fluid between individual kerf cutters 142, and are interlaced with horizontally disposed junk channel 136, which is in turn interlaced with the vertical passage provided between cutter assemblies 100.

Kerf cutters 142 are primarily shear cutting elements that also impart compressive forces to fail the formation being drilled. As a result of this process, high flow rates of drilling fluid at the kerf cutter 142 and formation interface are preferable to lower flow rates. This helps removes the cuttings and lower the temperature at the interface of kerf cutter 142 and the formation. It is detrimental to performance when the cuttings generated by kerf cutters 142 and teeth 182 are limited in their ability to escape from the center of drill bit 10 (or 11) to the annular section of the well bore surrounding drill bit 10 (or 11).

Teeth 182 on cones 180 are primarily compressive cutting elements, that also impart shear forces to fail the formation being drilled. As a result of this process, high jet impact forces imparted to the hole face being drilled are preferable to lower impact forces. The higher impact forces help dislodge cuttings and prevents re-drilling the chips that remain on the formation face.

Notwithstanding the optimization requirements of kerf cutters 142 and teeth 182 of cones 180, it is further noted that drilling systems are limited in the amount pressure their equipment can tolerate. Selecting smaller nozzles to increase jet impact forces beneficial to teeth 182 increases the drilling system operating pressure. Increasing pump speed to achieve flow rates beneficial to kerf cutters 142 likewise increases the drilling system operating pressure.

Thus, it is advantageous to be able to interchangeably select nozzles 28, and to have a contiguous connections between relief's on bit 10 (or 11) sufficient to readily permit removal of the cuttings generated by bit 10 (or 11). The present invention accomplishes this. First, there are interchangeable nozzles 28 connectable to ports 24. Second, there is a contiguous mesh of vertically and horizontally oriented flow channels and flow slots that being near nozzles 28 on the internal portions of legs 110 and continue to the outer portions of legs 110. Third, the contiguous mesh is interconnected to very large annular spaces provided between cutter assemblies 100 (and kerfing assemblies 200) in the modular, non-circumferential design of drill bit 10 (and 11).

FIG. 5 is a side view of cutter assembly 100 illustrated also in FIG. 3 and 4. In FIG. 5, cutter assembly 100 is viewed from the center of drill bit 10. Referring to FIG. 5, (see also FIG. 3), an internal flow channel 150 is disposed circumferentially above transition face 122, in the immediate proximity of where cuttings will be generated by teeth 182 on cone 180. Kerfing segment 140 extends downward from flow channel 150. On the inside of kerfing segment 140, internal flow slots 152 are vertically disposed between cutter supports 144, and merge with flow channel 150.

As can be seen in FIG. 5, cutter supports 144 support kerf cutters 142 in an angular deployment. This configuration provides flow passages 154 between kerf cutters 142, which connect internal flow slots 152 to external junk slots 146. This is best seen in FIG. 4, which also illustrates external junk slots 146 merged to junk channel 136, which is itself contiguous with both lead face 112 and trailing face 114 of leg 110. Lead face 112 and trailing face 114 of leg 110 define the boundaries of the large annular relief between cutter assemblies 100.

FIG. 9 is a side view of drill bit 10, as viewed between adjacent cutter assemblies 100. From this view, the large annular clearance provided between trailing face 114 of one cutter assembly 100 and lead face 112 of the adjacent cutter assembly 100 is clearly visible.

Likewise, in the alternative embodiment for drill bit 11, seen in FIG. 13, kerfing assemblies 200 have an internal flow channel 250 is disposed circumferentially above transition face 222. Kerfing segment 240 extends downward from flow channel 250. On the inside of kerfing segment 240, internal flow slots 252 are vertically disposed between cutter supports 244, and merge with flow channels 250.

Flow passages 254 between kerf cutters 142, connect internal flow slots 252 to external junk slots 246. This is best seen in FIG. 12, which also illustrates external junk slots 146 merged to junk channel 236, which is itself contiguous with both lead face 212 and trailing face 214 of leg 210. Lead face 212 and trailing face 214 of leg 210 define the boundaries of the large annular relief between kerfing assemblies 200, and between kerfing assemblies 200 and cutter assembly 100.

FIG. 7 is a side-sectional view of cutter assembly 100. As can also be inferred from FIG. 7, internal lubrication system 130 is contiguous to the external surface of journal 126 and the internal surface of cone 180, so as to provide pressure neutralized lubrication between journal 126 and cone 180, and to prevent the intrusion of drilling fluid between journal 126 and cone 180, in the manner that is well known in the industry.

FIG. 14 is a side view of alternative embodiment drill bit 11, as viewed between adjacent kerfing assemblies 200. From this view, the large annular clearance provided between trailing face 214 of one kerfing assembly 200 and lead face 212 of the adjacent kerfing assembly 200 is clearly visible.

FIG. 10 is a top view of the preferred embodiment of drill bit 10. In this view, it is seen that cones 180 have dissimilar cutting structures such that combined, they can rotate without interfering, and can best cover the bottom of the wellbore. This is noted by the designation of each cone 180 with a different alphanumeric suffix a through c.

Similarly, in the preferred embodiment, each kerf cutter 142 on a given cutter assembly 100 is located at a designated radial distance to the center of drill bit 10, known as the radial position of the kerf cutter 142. The radial position of each kerf cutter 142 may be unique. This is noted by the designation of each kerf cutter 142 with a different alphanumeric suffix a through c, with a designating the innermost kerf cutter 142 and c designating the outermost kerf cutter 142. In this manner, drill bit 10 can be specifically designed so that the combined physical forces acting on the combined cutters 142 and 182 on any given cutter assembly 100 are collectively, substantially equal. This provides a drill bit 10 that operates more efficiently. Due to the modular construction of drill bit 10, modification can be made on the basis of test and/or field results with minimal disruption to the manufacturing process.

FIG. 15 is a top view of the preferred embodiment of drill bit 11. In this view, it is seen that cone 180 is considerably larger than cone 180 of drill bit 10. In this embodiment, cone 180 and teeth 182 will drill substantially the entire well face internal to the placement of kerf cutter 142. The larger structure of a single cone 180 provides substantial design flexibility related to the larger components associated with a single cone bit, since cone size is reduced relative to hole size to accommodate outer diameter kerf cutters 142. Also, the larger structure of a single cone 180 provides substantial design as associated with the different performance characteristic of a single cone drill bit 11.

Moreover, the modular design of the present invention, while disclosed in detail a three-cone embodiment drill bit 10 and a one-cone embodiment drill bit 11, it can easily be configured to accommodate two cutting assemblies 100 and a single kerfing assembly 200. Likewise, by adding or removing slots 22 on body 12, other combinations of cutter assemblies 100 and kerfing assemblies 200 can be created.

The foregoing detailed description is to be clearly understood as being given by way of illustration and example, the spirit and scope of the present invention being limited solely by the appended claims.

Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US7661490Apr 10, 2007Feb 16, 2010Raney Richard CStabilizing system and methods for a drill bit
US8056651 *Apr 28, 2009Nov 15, 2011Baker Hughes IncorporatedAdaptive control concept for hybrid PDC/roller cone bits
US20120205160 *Feb 7, 2012Aug 16, 2012Baker Hughes IncorporatedSystem and method for leg retention on hybrid bits
WO2009135119A2 *May 1, 2009Nov 5, 2009Baker Hughes IncorporatedModular hybrid drill bit
Classifications
U.S. Classification175/374, 175/398, 175/415
International ClassificationE21B10/00
Cooperative ClassificationE21B10/04
European ClassificationE21B10/04
Legal Events
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