STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
Not applicable.
BACKGROUND
Embodiments described herein relate generally to earth-boring drill bits used to drill a borehole for the ultimate recovery of oil, gas, or minerals. More particularly, embodiments described herein relate to expandable drill bits and actuation systems for such bits.
In drilling a borehole (or wellbore) into the earth for the recovery of hydrocarbons from a subsurface formation, it is conventional practice to connect a drill bit to the lower end of a conduit (e.g., drill string, coiled tubing, etc.). The drill bit is then rotated either alone or along with the conduit with weight on bit (WOB) applied to engage the earthen formation and thus lengthen the resulting borehole. As the borehole extends deeper within the subterranean formation, casing pipe is inserted therein to line and thus provide additional structural reinforcement for borehole.
Often it is desirable to drill a slightly larger diameter borehole within the producing zones of the formation than in the initial sections of borehole that are closer to the surface. However, a larger bit may not be capable of passing through the relatively smaller casing string and borehole to reach the desired zone for larger borehole drilling. Eccentric drill bits and other cutting structures have been developed that are capable of drilling a relatively large borehole when rotated about their center of rotation, while maintaining a sufficiently small pass-through diameter capable of being advanced through the relatively smaller casing string. However, these bits are typically limited to a single size such that drilling selectively larger and smaller boreholes is not possible with a given bit, and unfortunately, replacing a drill bit with a different sized drill bit (to form a smaller or larger section of the borehole) often requires bringing the drill bit, along with the entire length of drillstring to the surface. This action is typically referred to as a “trip” of the drill bit and drillstring and requires hours of additional personnel and equipment time, such that each trip to the surface dramatically increases the total costs of drilling the borehole.
BRIEF SUMMARY OF THE DISCLOSURE
Embodiments disclosed herein are directed to a drill bit for drilling a borehole in a subterranean formation. In an embodiment, the drill bit includes a bit body having a central axis, an uphole end configured to be coupled to a drill string, and a downhole end including a cutting structure configured to engage the formation, wherein the bit body includes a bore extending axially from the uphole end and an aperture extending radially from the bore to a radially outer surface of the bit body. In addition, the drill bit includes a mandrel movably disposed in the bore, wherein the mandrel has a first end, a second end, a radially outer surface extending axially from the first end to the second end, and a radially inner surface extending axially from the first end to the second end. The outer surface of the mandrel includes an inclined surface oriented at an acute angle relative to the central axis. Further, the drill bit includes a first blade moveably disposed in the aperture and axially positioned between the cutting structure and the uphole end. The first blade has a radially retracted position and a radially extended position configured to engage a sidewall of the borehole to enlarge the borehole. The mandrel is configured to translate axially relative to the bit body to slide the inclined surface of the mandrel along the first blade to transition the first blade between the radially refracted position and the radially extended position.
Embodiments disclosed herein are directed to a downhole tool for enlarging a borehole extending through a subterranean formation. In an embodiment, the downhole tool has a central axis and includes a body having a central axis, an uphole end configured to be coupled to a drill string, a downhole end, a bore extending axially from the uphole end, and an aperture extending radially from the bore to a radially outer surface of the body. In addition, the downhole tool includes a mandrel movably disposed in the bore, wherein the mandrel has a first end, a second end, a radially outer surface extending axially from the first end to the second end, and a radially inner surface extending axially from the first end to the second end. The outer surface of the mandrel includes an inclined surface oriented at an acute angle relative to the central axis. Further, the downhole tool includes a first blade movably disposed in the aperture, wherein the first blade has a radially refracted position and a radially extended position configured to engage with a sidewall of the borehole to enlarge the borehole. The mandrel is configured to translate axially relative to the body to slide the inclined surface of the mandrel along the first blade to transition the first blade between the radially refracted position and the radially extended position.
Embodiments disclosed herein are directed to a method for enlarging a borehole extending through a subterranean formation. In an embodiment, the method includes (a) rotating a downhole tool about a central axis, the downhole tool including a central bore and a blade. In addition, the method includes (b) flowing drilling fluid through the bore of the downhole tool, wherein the drilling fluid has a pressure in the bore. Further, the method includes (c) increasing the pressure of the drilling fluid in the bore, and (d) moving a mandrel axially within the bore in a first direction in response to the increase in pressure in (c). Still further, the method includes (e) slidingly engaging the blade with an inclined surface on the mandrel during (d), and (f) moving the blade radially outward in response to the sliding engagement in (e).
Embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. 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, and by referring to the accompanying drawings. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.
BRIEF DESCRIPTION OF THE DRAWINGS
For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:
FIG. 1 is a schematic, partial cross-sectional view of an embodiment of a drilling system in accordance with the principles disclosed herein for drilling a borehole in an earthen formation;
FIG. 2 is a perspective view of the drill bit of FIG. 1;
FIG. 3 is a perspective cross-sectional view of the drill bit of FIG. 2;
FIG. 4 is a perspective view of the mandrel of the drill bit of FIG. 2;
FIG. 5 is a perspective view of the radially extendable member of FIG. 2;
FIG. 6 is a bottom view of the radially extendable member of FIG. 2;
FIG. 7 is a cross-sectional side view of the drill bit of FIG. 2 with the radially extendable member in the retraction position;
FIG. 8 is a cross-sectional side view of the drill bit of FIG. 2 with the radially extendable member in the expanded position; and
FIG. 9 is a cross-sectional side view of an embodiment of a downhole tool for enlarging a borehole in accordance with the principles disclosed herein.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.
Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.
In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . . ” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. Any reference to up or down in the description and the claims is made for purposes of clarity, with “up”, “upper”, “upwardly”, “uphole”, or “upstream” meaning toward the surface of the borehole and with “down”, “lower”, “downwardly”, “downhole”, or “downstream” meaning toward the terminal end of the borehole, regardless of the borehole orientation. As used herein, the term “Bi-center bit” is used to refer to a drill bit or other cutting tool that is configured to simultaneously drill a borehole having an initial diameter and enlarge the borehole to a final diameter that is larger than the initial diameter.
Referring now to FIG. 1, an embodiment of a drilling system 10 for drilling a borehole 11 in an earthen formation 12 is shown. Drilling system 10 includes a derrick 20 supported by a drilling deck or floor 21. Derrick 20 includes a traveling block 22 for raising and lowering a top drive 23 configured to releasably connect to and support a drill string 30. Top drive 23 is supported by derrick 20 and employed to rotate drill string 30.
Drilling system 10 also includes a drill string 30, a bottom hole assembly 32, and a drill bit 100. Drill string 30 has a central or longitudinal axis 35, a first or uphole end 30a, and a second or downhole end 30b. In this embodiment, drill string 30 is made from a plurality of tubulars or pipe joints 31 coupled together end-to-end. Each pipe joint 31 has a first or upper end 31a comprising an internally threaded box and a second or lower end 31b comprising an externally threaded pin. Joints 31 are connected end-to-end by threading pins into the mating boxes to form threaded connections or joints 34. Bottom hole assembly (BHA) 32 is coupled to the lower end 30b of drill string 30 and drill bit 100 is coupled to the lower end of BHA 32.
During drilling operations, drill bit 100 is rotated with weight-on-bit (WOB) applied to drill the borehole 11 through the formation 12. Traveling block 22 is operated to control the WOB, which impacts the rate-of-penetration of drill bit 100 through the formation 12. In this embodiment, drill bit 100 can be rotated from the surface by drillstring 30 via top drive 23, rotated by downhole mud motor 33 disposed in BHA 32 proximal bit 100, or combinations thereof (e.g., rotated by both drillstring 30 and mud motor 33). In either case, the rate-of-penetration (ROP) of the drill bit 100 into the borehole 11 for a given formation and a drilling assembly largely depends upon the WOB and the rotational speed of bit 100. During drilling operations a mud system 40 circulates pressurized drilling fluid or mud 41 down the drill string 30, through nozzles in the face of bit 100, and back up the annulus 42 between the drill string 30 and sidewall 11a of borehole 11.
As drill bit 100 and drill string 30 penetrate deeper into formation 12, casing 60 is installed within borehole 11 to ensure the structural integrity thereof as well as to limit/prevent fluid communication between formation 12 and borehole 11. Casing 60 includes an inner diameter D60 which defines the maximum outer diameter for any tool (e.g., bit 100) passing through wellbore 11. However, for some operations, it may become desirable to drill a larger diameter section of borehole 11 below casing 60 (i.e., to a diameter larger than inner diameter D60). As previously described, tripping the drill bit 100 to the surface to install a different bit (e.g., an eccentric bit capable of passing through casing 60 and drilling the larger diameter borehole) is generally undesirable. Thus, embodiments disclosed herein include downhole tools such as, for example, a drill bit (e.g., drill bit 100) that include a radially extendable member capable of selective radial retraction/extension to enable passage through the casing 60 as well as drilling selectively large or small sections of borehole 11 without needing to trip the bit to the surface.
Referring now to FIGS. 2 and 3, drill bit 100 of drilling system 10 is shown. Bit 100 has a central axis 105 (which is coaxially aligned with axis 35 of drill string 30 during operations), a first or uphole end 100a coupled to BHA 32 (see FIG. 1), and a second or downhole end 100b opposite uphole end 100a. Bit 100 rotates about axis 105, and thus, axis 105 may also be referred to as a “rotational” axis. Downhole end 100b engages the formation 12 during drilling operations to form borehole 11. In this embodiment, bit 100 is a bi-center bit configured to drill or form a borehole (e.g., borehole 11) with sections having different diameters. In this embodiment, bit 100 includes a bit body 140, a connection sub 120, an inner mandrel 170, and a radially extendable cutting blade or member 160.
Referring still to FIGS. 2 and 3, bit body 140 is an elongate generally cylindrical member having a first or uphole end 140a, a second or downhole end 140b defining downhole end 100b of bit 100, a female connection receptacle 142 (e.g., box end) at uphole end 140a, and an inner cavity or flow passage 148 extending axially from receptacle 142. Receptacle 142 includes an internally threaded inner surface 143 extending axially from uphole end 140a and an annular planar shoulder 144 extending radially inward from surface 143. Flow passage 148 is defined by a cylindrical surface 149 that extends axially from annular shoulder 144 toward, but not to, downhole end 140b. An aperture or opening 146 extends radially inward from a radially outer surface 141 of body 140 to cylindrical surface 149. As will be described in more detail below, extendable member 160 is disposed in opening 146 and slidingly engages body 140 such that member 160 can be moved radially relative to body 140 between a radially withdrawn or retracted position (FIG. 7) and a radially expanded or extended position (FIG. 8).
Referring again to FIGS. 2 and 3, a cutting structure 150 is disposed on downhole end 140b and is configured to engage with formation 12 during drilling operations. In this embodiment, cutting structure 150 is a fixed cutter bit arrangement that includes a plurality of cutter elements 152 mounted on downhole end 140b and arranged in a plurality of circumferentially spaced rows such that when bit 100 is rotated about axis 105 along a cutting direction 153, each cutter element 152 engages with and shears portions of formation 12, thereby forming and/or lengthening borehole 11 along a projection of axis 105. Drilling fluid (e.g., drilling mud) is circulated or flowed through central flow passage 148, through a plurality of nozzles 154 (note: only one nozzle 154 is shown in FIG. 3) extending axially from passage 148, and out downhole end 140b of bit body 140 to lubricate cutter elements 152, flush formation cuttings back to the surface through the annulus 42 (FIG. 1), and cool bit 100.
As is best shown in FIG. 2, in this embodiment, a plurality of fixed cutting members or blades 162 extend radially outward from surface 141 of body 140. Each fixed cutting member 162 is axially positioned between cutting structure 150 and receptacle 142. In addition, each member 162 includes a radially inner end 162a integral with bit body 140 and a radially outer end 162b radially spaced from outer surface 141. Outer end 162b is configured to engage with sidewall 11a of borehole 11 during drilling operations to enlarge the diameter of borehole 11 from that initially formed by cutting structure 150. Each member 162 has a height H162 measured radially between ends 162a, 162b. In this embodiment, each member 162 has a different height H162, such that one or more of the fixed members 162 are radially longer than the other fixed members 162. In this embodiment, a plurality of cutter elements 152 are mounted to end 162b of each member 162 such that when bit 100 is rotated along cutting direction 153, each cutter element 152 engages with and shears off portions of sidewall 11a to radially widen borehole 11.
Referring again to FIGS. 2 and 3, connection sub 120 is a tubular member that connects bit 100 to BHA 32. In particular, connection sub 120 has a first or uphole end 120a defining uphole end 100a of bit 100, a downhole end 120b, a radially outer surface 127 extending axially between ends 120a, 120b, and a radially inner surface 121 extending axially between ends 120a, 120b Inner surface 121 defines a central flow passage 122 extending axially through sub 120 and includes a cylindrical section 121a extending axially from end 120b and an annular planar shoulder 121b proximal uphole end 120a. An externally threaded male connector 124 (e.g., pin end) is disposed at uphole end 120a and threadably engages a mating internally threaded receptacle (e.g., box end) at the lower end of BHA 32 to connect sub 120 and BHA 32. An externally threaded male connector 128 (e.g., pin end) extends axially from downhole end 120b and threadably engages mating internally threaded receptacle 142 at upper end 140a of bit body 140 to connect sub 120 and bit body 140. Also, outer surface 127 includes an annular planar shoulder 125 that axially abuts end 140a.
Referring now to FIGS. 3 and 4, mandrel 170 is an elongate tubular member that includes a first or uphole end 170a, a second or downhole end 170b, a radially outer surface 176 extending axially between ends 170a, 170b, and a radially inner cylindrical surface 173 extending axially between ends 170a, 170b. Inner surface 173 defines a through passage 172 extending axially between ends 170a, 170b. Inner surface 173 has a uniform inner radius between ends 170a, 170b, however, the outer radius of outer surface 176 varies between ends 170a, 170b. In particular, as is best shown in FIG. 4, outer surface 176 has a first or upper cylindrical section 171 extending axially from end 170a, a second or lower cylindrical section 175 extending axially from end 170b, and an inclined transition section 177 extending axially between sections 171, 175 and oriented at an angle α (see FIG. 6) with respect to the axis 105. In this embodiment, inclined transition section 177 is an annular frustoconical surface. In addition, in this embodiment angle α is an acute angle and preferably ranges from 5° to 25°, and more preferably is approximately 10°. Further, upper section 171 of surface 176 is disposed at a radius that is greater than the radius of lower section 175.
As is best shown in FIG. 3, downhole end 170b comprises an annular planar end face 180 that extends radially between radially surfaces 173, 176. End face 180 has a surface area SA180. As is best shown in FIG. 4, uphole end 170a comprises an annular planar end face 181 that extends radially between surfaces 173, 176. End face 181 has a surface area SA181 that is smaller than surface area SA180.
Referring still to FIGS. 3 and 4, during assembly of bit 100, lower section 175 of mandrel 170 slidingly engages surface 149 of flow passage 148 within bit body 140 while upper section 171 slidingly engages surface 121a of flow passage 122 within connector sub 120. In addition, mandrel 170 is oriented within passages 148, 122 such that uphole end 170a is proximate uphole end 100a and downhole end 170b is proximate downhole end 100b of bit 100. Further a first or upper annular seal gland 179′ extends radially inward from surface 176 on upper section 171, while a second or lower annular seal gland 179″ extends radially inward from surface 176 on lower section 175. As will be described in more detail below, each seal gland 179′, 179″ houses a corresponding sealing member (e.g., an O-Ring) (not shown) configured to restrict fluid flow between radially outer surfaces 174, 176, respectively, of mandrel 170 and surfaces 122, 149, respectively, when mandrel 170 is installed within flow passages 148, 122 in the manner described.
As best shown in FIG. 3, a biasing member 130 is disposed within flow passage 122 of connection sub 120 between end 170a of mandrel 170 and shoulder 121. In particular, biasing member 130 has a first or uphole end 130a seated against shoulder 121 and a second or downhole end 130b axially abutting end 170a. Biasing member 130 is compressed between shoulder 121 and end 170a, and thus, biases mandrel 170 axially downward toward end 100b of bit 100. In general, biasing member 130 can be any suitable member for axially biasing one component relative to another component along a central axis (e.g., axis 105) while still complying with the principles disclosed herein, such as, for example, a coiled spring, Bellville washers, etc. In this embodiment, biasing member 130 is a coiled spring.
Referring now to FIGS. 2, 3, and 5, extendable cutting member 160 is moveably disposed within opening 146 of bit body 140 and includes a first or radially inner end 160a with respect to axis 105 (see FIG. 3), a second or radially outer end 160b with respect to axis 105, a pair of laterally opposed side walls 164 extending radially between ends 160a, 160b with respect to axis 105, and a pair of axially opposed side walls 163 extending radially between ends 160a, 160b with respect to axis 105. As will be described in more detail below, each wall 164, 163 slidingly engages one of the surfaces defining opening 146 on bit body 140 as member 160 is radially extended from and refracted within opening 146.
In this embodiment, radially outer end 160a includes a pair of circumferentially-spaced parallel blades 166 configured to engage formation 12 during drilling operations to radially enlarge borehole 11 to a desired diameter greater than that formed by cutting structure 150. Each blade 166 includes a formation facing surface 168 and a plurality of cutter elements 152 as previously described mounted to surface 168. When bit 100 is rotated about axis 105 in cutting direction 153, cutter elements 152 on member 160 may engage with and shear off portions of sidewall 11a of borehole 11.
Referring now to FIGS. 5 and 6, inner end 160a includes a recess 165 extending axially between opposed axial walls 163 with respect to axis 105 (see FIG. 3). Recess 165 is defined by a cylindrical surface 167 extending from uphole wall 163 and an inclined surface 169 extending from downhole wall 163 to cylindrical surface 167 and oriented at an angle β (see FIG. 7) with respect to axis 105. In this embodiment surface 169 is a frustoconical surface. As shown in FIG. 3, during assembly, member 160 is installed within opening 146 in bit body 140 such that recess 165 forms a portion of the flow passage 148 extending through bit body 140. Cylindrical surface 167 is sized to slidingly engage mating sections 171, 175 on mandrel 170 and frustoconical surface 169 is sized to slidingly engage mating frustoconical transition section 177. Referring briefly to FIG. 7, in this embodiment, the angle β is an acute angle and is the same as the angle α of transition section 177 of mandrel 170 previously described. However, it should be appreciated that in other embodiments, the angle β is different than the angle α while still complying with the principles disclosed herein.
Referring now to FIGS. 7 and 8, during drilling operations, drilling fluids (e.g., drilling mud) are circulated through bit 100 from uphole end 100a to downhole end 100b as previously described. In particular, drilling fluid enters bit 100 at uphole end 100a and flows through flow passage 122 of sub 120, throughbore 172 of mandrel 170, flow passage 148 of bit body 140, and finally through nozzles 154 and out downhole end 100b proximate cutting structure 150. As drilling fluids flow through bit 100 as described, biasing member 130 engages annular shoulder 121 within flow passage 122 and uphole end 170a of mandrel 170 with ends 130a, 130b, respectively, to bias mandrel 170 toward downhole end 100b and away from uphole end 100a.
During operations, cutting member 160 may be transitioned between a first or radially retracted position, such as shown in FIG. 7, and a second or radially expanded position, such as shown in FIG. 8. In particular, while in the radially retracted position (e.g., FIG. 7), mandrel 170 is biased toward downhole end 100b such that frustoconical transition section 177 of mandrel 170 is received within recess 165 of extendable member 160 and abuts frustoconical surface 169 of recess 165.
When it becomes desirable to transition member 160 of bit 100 to the radially expanded position (e.g., FIG. 8), the pressure of the drilling fluids flowing through flow passage 122, throughbore 172, and flow passage 148 is increased to cause mandrel 170 to translate axially in a first direction 190 toward uphole end 100a of bit 100. In particular, the pressure of drilling fluid flowing through bit 100 is increased such that the pressure exerted on end face 180 on downhole end 170b of mandrel 170 by the drilling fluid is larger than the combined force exerted on uphole end 170a by biasing member 130 and the pressure exerted on end face 181 on uphole end 170a by drilling fluids within the passage 122. In this embodiment, the surface areas SA180, SA181 of surfaces 180, 181, respectively, on ends 170b, 170a, respectively, of mandrel 170 are each relatively sized such that a given and previously determined pressure, P, applied to end face 180 will be sufficient to overcome the combined forces of that same given pressure, P, on end face 181 by the drilling fluid and the biasing force supplied by biasing member 130 such that mandrel 170 translates in the first direction 190, toward uphole end 100a. For example, in this embodiment, the surface area SA180 is larger than the surface area SA181. As mandrel 170 translates within flow passages 148, 122 in the first direction 190, frustoconical transition section 177 slidingly engages frustoconical surface 169 within recess 165, thereby radially extending member 160 from opening 146. Eventually, as mandrel 170 continues to translate in the first direction 190 toward uphole end 100a, frustoconical transition section 177 translates axially past frustoconical surface 169 and lower section 175 slidingly engages cylindrical surface 167 within recess 165 thereby camming member 160 radially outward to a maximum radially extended position. In at least some embodiments, the pressure of the drilling fluid flowing through bit 100 is increased to cause translation of mandrel 170 in the first direction 190 toward uphole end 100a in the manner described by engaging downhole end 100b of bit 100 with the axial bottom of borehole 11 such that the outflow of drilling fluid from nozzles 154 is at least partially restricted (thereby resulting in a subsequent buildup of pressure within bit 100).
When it becomes desirable to transition member 160 of bit 100 back to the radially retracted position (e.g., FIG. 7), the pressure of the drilling fluids flowing through passage 122, through 172, and flow passage 148 is decreased to cause mandrel 170 to translate axially in a second direction 191, toward downhole end 100b of bit 100. In particular, the pressure of drilling fluid flowing through bit 100 is decreased such that the pressure exerted on end face 180 on end 170b of mandrel 170 by the drilling fluid is smaller than the combination of the force exerted on uphole end 170a by biasing member 130 and the pressure exerted end face 181 on uphole end 170a by drilling fluids within the passage 122. Once the pressure of the drilling fluid is sufficiently decreased to achieve the above described balance of forces, mandrel 170 translates within flow passages 148, 122 in the second direction 191 toward downhole end 100b, such that frustoconical surfaces 177, 169 once again engage one another and extendable member 160 is allowed to radially retract back within opening 146. In some embodiments, member 160 is biased radially inward within opening 146 to ensure that member 160 defaults to the radially retracted position in the event of a loss of power or fluid flow to bit 100. In this way, operators can ensure that bit 100 can be withdrawn back to the surface through casing 60 in spite of such a failure.
In this embodiment, with member 160 in the radially retracted position (e.g., FIG. 7), bit 100 has a maximum outer diameter DR measured radially between radially outer end 162b of the longest one of the fixed members 162 (i.e., end 162b of one of the fixed members 162 having the greatest height H162) and a point that is radially opposite that member 162 along radially outer surface 141 with respect to axis 150. In addition, with member 160 in the radially expanded position (e.g., FIG. 8), bit 100 has a maximum outer diameter DE that is measured radially between radially outer end 160b of extendable member 160 and a point that is radially opposite member 160 along radially outer surface 141. As shown, diameter DE is greater than diameter DR. Thus, when with member 160 is in the radially retracted position (e.g., FIG. 7), bit 100 may be passed through a tubular or structure having an inner diameter (e.g., diameter D60 of casing 60) equal to or greater than either DR or DE, and when member 160 is the radially expanded position (e.g., FIG. 8), bit 100 may be passed through a structure having an inner diameter equal to or greater than DE only.
Further, with member 160 in the radially retracted position (e.g., FIG. 7), bit 100 has a maximum radius RR measured radially from radially outer end 162b of the longest one of the fixed members 162 to axis 105. In addition, with member 160 in the radially expanded position (e.g., FIG. 8), bit 100 has a maximum radius RE measured radially from radially outer end 160b of member 160 to axis 105. The maximum radii RR, RE each determine the maximum diameter hole (e.g., borehole 11) that can be formed by bit 100 while member 160 is in the respective position. In particular, the maximum diameter borehole that can be formed by bit 100 with member 160 in the radially retracted position (e.g., FIG. 7) is equal to two times radius RR while the maximum diameter borehole that can be formed by bit 100 with member 160 in the radially expanded position (e.g., FIG. 8) is equal to two times RE. As shown in FIGS. 7 and 8, RE is greater than RR, and thus, the resulting borehole diameter formed by bit 100 with member 160 in the radially retracted position (e.g., 2*RR) is less than the resulting borehole diameter formed by bit 100 with member 160 in the radially expanded position (e.g., 2*RE). It should be appreciated that diameters DR, DE, and radiuses RR, RE are ultimately defined between the radially outermost extending portions of cutter elements 152 that are disposed along the relevant members 160, 162, since it is these cutter elements 152 that will first engage with formation 12 during operations.
In the manner described, a drill bit (or other downhole tool) in accordance with the principles disclosed herein (e.g., drill bit 100) may be disposed on a downhole end of a drill string (e.g., drill string 30) and selectively radially retracted so that the bit may be passed through a relatively narrow casing (e.g., casing 60) and selectively radially expanded to allow the bit to form a borehole having a diameter that is larger than the inner diameter of the casing. In addition, through use of a drill bit in accordance with the principles disclosed herein (e.g., bit 100), selectively smaller/larger diameter boreholes (e.g., borehole 11) may be formed without needing to trip the bit and drill string to the surface. Still further, because member 160 is incorporated within a relatively small downhole tool (e.g., bit 100), the utilization of drill bits and/or downhole tools in accordance with the principles disclosed herein may be more easily utilized in directional drilling applications.
While embodiments disclosed herein have included a drill bit 100, it should be appreciated that the principles disclosed herein may be utilized on other downhole tools. For example, referring now to FIG. 9, an embodiment of a downhole tool 200 is shown. In this embodiment, tool 200 is a reaming tool designed to enlarge (i.e., widen) a borehole (e.g., borehole 11) that was initially formed by a drill bit. Tool 200 generally includes a central or longitudinal axis 205, a first or uphole end 200a, a second or downhole end 200b opposite uphole end 200a, and a tool body 240. In addition, tool 200 includes connection sub 120, inner mandrel 170, and extendable cutting member or blade 160, each being the same as previously described above. Moreover, tool body 240 is substantially the same as the bit body 140 previously described, except that tool body 240 does not include cutting structure 150 and nozzles 154, and instead includes a female connector 242. In this embodiment, female connector 242 is a box threaded connector that is configured to threadably engage with a corresponding pin-end connector on a tubular member or other downhole tool (e.g., a drill bit). During operations, tool 200 functions in substantially the same manner as bit 100 to radially translate or extend member 160 from opening 146, and thus, a detailed description of this operation is omitted for conciseness.
While embodiments disclosed herein have shown drill bit 100 coupled to downhole end 30b of drill string 30, it should be appreciated that in other embodiments, drill bit 100 may be coupled to any suitable conduit for suspending a drilling bit within a subterranean wellbore during drilling operations, such as, for example, coiled tubing. In addition, while embodiments disclosed herein have included a plurality of fixed members 162 on bit 100, it should be appreciated that in other embodiments no fixed members 162 are included or only a single member 162 is included on bit 100 while still complying with the principles disclosed herein. Also, in some embodiments, each of the fixed members 162 may have the same or different heights H162.
While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.
Patent Application
20150300093
