STEERABLE FIXED CUTTER DRILL BIT
A fixed cutter drill bit includes a plurality of gage pads, where certain of the gage pads have an active cutting region adjacent to the end of the gage pad adjacent to the bit face, and a passive region at the end of the gage pad adjacent to the pin-end of the bit. The active regions include forward-facing cutter elements. Other gage pads include an active region on the end adjacent to the pin-end, and a passive region on the gage pad end adjacent to the bit face. The passive and active regions have lengths within the range of 40 to 60 percent of the total axial length of the gage pads. A passive gage pad is positioned on the bit between the gage pads having both active and passive regions.
This application claims benefit of U.S. provisional application Ser. No. 60/741,005 filed Nov. 30, 2005, and entitled “Side Cutting Drill Bit and Gage Pad Configuration,” which is hereby incorporated herein by reference in its entirety.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENTNot Applicable.
BACKGROUND1. Field of the Invention
The invention relates generally to earth boring drill bits. More specifically, the invention relates to fixed cutter, steerable drill bits.
2. Description of the Related Art
In drilling a borehole in the earth, such as for the recovery of hydrocarbons, minerals or for other applications, it is conventional practice to connect a drill bit on the lower end of an assembly of drill pipe sections which are connected end-to-end so as to form a “drill string.” The drill string and bit are rotated by apparatus that is positioned on a drilling platform located at the surface of the borehole. The bit may also or alternatively be rotated by means of a downhole motor that is connected to the drill string above the bit. Such apparatus turns the bit and advances it downward, causing the bit to cut through the formation material by either abrasion, fracturing, shearing, or through a combination of all cutting methods. While the bit rotates, drilling fluid is pumped through the drill string and directed out of the drill bit through nozzles that are positioned in the bit face. The drilling fluid cools the bit and flushes cuttings away from the cutting structure and face of the bit. The drilling fluid and cuttings are forced from the bottom of the borehole to the surface through the annulus that exists between the drill string and the borehole sidewall.
Many different types of drill bits with different rock removal mechanisms have been developed and found useful in drilling such boreholes. Such bits include diamond impregnated bits, milled tooth bits, tungsten carbide insert (“TCI”) bits, polycrystalline diamond compacts (“PDC”) bits, and natural diamond bits. The selection of the appropriate bit and cutting structure for a given application depends upon many factors.
Without regard to the type of bit, the cost of drilling a borehole for recovery of hydrocarbons is proportional to the length of time it takes to drill the borehole to the desired depth and location. The drilling time, 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 because each time the bit is changed, the entire drill string, 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 must be reconstructed again, 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 that will drill faster and longer and that are usable over a wider range of differing formation hardnesses.
The length of time that a drill bit is kept in the hole before the drill string must be tripped and the bit changed depends upon a variety of factors. These factors include the bit's rate of penetration (“ROP”), its durability or ability to maintain a high or acceptable ROP, and its ability to be steered along the predetermined path or drilling program. Also important is borehole quality, as represented by the smoothness of the borehole wall created by the drill bit.
With modern drilling practices, especially important to maximizing the time that a dill bit may be kept in the hole before the drill string must be tripped and the bit changed is the bit's ability to achieve the objectives outlined by the drilling program, especially in directional applications. For example, varying formation hardnesses may dictate the need for different types of drill bits for use in different portions of the borehole. In directional applications, a particular drill bit design may be most appropriate for high dog leg applications (i.e., an application requiring relatively severe turning angles), while a different drill bit is most suited for low dog leg applications (i.e., an application requiring relatively gradual turning angles).
In recent years, the fixed cutter bit has become an industry standard for cutting formations of soft and medium hardnesses, and some hard formations. The inserts or cutter elements used in such bits are formed of extremely hard materials, which sometimes include a layer of thermally stable polycrystalline (“TSP”) material or polycrystalline diamond compacts (“PDC”). In the typical fixed cutter PDC bit, each cutter element comprises an elongate and generally cylindrical support member which is received and secured in a pocket formed in the surface of the bit body. A disk or tablet-shaped, hard cutting layer of polycrystalline diamond or thermally stable polycrystalline material is bonded to the exposed end of the support member, which is typically formed of tungsten carbide. For convenience, a fixed cutter bit employing either PDC or TSP cutter elements will be referred to in the following disclosure as a “PDC bit.”
A PDC bit may also include gage pads extending from the bit body on the sides of the drill bit. Among other purposes, gage pads may be employed to reduce vibrations experienced by the drill bit, as well as to help maintain the borehole at the desired full gage diameter. In general, vibrations are undesirable because excess vibration of the drill bit reduces the effectiveness and ROP of the drill bit, interferences with communications, and increases detrimental loads and stresses on various drill string components. A bit that experiences relatively minor vibrations is referred to as a “stable” bit. Thus, a stable PDC bit is preferred to enhance drilling effectiveness and ROP.
Side cutting is a drill bit's ability to cut the sidewall of the borehole, as contrasted to cutting the bottom of the borehole. Side cutting ability is particularly important in directional drilling applications where a drill bit must be steered to achieve different trajectories as dictated by the inclination or azimuth called for by the predetermined drilling plan or program. For example, in horizontal drilling through a pay zone (i.e., the formation layer that contains the hydrocarbons to be recovered), it is not uncommon for the pay zone to incline or decline over a portion of its length. To stay in the pay zone, or the desired portion of the pay zone, carefully controlled steering of the drill bit may be necessary. Such steering ability is greatly enhanced by employing a bit that provides substantial side wall cutting.
All PDC bits are not well suited for side cutting however, and the design of a successful side cutting drill bit is a challenge. In some applications, an ability to make quick, severe changes in drilling direction is most important, while other application may require design features making the drill bit more suited to cutting longer straight sections of the borehole, even if the drill bit's ability to make sharp turns is somewhat compromised.
Attempts to provide a bit having side cutting capability have included placing forward-facing cutter elements along the length of the bit's gage pads, rather than employing “cutterless” gage pads that simply resist wear and rub the sidewall. In addition to enhancing the side cutting capability of the drill bit, forward-facing cutter elements disposed on the bit's gage pads to engage the borehole sidewall also improves the directional maneuverability or steerability of the bit. Although forward-facing cutter elements along the length of the gage pads may allow the bit to be steered to make sharp or relatively “quick” turns, such an arrangement can result in a drill bit that requires increased torque for rotation since the side cutting cutter elements cut or bite into the borehole sidewall, particularly upon unplanned trajectory changes. Increased bit torque may lead to increased likelihood for lateral torsional excitations, vibrations, bit whirl, or combinations thereof. Excessive vibrations may place increased and undesirable loads on the drill string components, as well as detrimentally affect tool electronics and communication capabilities. Thus, many conventional steerable fixed cutter bits with forward-facing cutter elements spaced along the entire length of the gage pad may be easily steered, but tend to experience undesirable vibrations. For example, some conventional steerable bits capable of making 0-5° turns within 100 feet are highly maneuverable, but are especially more prone to severe vibrations. On the other hand, cutter less gage pads (i.e., gage pads without forward-facing cutter elements) generally require less torque to rotate, but provide reduced and limited steerability.
A “sail” is a length of borehole intended to remain constant in terms of angular trajectory or cutting path. During long sails, relatively little corrective turning is needed, provided the bit “holds angle” and does not deviate from the desired path or trajectory. Unfortunately, due to unforeseen faults, variations in formation material, or other occurrences, the bit will sometimes “lose angle” and leave the desired path. When that occurs, some correction needs to be made in order to place the bit back on the intended path. Drill bits that include aggressive side cutting features provide improved maneuverability and enable the bit to be correctively steered back onto the desired path quickly. Such aggressive side cutting bits include those having cutter elements positioned along substantially the entire length of each of the bits' gage pads, or on at least on certain of the gage pads. However, as previously described, although steerable fixed cutter bits with forward-facing cutter elements spaced along the gage pads may be easily steered, such bits tend to experience undesirable vibrations. In addition, during long sails or tangent trajectories, the aggressive side cutting features tend to cut the low-side of the borehole, making it difficult to hold angle. Further, this arrangement tends to result in the introduction of undesirable “kinks” or “irregularities” in the borehole at each change in direction, thereby decreasing borehole quality. Drilling a borehole with an undesirable number of such kinks increases the stress and forces applied to the drill string, and may lead to tools becoming stuck in the borehole or otherwise damaged. Thus, some highly maneuverable conventional bits are capable of directional changes in a short length of borehole, but they tend to create boreholes with less than desirable quality. Still further, it should also be appreciated that any damage to the forward-facing cutter elements for side cutting (e.g., due to chipping, spalling, or breakage) reduces the ability of the bit to maintain full gage diameter.
An alternative bit design calls for longer gage pads and fewer cutter elements along the gage pads' lengths, such that the PDC bit and its gage pads may be said to be less aggressive. Such a design may be highly desirable in relatively long sails where few directional changes need to be made. In addition, such bits having less-aggressive gage pad cutting structures generally require less torque to rotate, and thus, are less likely to contribute and/or excite the bit into torsional vibrations. However, when a correction does need to be made, the less aggressive bit is less responsive. Consequently, changes in direction must occur much more slowly, requiring a substantially greater length of borehole in order to affect a directional change.
Accordingly, an improved PDC bit providing good ROP and borehole quality, yet still capable of reasonable maneuverability within what might be a generally narrow pay zone would be welcome in the art. Such a bit would be particularly well received if it offered the potential to reduce vibrations experienced by the bit, effectively maintained full gage diameter, and created a relatively smooth borehole during use.
SUMMARY OF PREFERRED EMBODIMENTSThe embodiments described herein include a fixed cutter drill bit particularly suited for low dog-leg applications where modest build rates are needed. In certain embodiments, the bit includes a bit body having a bit face with a cutting structure for cutting a borehole to full gage diameter, and a pin-end opposite said bit face. The bit includes a plurality of gage pads spaced about said bit body. Certain of the gage pads include forward-facing cutter elements forming an active cutting region on an end of the gage pad that is closer to the bit face than to the pin-end, and include a passive region, without forward-facing cutter elements, located on the end of the gage pad closer to the pin-end than the bit face. The passive and active regions each have a length that is within the range of 40 to 60 percent of the length of the gage pad. In this embodiment, the bit includes a passive gage pad immediately adjacent to the gage pad having passive and active regions.
In other embodiments, the fixed cutter drill bit includes one or more additional gage pads having active and passive regions, as described above, but that are located at different positions. Specifically, in such embodiments, the drill bit includes a gage pad having forward-facing cutter elements and an active region on the end of the gage pad that is closer to the pin-end than to the bit face.
The active regions of multiple gage pads form, in rotated profile, a composite active cutting profile that has a length of approximately 50 percent of the length of the gage pads, and within the range of 40 to 60 percent of their length. Likewise, the passive regions of other of the gage pads form, in rotated profile, a composite passive cutting profile having a length of about 50 percent of the length of the gage pads, and within the range of 40 to 60 percent of the gage pads' length.
The embodiments described herein provide the maneuverability required in many applications. Although maneuverable, the bit resists vibration and produces a borehole with fewer kinks or restrictions as may be created by a drill bit that employs forward-facing cutter elements along the entire length of the bit's gage pads. Thus, the embodiments described herein comprise a combination of features providing the potential to overcome certain shortcomings associated with prior devices. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description of the preferred embodiments, and by referring to the accompanying drawings.
BRIEF DESCRIPTION OF THE DRAWINGSFor a more detailed description of the preferred embodiments, reference will now be made to the accompanying drawings, wherein:
Referring to
Body 12 includes a central longitudinal bore 17 permitting drilling fluid to flow from the drill string into bit 10. Bit body 12 further includes a bit face 20 formed on the end of the bit 10 opposite pin end 16 and which supports cutting structure 15. Body 12 is formed in a conventional manner using powdered metal tungsten carbide particles in a binder material to form a hard metal cast matrix. Alternatively, body 12 can be machined from a metal block, such as steel, rather than being formed from a matrix.
As shown in this example, bit 10 includes eight angularly spaced-apart blades 31-38, which are integrally formed as part of, and which extend from, bit body 12. Blades 31-38 extend radially across the bit face 20 and longitudinally along a portion of the periphery of the bit. It should be understood that as used herein, the term “radial” or “radially” refers to positions or movement substantially perpendicular to bit axis 11. In addition, it should be understood that as used herein, the term “axial,” “axially”, or “longitudinally” refers to positions or movement generally parallel to bit axis 11.
Referring still to
Referring still to
Conventional drill bits sometimes include wear-resistant inserts embedded in the gage pads and protruding from the gage-facing surface of gage pads. These inserts, which may include diamond coatings or coatings of other super-abrasive materials, are disposed in the gage pad so as to generally face the borehole sidewall. Whether they be termed cutters or abrasion-resistant inserts or otherwise, these wear-resistant inserts are not “forward-facing” cutter elements as the term is used herein. Such wear-resistant inserts may be employed in gage-facing surface 60 of one or more gage pads 51-58. For example, as shown in
Inserts 100 are made of a harder and more wear-resistant material than the material used to form gage pads 51-58, and thus, aid in protecting the gage pads against excessive wear and abrasion. Consequently, gage pads having wear-resistant inserts such as insert 100 maintain full gage diameter for a longer period of time and tend to improve the staibilty of the bit against vibration. Although such inserts aid in maintaining the bit's stability, they are not intended to actively cut the borehole sidewall.
Certain of gage pads 51-58 include forward-facing cutter elements 70 disposed in forward-facing surface 61. More specifically, as best shown in
Cutter elements 70 include cutting profiles that extend substantially to full gage diameter and are particularly useful in steering bit 10. In contrast to gage pads 51, 57, gage pads 52 and 58 do not support forward-facing cutter elements in this embodiment, and thus, may be described as “passive” along their entire length. The passive regions on the gage pads provide a gage protection region that extends substantially to full gage diameter, thereby aiding in maintaining full gage diameter. Such passive regions are substantially free from active cutter elements, i.e., forward-facing cutter elements having cutting faces extending to substantially full gage diameter. Thus, as used herein, the term “passive” may be used to describe gage pads, regions of gage pads, or composite profiles of gage pads that are free of forward-facing cutter elements having cutting faces extending substantially to full gage diameter. As a further illustration, a portion of the gage pad including a forward-facing cutter element whose cutting face does not extend to full gage diameter would still be a “passive” cutting region as used herein.
Certain features and operating principles of bit 10 are best understood with reference to
As shown in
Referring still to
Gage pads 51 and 55 each include three cutter elements 70 positioned in face-side portion 81. Similarly, gage pads 53 and 57 each include three forward-facing cutter elements 70 positioned in pin-side portion 82. In general, the regions or portions of the gage pads 51-58 having forward-facing cutter elements 70 retained therein are described herein as being “active” regions or “active” cutting regions. Thus, gage pads 51 and 55 may be described as including face-side active regions 72 that are closer to the bit face 20 than to pin-end 16. Similarly, gage pads 53 and 57 include pin-side active regions 73 that are closer to the pin-end 16 than to bit face 20. As used herein, the term “active” refers to gage pads or regions of gage pads that include forward-facing cutter elements whose cutting faces extend substantially to full gage diameter.
Referring still to
Referring still to
Referring again to
In the embodiment thus described with reference to
In general, the greater the length of the active cutting region of a gage pad (i.e., the greater the percentage of gage pad length L1 occupied by the active cutting region), the more aggressive the side cutting ability of the bit and the more maneuverable the bit (i.e., the greater the ability of the bit to turn more quickly over a shorter length of borehole). However, longer active cutting regions tend to make the bit more susceptible to torsional excitation and undesirable vibrations. In addition, longer active cutting regions may impair the ability of the bit to maintain full gage diameter in the event one or more forward-facing cutter elements (e.g., cutter elements 70) becomes damaged (e.g., chips, spalls, or breaks), and further, may reduce the ability of the bit to hold angle over long sails and straight trajectories. In the embodiments illustrated in
Bit 10 may also be described as including a plurality of gage pads that are arranged in pairs. The first of the pair (gage pad 51 for example) includes an active region 72 that is closer to the bit face 20 than to the pin end 14, and the other of the pair (pad 53 in this example) includes an active region 73 that is closer to the pin end 14 of bit 10 than to bit face 20. Disposed between the pair of gage pads having active cutting regions, bit 10 includes a passive gage pad (pad 52 in this example) having no forward-facing cutter elements and thus no active region.
Embodiments of drill bit 10 as shown and described with reference to
Accordingly, embodiments of bit 10 provide the bit designer the capability of having relatively long gage pads with passive regions as desirable for long sails where the bit does not change build angle. Most conventional bits employing relatively long pads without forward-facing cutter elements are ideally suited for long sails and generally experience reduced vibrations, but are typically not as maneuverable as desired. By providing the arrangement of forward-facing cutter elements 70 in selected positions on certain gage pads of bit 10 as described above, embodiments of bit 10 provide relatively long gage pads having passive regions and associated benefits, and also offers the potential for modest but sufficient build rate, steering, and maneuverability. The relatively long gage pads 51-58 of bit 10 described with reference to
The gage-facing surface 60 of gage pads 51-58 may extend generally parallel to bit axis 11 and the borehole wall along its entire longitudinal length as, for example, shown with respect to gage pads 52, 54, 56 and 58. Alternatively, portions of the gage-facing surface 60 of gage pads 51-58 may be angled or tapered relative to bit axis 11. For example, referring to the representation of gage pad 51 shown in
The cutter elements 70a-c on gage pad 51 include cutting faces of non-uniform size. Specifically, as shown in
Referring to the cutter arrangement on gage pad 53, the cutter element having the smallest cutting face 70d is closest to plane 80, while the cutter element 70f having the largest cutting face is furthest from (i.e., distal) plane 80 and is closest to pin 14. Cutter element 70e with a cutting face smaller than that of 70f but larger than that of 70d is disposed between cutter elements 70d and 70f. The cutter elements 70j-l of gage pad 57 are arranged so as to be offset slightly from the positions of cutter elements 70d-f of gage pad 53, thereby leaving substantially no uncut portion of borehole sidewall that comes into engagement with the composite active pin-side region 86.
The gage-facing surfaces 60 of gage pads 51, 53, 55, 57 may include active regions which are configured differently than that shown in
As a further example, the gage-facing surface may include an active region that is sloped in a direction opposite that shown for gage pad 51 in
Although many factors will determine the arrangement of cutter elements 70 on the gage pads, the arrangement shown in
Bit 10 described above includes eight gage pads including four that include both active and passive regions; however, employing fewer than eight gage pads can still produce a steerable bit having an acceptable build rate and vibration level for at least certain formations and conditions. For example, a six bladed bit having only gage pads 51-56 as described previously with respect to
Likewise, a four bladed bit having only gage pads 51-54 as described in
While preferred embodiments of this invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit or teaching of this invention. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the system and apparatus are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims which follow, the scope of which shall include all equivalents of the subject matter of the claims.
Claims
1. A drill bit for drilling a borehole having a predetermined full gage diameter, the bit comprising:
- a bit body having a bit face with a cutting structure thereon, and a pin end opposite the bit face;
- at least a first and a second gage pad positioned on the bit body between the bit face and the pin end, wherein the second gage pad is angularly spaced apart from the first gage pad;
- wherein the first gage pad comprises a first axial length, an active region including a plurality of generally forward-facing cutter elements having cutting surfaces extending substantially to full gage diameter, and a passive region including a gage-facing surface extending substantially to gage diameter, wherein each of the active and passive regions has a length between 40 and 60 percent of the first axial length; and
- wherein the second gage pad comprises a second axial length, a gage-facing surface extending substantially to full gage diameter, and a passive cutting region along substantially all of the second axial length.
2. The drill bit of claim 1 wherein the length of the active region of the first gage pad is within the range of 45-55 percent of the first axial length.
3. The drill bit of claim 1 wherein the active region of the first gage pad is positioned proximal the bit face.
4. The drill bit of claim 1 wherein the active region of the first gage pad is positioned proximal the pin-end.
5. The drill bit of claim 1 wherein the first gage pad is disposed at an angular position immediately adjacent the second gage pad.
6. The drill bit of claim 1 wherein the cutting surface of each forward-facing cutter element has a cutting face surface area, wherein at least two of the forward-facing cutter elements have cutting surfaces with different cutting face surface areas.
7. The drill bit of claim 1 wherein the active region of the first gage pad includes a gage-facing surface and wherein the gage-facing surface of the active region and passive region of the first gage pad are substantially parallel to the bit axis.
8. The drill bit of claim 1 wherein the active region of the first gage pad includes a gage-facing surface including a tapered portion oriented at an angle between 0° and 10° relative to the bit axis.
9. The drill bit of claim 8 wherein the tapered portion is oriented at an angle between 7° and 10° relative to the bit axis.
10. A drill bit for forming a borehole in earthen formations, the bit comprising:
- a bit body having a bit axis, a bit face, and a pin end opposite the bit face;
- a plurality of gage pads having first and second ends and disposed about the bit body at angularly spaced-apart positions, the first end of each gage pad being closer to the bit face than to the pin end;
- a first of the plurality of gage pads having a length and comprising an active region including a plurality of forward-facing cutter elements and a passive region, each of the active and passive regions of the first gage pad having a length of at least 40 percent of the length of the first gage pad; and
- a second of the plurality of gage pads disposed at an angular position immediately adjacent to the first gage pad, the second gage pad having a length and comprising a passive region along substantially the entire length of the second gage pad.
11. The drill bit of claim 10 wherein the active region of the first of the plurality of gage pads is positioned adjacent the first end of the first gage pad and wherein the passive region of the first of the plurality of gage pads is positioned adjacent the second end of the first gage pad.
12. The drill bit of claim 11 further comprising:
- a third of the plurality of gage pads disposed at an angular position immediately adjacent to the second gage pad such that the second gage pad is disposed between the first and third gage pads, the third gage pad having a length and comprising an active region including a plurality of forward-facing cutter elements adjacent to the second end of the third gage pad and a passive region adjacent to the first end of the third gage pad, the active and passive regions of the third gage pad each having a length of at least 40 percent of the length of the third gage pad.
13. The drill bit of claim 12 further comprising a fourth gage pad disposed at an angular position immediately adjacent to the third gage pad such that the third gage pad is disposed between the second gage pad and the fourth gage pad, the fourth gage pad having a length and comprising a passive region along substantially the entire length of the fourth gage pad.
14. The drill bit of claim 10 wherein the active region of the first of the plurality of gage pads is positioned adjacent the second end of the first gage pad and wherein the active region of the first of the plurality of gage pads is positioned adjacent the second end of the first gage pad.
15. The drill bit of claim 14 further comprising:
- a third of the plurality of gage pads disposed at an angular position immediately adjacent to the second gage pad such that the second gage pad is disposed between the first and third gage pads, the third gage pad having a length and comprising an active region including a plurality of forward-facing cutter elements adjacent to the first end of the third gage pad and a passive region adjacent to the second end of the third gage pad, the active and passive regions of the third gage pad each having a length of at least 40 percent of the length of the third gage pad.
16. The drill bit of claim 15 further comprising a fourth gage pad disposed at an angular position immediately adjacent to the third gage pad such that the third gage pad is disposed between the second gage pad and the fourth gage pad, the fourth gage pad having a length and comprising a passive region along substantially the entire length of the fourth gage pad.
17. The drill bit of claim 10 wherein each of the forward-facing cutter elements of the active region of the first gage pad extends substantially to a predetermined full gage diameter.
18. The drill bit of claim 10 wherein the first and second of the plurality of gage pads each includes a gage-facing surface including at least a portion that extends substantially to a predetermined full gage diameter and is substantially parallel to the bit axis.
19. The drill bit of claim 15 wherein the gage-facing surface of the first of the plurality of gage pads comprises a tapered portion oriented at angle between 0° and 10° relative to the bit axis.
20. A drill bit for cutting a borehole at a predetermined full gage diameter, the bit comprising:
- a bit body having at least eight gage pads disposed about the body at angularly spaced-apart positions;
- a bit face on the bit body, the bit face comprising a cutting structure cutting the borehole to the full gage diameter;
- a pin end on the bit body opposite the bit face;
- wherein a first and a second of the gage pads each comprises a plurality of forward-facing cutter elements forming an active cutting region that is closer to the bit face than to the pin end, and a passive region closer to the pin end than to the bit face;
- wherein a third and a fourth of the gage pads each comprises a plurality of forward-facing cutter elements forming an active cutting region that is closer to the pin-end than to the bit face, and a passive region that is closer to the bit face than to the pin-end;
- wherein the gage pads are angularly spaced about the bit such that each of the first and second gage pads is disposed at a location that is between the third and fourth gage pads; and
- wherein four other of the at least eight gage pads includes only a passive cutting region.
21. The drill bit of claim 20 wherein one of the four other gage pads is angularly positioned between two of the gage pads having the active and passive regions.
22. The drill bit of claim 20 wherein each of the forward-facing cutter elements of each active region extend substantially to the predetermined full gage diameter.
23. The drill bit of claim 20 wherein each of the eight gage pads includes a gage-facing surface having at least a portion that extends substantially to the predetermined full gage diameter.
24. A drill bit for drilling through earthen formations and forming a borehole of a predetermined full gage diameter, the bit comprising:
- a bit body;
- a bit face on the body having a cutting structure for cutting the borehole to full gage diameter;
- a pin end on said body opposite the bit face;
- a plurality of gage pads angularly spaced about the bit body, each gage pad having a length;
- wherein at least a first and a second of the gage pads each comprise forward-facing cutter elements that are positioned closer to the pin end than to the bit face, the first and second gage pads forming a first composite active cutting profile having a length equal to between 40 and 60 percent of the length of the first gage pad, the first composite active cutting profile being located closer to the pin end of the bit than to the cutting face;
- wherein each of the first and second gage pads further includes a passive cutting region positioned at a location closer to the bit face than to the pin end and forming a first composite passive cutting profile having a length of between 40-60 percent of the length of the first gage pad; and
- a third gage pad disposed at an angular position between the first and second gage pads, wherein the third gage pad is passive.
25. The drill bit of claim 24 further comprising:
- a fourth gage pad disposed an angular position between the first and third gage pads, wherein the fourth gage pad is passive.
26. The drill bit of claim 25 further comprising:
- a fifth gage pad comprising forward-facing cutter elements forming an active cutting region that is closer to the bit face than to the pin end, and further comprising a passive region that is closer to the pin end than to the bit face; and
- wherein the fifth gage pad is disposed an angular position between the third and fourth gage pad.
27. The drill bit of claim 24 further comprising a fourth and a fifth gage pad, each comprising forward-facing cutter elements that are positioned closer to the bit face than to the pin-end, the fourth and fifth gage pads forming a second composite active cutting profile having a length between 40 and 60 percent of the length of the first gage pad, the second composite active cutting profile being located closer to the bit face than to the pin-end;
- wherein each of the fourth and a fifth gage pads further comprises a passive cutting region positioned at a location closer to the pin-end than to the bit face, and forming a second composite passive cutting profile having a length between 40 and 60 percent of the length of the first gage pad.
28. The drill bit of claim 27 wherein each of the fourth and a fifth gage pads is positioned at a different angular position, and positioned at an angular position that is between the first and second gage pads.
29. The drill bit of claim 28 wherein the bit further comprises at least one passive gage pad located at an angular position between each of the first, second, fourth and fifth gage pads.
30. The drill bit of claim 27 wherein the first composite active cutting profile overlaps with the second composite active cutting profile by no more than 10 percent of the length of the first gage pad.
Type: Application
Filed: Nov 29, 2006
Publication Date: Sep 6, 2007
Inventor: Graham Mensa-Wilmot (Houston, TX)
Application Number: 11/564,447
International Classification: E21B 10/62 (20060101);