CN111894471A

CN111894471A - Drill bit with through extending channel and manufacturing method thereof

Info

Publication number: CN111894471A
Application number: CN201910369849.9A
Authority: CN
Inventors: 王巍雄; 罗江河; 文磊
Original assignee: Seed Technologies Corp Ltd
Current assignee: Seed Technologies Corp Ltd
Priority date: 2019-05-06
Filing date: 2019-05-06
Publication date: 2020-11-06

Abstract

The invention relates to a drill bit with a through extending channel and a manufacturing method thereof. A drill bit for drilling a wellbore in an earthen formation has a central axis and a cutting rotational direction about the central axis. The drill bit includes a bit body having a bit face. Additionally, the drill bit includes a blade disposed on the bit face. Further, the drill bit includes a bore extending axially into the bit body. Still further, the drill bit includes a flow passage extending from the bore through the bit body to the bit face. The flow passage is configured to supply drilling fluid to the bit face. The drill bit also includes a channel extending from the flow channel to the blade.

Description

Drill bit with through extending channel and manufacturing method thereof

Cross Reference to Related Applications

Not applicable to

Statement regarding federally sponsored research or development

Not applicable to

Technical Field

The present disclosure relates generally to drill bits for drilling wellbores in earthen formations for the ultimate retrieval of oil, gas, or minerals. More particularly, the present disclosure relates to fixed cutter bits (fixed cutter bits) that include channels that extend to selected cutter elements, and to additive manufacturing methods for manufacturing such bits.

Background

An earth-boring drill bit is disposed at a lower end of a drill string and is rotated relative to a formation by an applied Weight On Bit (WOB) to drill a wellbore through the formation along a predetermined path. The diameter of the wellbore is equal to the diameter or "gauge" of the drill bit used to form the wellbore.

Two common types of drill bits used for drilling earthen formations include fixed cutter or rotary drag bits and roller cone bits. Fixed cutter drill bits include a plurality of circumferentially spaced blades arranged along the bit face. A plurality of cutting tooth elements are mounted on each blade. The number and arrangement of cutter elements can vary depending on various factors, including the type of formation being drilled.

The cutter elements mounted to the blade are formed of an extremely hard material. Typically, each cutter element includes an elongated, generally cylindrical tungsten carbide support member and a hard layer of polycrystalline diamond or other superabrasive material mounted to one end of the support member. The support member is received and secured in a pocket or recess formed in a surface of the insert.

During drilling operations, the drill bit is rotated from the surface by the drill string and/or by a downhole motor while drilling fluid is pumped down the drill string and directed out of the face of the drill bit. In particular, nozzles along the face of the bit between the blades eject drilling fluid that removes formation cuttings from the cutting structures (e.g., cutter elements), removes cut formation material from the bottom of the wellbore, and removes heat caused by contact between the bit and the formation. The drilling fluid exits the bit face via the nozzles and flows back to the surface via the annulus (annuus) between the drill string and the sidewall of the wellbore. The drilling fluid carries formation cuttings to the surface, thereby circulating the cuttings out of the wellbore to avoid the accumulation of cuttings (which may reduce drilling of the cutting structure into the formation and increase wear of the cutting tooth elements). Removing heat through the drilling fluid also extends the life of the cutter elements.

Disclosure of Invention

Embodiments of a drill bit for drilling a wellbore in an earthen formation are described herein. In one embodiment, the drill bit has a central axis and a cutting rotational direction about the central axis. Additionally, the drill bit includes a bit body having a bit face. Further, the drill bit includes a blade disposed on the bit face. Still further, the drill bit includes a bore extending axially into the bit body. Further, the drill bit includes a flow passage extending from the bore through the bit body to the bit face. The flow passage is configured to supply drilling fluid to the bit face. The drill bit also includes a channel extending from the flow channel to the blade.

In another embodiment, a drill bit for drilling a wellbore in an earthen formation has a central axis and a cutting rotational direction about the central axis. Additionally, the drill bit includes a bit body having a bit face. Further, the drill bit includes a plurality of circumferentially spaced apart primary blades disposed on the bit face. Each primary blade begins substantially adjacent the central axis and extends through the conical region and the shoulder region of the drill bit. Still further, the drill bit includes a plurality of primary cutter elements mounted on each primary blade. The primary cutter elements on each primary blade are arranged in an extended row and extend through the cone region and shoulder region of the drill bit. Further, the drill bit includes a plurality of drilling fluid flow channels extending through the bit body to the bit face. The drill bit also includes a plurality of channels. Each channel extends from one flow passage through at least a portion of one of the drill bit bodies and one of the primary blades.

The embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain existing devices, systems, and methods. The foregoing has outlined rather broadly the features and technical advantages of the present invention in order that the detailed description of the invention that follows may be better understood. The various features 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 specific embodiment disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the present 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.

Drawings

For a detailed description of preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:

FIG. 1 is a perspective view of an embodiment of a fixed cutter drill bit made according to the principles described herein.

FIG. 2 is an end view of the drill bit of FIG. 1 showing the bit face;

FIG. 3 is a side view of the drill bit of FIG. 1;

FIG. 4 is a cross-sectional side view of the drill bit of FIG. 1 showing an exemplary primary blade;

FIG. 5 is a schematic cross-sectional view of the drill bit of FIG. 1, wherein the blades and cutter elements of the drill bit are rotated to a single profile;

FIG. 6 is an enlarged view of an exemplary insert of the drill bit of FIG. 1;

FIG. 7 is a fragmentary, perspective view of the drill bit of FIG. 1 illustrating a drilling fluid distribution system extending therethrough;

FIG. 8 is a partially broken away perspective view of the drill bit of FIG. 1 illustrating the primary hydraulic system of the drilling fluid distribution system;

FIG. 9 is a fragmentary, perspective view of the drill bit of FIG. 1 illustrating a secondary hydraulic system of the drilling fluid distribution system;

FIG. 10 is an enlarged partial schematic view of the inlet end of one of the channels of the drill bit of FIG. 1; and is

FIG. 11 is a partial enlarged view of an embodiment of a drill bit including sensors on a leading face of an exemplary blade.

Detailed Description

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 the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to intimate 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. Those skilled in the art will appreciate that 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 drawings 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 the interest of clarity and conciseness.

In the following discussion and claims, the terms "include …" and "include …" are used in an open-ended fashion, and thus should be interpreted to mean "include, but not limited to …". Also, the terms "couple" or "couples" are 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. Further, as used herein, the terms "axial" and "axially" generally mean along or parallel to a central axis (e.g., the central axis of a body or portion), while the terms "radial" and "radially" generally mean perpendicular to the central axis. For example, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance refers to a distance measured perpendicular to the central axis. Still further, as used herein, the term "component" may be used to refer to a continuous single piece or unitary structure, portion, or device. It should be understood that the components may be used alone or as part of a larger system or assembly.

During drilling operations, the drill bit is subjected to extreme wear, impact loads, and thermal stresses. In some cases, the drill bit may also be exposed to corrosive fluids. As a result, the drill bit may experience severe wear, erosion, and physical damage while drilling. For example, the bit body may chip or fracture due to impact with hard formations and rock. Sufficient damage to the drill bit may adversely reduce its cutting efficiency and rate of penetration (ROP). In such a case, it may be necessary to replace the drill bit by pulling the entire drill string (which may be thousands of feet long) section by section from the wellbore. Once the drill string is tripped out and a new bit is installed, the bit must be lowered on the drill string to the bottom of the wellbore, which in turn must be set up section by section. This process (known as "tripping" of the drill string) requires considerable time, effort and expense. Regardless of the type of drill bit, the cost of drilling a wellbore is directly related to the length of time it takes to drill to the desired depth and location. Thus, it is desirable to maximize the durability of drill bits so that they can drill faster and longer over a wider range of formation hardnesses.

Fixed cutter drill bits are typically made from a hard metal cast matrix. In particular, the matrix bit body is formed by a powder metallurgy process in which powdered tungsten carbide and a binder material such as Cu-Ni-Mn-Zn, Cu-Zn, or Cu-Ni-Mn-Sn are placed in a carbon/graphite mold. Typically, the powder material (i.e., tungsten carbide and binder) placed in the mold has a composition comprising 50 to 80 wt% tungsten carbide and 20 to 50 wt% binder. The mold is then heated in a furnace to a temperature greater than 2,000 ° F (greater than 1,100 ℃) for about 1 hour to allow the binder material to infiltrate the tungsten carbide and form a solid metal matrix bit body. Next, the mold in which the metal matrix bit body is disposed is directionally cooled to room temperature, and then removed from the bit body by crushing, carving, and grinding the mold. This process of manufacturing a metal matrix bit body may take more than 24 hours to perform.

Drill bits made from hard metal cast matrix materials have been the focus of much research and development aimed at improving impact strength, wear resistance and corrosion resistance. As noted above, the powder metallurgy processes typically used to produce such metal matrix bit bodies employ a powder mixture of a binder material and tungsten carbide. The powder mixture is pressed or injected into a mold and then sintered into the final product. Due to the use of dies, the limited flow capability of the powder mixture, and other limitations, it is difficult to produce parts having complex shapes using conventional powder metallurgy manufacturing processes. In addition, components produced using such conventional powder metallurgy manufacturing processes may include defects or develop cracks due to uneven heating during sintering or uneven cooling after sintering. These defects and cracks may adversely reduce the wear resistance, erosion resistance, corrosion resistance and impact strength of the produced parts.

As will be described in greater detail below, embodiments of drill bits made by additive manufacturing processes offer the potential for more tailored complex shapes and geometries, including channels for supplying drilling fluid to selected individual cutter elements to enhance bit durability. Additionally, embodiments of drill bits made from metal matrix composite compositions (composite compositions) and manufactured by additive manufacturing processes offer the potential for materials and components with enhanced impact strength, wear resistance, erosion resistance, corrosion resistance, and working life.

Embodiments of drill bits described herein may be manufactured using electron beam additive manufacturing techniques (also referred to as "electron beam melting" or simply "EBM"). Generally, the EBM additive manufacturing process is a 3D printing technique that consolidates layer-by-layer into a solid mass by controlled and selective melting of metal powders using an electron beam as a heat source, producing dense metal (or metal matrix composite) parts. The EBM additive manufacturing process is performed in and controlled by an EBM machine, which reads data from the 3D CAD model, lays successive layers of powder metal, and melts each successive layer (one layer at a time) with an electron beam to build (i.e., "print") the metal part layer by layer. Each layer is melted into the exact geometry defined by the 3D CAD model, thus enabling the production of parts with very complex geometries without the need for tools, jigs or molds and without any scrap. The EBM additive manufacturing process is performed under vacuum (i.e., at a pressure below atmospheric pressure) to enable the use of metals and materials (e.g., titanium) that have a high affinity for oxygen and are used at high temperatures. Examples of EBM machines capable of performing EBM manufacturing processes include, but are not limited to, Arcam A2X, Arcam Q10, Arcam Q20, and Arcam spec H, each available from Arcam AB company, moindale, sweden.

Referring to fig. 1-3, an embodiment of a fixed cutter drill bit 100 for drilling through a rock formation to form a wellbore is shown. The drill bit 100 has a central or longitudinal axis 105, a first or uphole end 100a, and a second or downhole end 100b opposite the end 100 a. In addition, the drill bit 100 includes a bit body 110 proximate the end 100b, a shank 113 axially adjacent the body 110, and a threaded connection or pin 14 axially adjacent the shank 113. More specifically, the pin member 14 extends axially from the end 100a to a shank 113, the shank 113 extending axially from the pin member 14 to the body 110. The pin member 14 connects the drill bit 100 to a drill string (not shown) for rotating the drill bit 100 about an axis 105 in a cutting direction 118. Additionally, the bit body 110 defines a bit face 120, the bit face 120 supporting a cutting structure 130 extending to the end 100 b. As will be described in more detail below and best shown in fig. 4 and 7, the drill bit 100 includes a drilling fluid distribution system 150 (fig. 7), the drilling fluid distribution system 150 extending from the end 100a through the pin 114, the shank 113, and the body 110 to the bit face 120 and the cutting structure 130. The fluid distribution system 150 allows drilling fluid to flow from the drill string into the drill bit 100 and out the proximal end 100b of the drill bit 100 to distribute the drilling fluid around the cutting structure 130 to flush away formation cuttings and remove heat from the drill bit 100 during drilling.

Referring again to fig. 1-3, the cutting structure 130 includes a plurality of circumferentially spaced blades extending from the bit face 120. In the embodiment shown in fig. 1-3, the cutting structure 130 includes three angularly spaced

primary blades

131, 132, 133 and three angularly spaced

secondary blades

134, 135, 136. In particular, in the present embodiment, the plurality of inserts are substantially evenly spaced (e.g., about 60 ° apart) about the bit face 120. In addition, one

secondary insert

134, 135, 136 is positioned circumferentially between each pair of circumferentially adjacent

primary inserts

131, 132, 133. In other embodiments, the blades may be non-uniformly spaced about the bit face, the number of primary blades may vary, the number of secondary blades may vary, or a combination of these variations may be employed.

Primary blades

131, 132, 133 and

secondary blades

134, 135, 136 extend radially on bit face 120 and longitudinally along a portion of the outer circumference of bit 100. The

primary blades

131, 132, 133 extend radially from the generally proximal central axis 105 to the outer periphery of the drill bit 100. Thus, as used herein, the term "primary blade" is used to describe a blade that extends from substantially the proximal central axis 105.

Secondary blades

134, 135, 136 do not extend from substantially proximal central axis 105. As best seen in fig. 2, the

secondary blades

134, 135, 136 extend radially from a location at a radial distance from the central axis 105 to the outer periphery of the drill bit 100. Thus, the

primary blades

131, 132, 133 extend closer to the central axis 105 than the

secondary blades

134, 135, 136. Thus, as used herein, the term "secondary blade" is used to describe a blade that does not extend from the generally proximal central axis 105.

Primary blades

131, 132, 133 and

secondary blades

134, 135, 136 are separated by junk slots or valleys 137, which junk slots or valleys 137 define a drilling fluid flow path along bit face 120.

Each

blade

131, 132, 133, 134, 135, 136 includes a leading or front face 140 relative to the bit rotational direction 118, a trailing or rear face 141 relative to the bit rotational direction 118, and a tooth support surface 142 extending circumferentially between the

faces

140, 141. The front face 140 and the rear face 141 generally extend axially from the bit face 120 and radially from the outer periphery of the bit body 110. The surfaces 142 are oriented substantially perpendicular to the respective faces 140, 141. As will be described in greater detail below, a plurality of cutter elements are mounted to a surface 142 of each

blade

131, 132, 133, 134, 135, 136.

In the present embodiment, the

primary blades

131, 132, 133 and the

secondary blades

134, 135, 136 are integrally formed as part of the bit body 110 and the bit face 120 and extend from the bit body 110 and the bit face 120. Specifically, the bit body 110 and the

blades

131, 132, 133, 134, 135, 136 are made from a metal matrix composite composition by an EBM additive manufacturing process. Examples of suitable metal matrix composite compositions and EBM additive manufacturing processes that can be used to make the embodiments described herein (e.g., bit body 110 and inserts 131, 132, 133, 134, 135, 136) are disclosed in PCT patent application No. PCT/CN2016/080123 filed 4-25/2016, which is incorporated herein by reference in its entirety.

As described above, drill bits made from metal matrix composite compositions via additive manufacturing processes (e.g., EBM additive manufacturing processes) offer the potential for enhanced impact strength (toughness) as compared to conventional hard metal cast matrix drill bits. In particular, conventional hard metal cast matrix bits are relatively brittle.

Thus, the high insert design with conventional hard metal cast matrix bits has a high risk of breakage. In addition, the high insert design in conventional hard metal cast matrix bits causes high residual stresses because the shrinkage and expansion of the composition can fluctuate within the mold depending on environmental conditions (e.g., humidity, moisture in graphite and powder materials, compactness of powder materials, different shrinkage and expansion rates within the billet, and element enriched areas). Such stresses are typically relieved in the blades after penetrating thermal cycles (e.g., welding, brazing, etc.), causing the drill bit to crack along the shoulder region (typically between the nozzle openings, between the cutter element pocket and the blade root), or may crack during operation and maintenance, causing a reduction in the life of the drill bit. However, the use of a controlled vacuum chamber environment employed in the EBM additive manufacturing process (which eliminates graphite molds, billet and graphite or sand core assembly components and adhesives) reduces and/or alleviates this problem. Furthermore, the layer-by-layer construction achieved by additive manufacturing provides a more uniform and consistent distribution of material elements, as well as advanced material toughness properties. Thus, embodiments described herein may include blades (e.g.,

blades

131, 132, 133, 134, 135, 136) that extend farther (both radially and longitudinally) from the bit body than blades on similarly sized bits made from a hard metal cast matrix in a conventional manner. For example, as best shown in fig. 2, each

blade

131, 132, 133, 134, 135, 136 has a corresponding blade in end viewAnd a circumferential width W measured circumferentially between

faces

140, 141 and substantially parallel to the bit rotational direction 118_blade(ii) a And as best shown in fig. 4, each

blade

131, 132, 133, 134, 135, 136 has a height H in side view measured perpendicularly from the respective cutter support surface 142 to the bit face 120_blade. As shown in FIG. 2, the width W of each

blade

131, 132, 133, 134, 135, 136_bladeAll varying with radial movement along

blades

131, 132, 133, 134, 135, 136, and as best shown in fig. 4, the height H of each

blade

131, 132, 133, 134, 135, 136_bladeAll varying with radial movement along the

blades

131, 132, 133, 134, 135, 136.

To compare the relative heights of inserts (which may be of similar or different sizes) on different bits, the insert height H may be compared_bladeWidth W of the blade_bladeIs compared (referred to herein as the "K" value or ratio of the blades) based on the following understanding: the greater the K ratio, the greater the blade height relative to its width. For clarity and consistency, the insert height H measured from the same point along the intersection of the leading end surface (e.g., surface 140) and the cutting tooth support surface (e.g., surface 142) is used_bladeAnd blade width W_bladeTo calculate the K ratio at any position along the blade. Due to the width W of the blade moving in the radial direction of the blade_bladeAnd/or height H_bladeIt should be understood that the K ratio may vary as one moves radially along the blade. In the embodiments described herein, the maximum K ratio of each

blade

131, 132, 133, 134, 135, 136 is greater than 1.1, and in some embodiments greater than 1.5, 1.8, or even greater than 2.0. In embodiments, the maximum K-ratio of each

blade

131, 132, 133, 134, 135, 136 can be as large as 1.5, 1.8, 2.0, or even 2.5. For conventional hard metal cast matrix bits, the maximum K-ratio per insert is typically less than about 1.1. Thus, embodiments described herein made from metal matrix composite compositions via additive manufacturing processes typically have relatively taller blades than most conventional hard metal cast matrix drill bits. Generally, comprises a toolDrill bits with blades (e.g.,

blades

131, 132, 133, 134, 135, 136) having relatively large K-ratios (large height/width ratios) provide larger junk slots (e.g., valleys 137), which advantageously allow for greater volumetric flow rates (drilling fluid and formation cuttings) through the junk slots.

Referring again to fig. 1-3, as described above, a plurality of cutting tooth elements are mounted to the surface 142 of each

blade

131, 132, 133, 134, 135, 136. More specifically, a plurality of leading or primary cutter elements 145 having cutting faces 146 are mounted to the surface 142 of each

blade

131, 132, 133, 134, 135, 136, and a plurality of trailing or backup cutter elements 147 having cutting faces 148 are mounted to the surface 142 of each

blade

131, 132, 133, 134, 135, 136. In other embodiments, backup cutter elements 147 may not be provided on one or more

primary blades

131, 132, 133 and/or one or more

secondary blades

134, 135, 136.

The primary cutter elements 145 are positioned generally side-by-side in a row extending radially along each

blade

131, 132, 133, 134, 135, 136 adjacent the respective leading face 140. In addition, backup cutter elements 147 are generally positioned side-by-side in a row extending radially along each

blade

131, 132, 133, 134, 135, 136. On each

blade

131, 132, 133, 134, 135, the row of backup cutter elements 147 is located behind the row of primary cutter elements 145 with respect to the bit rotational direction 118. Thus, as best seen in fig. 2, as the drill bit 100 rotates about the central axis 105 in the rotational direction 118, the backup cutter elements 147 trail the primary cutter elements 145 on the

same blades

131, 132, 133, 134, 135, 136. Thus, as used herein, the term "backup cutter element" is used to describe a cutter element that trails any other cutter element on the same blade as the drill bit 100 rotates in the rotational direction 118. Further, as used herein, the term "primary cutter element" is used to describe a cutter element located at or near the leading face (e.g., leading face 140) of the blade. Thus, the "primary cutter element" does not trail any other cutter elements on the same blade as the drill bit 100 rotates about the central axis 105 in the direction 118.

While the primary cutter elements 145 and backup cutter elements 147 are arranged in rows on the drill bit 100, it should be appreciated that in other embodiments, the cutter elements (e.g., primary cutter elements and/or backup cutter elements) may be mounted in other suitable arrangements. Examples of suitable arrangements may include, but are not limited to, an array or an organized pattern, a random sinusoidal pattern, or a combination thereof. Moreover, in other embodiments (not specifically shown), additional rows of cutting tooth elements may be provided on the primary blade, the secondary blade, or a combination thereof.

Referring now to fig. 1 and 3, the drill bit 100 also includes a plurality of circumferentially spaced apart metering pads (gage pads)138 of substantially equal length disposed about the circumference of the drill bit 100. Each metering shim 138 intersects with and extends from one

blade

131, 132, 133, 134, 135, 136. The metering shim 138 is integrally formed as part of the bit body 110 and the

blades

131, 132, 133, 134, 135, 136. Thus, the metering shim 138 is made from the metal matrix composite composition by an EBM additive manufacturing process. Each metering pad 138 includes a surface 139 that faces radially outward from the formation against the sidewall of the wellbore during drilling. Thus, the gauge pads 138 can help maintain the dimensions of the wellbore and help stabilize the drill bit 100 from vibration during drilling.

Referring to fig. 5, the profile of the drill bit 100 is shown as it would appear if all of the blades (e.g.,

blades

131, 132, 133, 134, 135, 136) and all of the cutting faces (e.g., cutter elements 146, 148) were rotated into a single rotational profile. As shown in fig. 5, in the rotational profile, the cutting tooth support surfaces 142 of the

blades

131, 132, 133, 134, 135, 136 define a blade profile 139, which blade profile 139 can be divided into three distinct regions — a taper region 139a, a shoulder region 139b, and a metering region 139 c. Tapered region 139a is concave in this embodiment and comprises the radially innermost region of bit 100 extending from axis 105. Shoulder region 139b is convex and is positioned radially adjacent to tapered region 139 a. The metering region 139c is radially adjacent the shoulder region 139b and defines the outer radius R of the drill bit 100. The outer radius R extends to and defines the full gage diameter of the drill bit 100.

Primary blades

131, 132, 133 extend from tapered region 139a to metering region 139c through shoulder region 139b, whereas

secondary blades

134, 135, 136 extend from shoulder region 139b to metering region 139 c. In other words, in the present embodiment, the

secondary blades

134, 135, 136 do not extend into the tapered region 139 a. Additionally, in the present embodiment, primary cutter elements 145 and associated cutting faces 146 are disposed in tapered region 139a, shoulder region 139b, and metering region 139c, whereas secondary cutter elements 147 and associated cutting faces 148 are disposed in shoulder region 139b and metering region 139c, but not in tapered region 139 a.

Each primary cutter element 145 and each backup cutter element 147 includes an elongated, generally cylindrical support member or base that is received and secured (e.g., via brazing) in a pocket formed in a surface 142 of the

insert

131, 132, 133, 134, 135, 136, to which the support member or base is secured. In addition, the cutting faces 146, 148 comprise forward facing disks, and a hard cutting layer of polycrystalline diamond or other superabrasive material is bonded to the exposed forward end (relative to the direction of rotation 118) of the support member.

In the embodiments described herein, cutting faces 146, 148 are forward facing, meaning that cutting faces 146, 148 are oriented substantially perpendicular to or at an acute angle relative to cutting direction 118 of drill bit 100. For example, forward facing cutting faces 146, 148 may be oriented substantially perpendicular to cutting direction 118 of drill bit 100, may include a trailing rake angle, and/or may include a side rake angle.

As noted above, embodiments of the drill bits described herein are made from metal matrix composite compositions via EBM additive manufacturing processes, and furthermore, such materials and manufacturing techniques generally enable the design and manufacture of more custom-tailored complex shapes and geometries. Accordingly, embodiments of the drill bits described herein (e.g., the drill bit 100) may include more custom-made complex drilling fluid distribution systems than most conventional drill bits made from hard metal cast matrices.

Referring now to fig. 4 and 7, in this embodiment, a drilling fluid distribution system 150 includes a central bore or plenum 151 extending axially into the body 110 from the end 110a through the pin 114 and shank 113, a primary hydraulic system 152 extending through the body 110 from the bore 151 to the bit face 120, and a secondary or supplemental hydraulic system 155 extending through the body 110 from the bore 151 to the

blades

131, 132, 133, 134, 135, 136. In fig. 7, a drilling fluid distribution system 150 is shown that includes both

systems

152, 155; in fig. 8, the orifice 151 and the primary hydraulic system 152 are shown, however, the supplemental hydraulic system 155 is not shown; also in fig. 9, the bore 151 and the supplemental hydraulic system 155 are shown, however, the main hydraulic system 152 is not shown.

As best shown in fig. 8, the primary hydraulic system 152 includes a plurality of circumferentially spaced flow passages 153 extending generally linearly from the bore 151 to the bit face 120. In particular, each flow channel 153 has a first or inlet end 153a at the bore 151 and a second or outlet end 153b at the bit face 120. In the present embodiment, each outlet end 153b is circumferentially disposed between a pair of circumferentially

adjacent blades

131, 132, 133, 134, 135, 136, and further, one outlet end 153b is provided between each pair of circumferentially

adjacent blades

131, 132, 133, 134, 135, 136. A port or nozzle 154 is disposed at the outlet end 153b of each flow channel 153 to direct the drilling fluid flowing from the bore 151 into each valley 137. During drilling operations, the channels 153 and nozzles 154 together distribute drilling fluid around the cutting structures 130 to flush away formation cuttings and remove heat from the drill bit 100.

As best shown in fig. 9, the supplemental hydraulic system 155 includes a plurality of circumferentially spaced curved flow channels 156 extending from the channel 153 adjacent the bore 151 and the inlet end 153a to the

blades

131, 132, 133, 134, 135, 136. In the present embodiment, each

blade

131, 132, 133, 134, 135, 136 includes a plurality of channel guides 157 that protrude from the front face 140 of the

blade

131, 132, 133, 134, 135, 136 to receive and house a downstream portion of the respective channel 156. Accordingly, each channel 156 extends from the channel 153 through the body 110, a portion of the

respective blade

131, 132, 133, 134, 135, 136, and a respective channel guide 157 disposed along the front face 140 of the

respective blade

131, 132, 133, 134, 135, 136. Thus, each channel 156 is in fluid communication with the bore 151 via a channel 153 and has a first or inlet end 156a at the respective channel 153 and a second or outlet end 156b at the end of the respective channel guide 157. In the present embodiment, two channels 156 extend from each channel 153, and furthermore, the inlets 156a of the two channels 156 extending from each channel 153 intersect and at least partially overlap. Although each channel 156 extends from a channel 153 in the present embodiment, in other embodiments, one or more channels (e.g., channel 156) may extend from a longitudinal bore (e.g., bore 151).

As shown in fig. 2, 6 and 9, in the present embodiment, each channel guide 157 is disposed along the front end face 140 and is positioned axially adjacent to a

respective cutting face

146, 148. Additionally, an outlet end 156b of channel 156 is oriented to direct drilling fluid toward a selected one of cutting faces 146, 148. Thus, during drilling operations, the channels 156 distribute drilling fluid to selected individual cutting faces 146, 148 to flush formation cuttings from the cutting faces 146, 148 and remove heat from the cutting faces 146, 148. Generally, cutting faces 146, 148 disposed along shoulder region 139b experience the greatest loads and heat. Thus, in the present embodiment, each outlet end 156b is positioned and oriented to direct drilling fluid to cutting faces 146, 148 disposed along shoulder region 139b of drill bit 100.

Still referring to fig. 2, 6 and 9, in the present embodiment, the channel 156 is generally narrower than the channel 153. More specifically, each channel 156 has a cross-sectional area in a plane oriented perpendicular to the central axis of the channel 156 that is less than the cross-sectional area of each channel 153 measured in a plane oriented perpendicular to the central axis of the channel 153. Because the channel 156 is narrower than the channel 153, the channel 156 may be more susceptible to plugging by any debris or solids in the drilling fluid flowing down the drill string, through the bore 151 and channel 153, and into the channel 156. Thus, as schematically illustrated in fig. 10, in the present embodiment, a screen or mesh 158 is provided at each inlet 156 a. The screens 158 extend fully across the respective inlets 156a and limit the size of any debris or solids that can enter the channels 156. Because the inlet 156a is disposed along the channel 153, any debris or solids blocked by the screen 158 are washed away from the screen 158 by the drilling fluid flowing downstream through the channel 153 and exiting the drill bit 100 via the outlet 156 b. In this sense, the screen 158 may be described as "self-cleaning".

In the present embodiment, two channels 156 extending from each channel 153 to the front face 140 of each

blade

131, 132, 133, 134, 135, 136, and an outlet end 156b of the channel 156 extending to each

blade

131, 132, 133, 134, 135, 136 are positioned and oriented to direct drilling fluid to a pair of radially adjacent cutting faces 146, 148 disposed along a shoulder region 139b of the drill bit 100. In general, however, any number of channels (e.g., channel 156) may extend to each blade (e.g., zero, one, two, three, or more channels), the outlet ends of one or more channels may not be positioned and oriented to direct drilling fluid to a pair of radially adjacent cutting faces, the outlet ends of one or more channels may not be positioned to direct drilling fluid to a cutting face in a shoulder region (e.g., shoulder region 139b), or a combination of these variations may be employed.

In the manner described, the embodiments described herein, made from a metal matrix composite composition by an additive manufacturing process, offer the potential for more tailored complex shapes and geometries, including channels for supplying drilling fluid to selected individual cutter elements to enhance bit durability. In addition, embodiments of the drill bit provide enhanced impact strength, which provides the potential for higher blades and associated benefits.

Although the channel 156 is shown and described as part of the supplemental hydraulic system 155 of the drilling fluid distribution system 150, in other embodiments, a channel (e.g., channel 156) extending through the bit body can be used for other purposes. For example, in other embodiments, the channel provides a conduit for a cable (e.g., electrical cable, optical cable, etc.) to pass through the drill bit to a sensor coupled to the drill bit. In general, the sensor can be mounted to any desired location along the drill bit, including, but not limited to, an inner surface of the drill bit (e.g., within bore 151) or an outer surface of the drill bit, such as along a leading face, a trailing face, or a cutter support surface of a primary or secondary blade. For example, FIG. 11 illustrates an embodiment of drill bit 200 that is identical to drill bit 100 described previously, except that a pair of sensors 159 are disposed on the leading face 140 of blade 131 adjacent the exit ends 156b of channels 156 extending to blade 131. In this embodiment, a cable (not shown) extends through the channel 156 to the sensor 159 for receiving signals from the sensor 159 that can communicate with the wellhead. In general, the sensor (e.g., sensor 159) can be any sensor known in the art including, but not limited to, a strain gauge, a pressure sensor, a temperature sensor, a sensor for material analysis, a sensor for chemical composition analysis, a sensor for radiation analysis, a sensor for formation analysis, a sensor capable of transmitting commands in response to an input, a camera, or a combination thereof.

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, devices, and processes described herein are possible and are within the scope of the disclosure. For example, the relative dimensions of the various components, the materials used to fabricate the various components, and other parameters may 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. The steps in the method claims may be performed in any order, unless explicitly stated otherwise. Identifiers such as (a), (b), (c) or (1), (2), (3) employed prior to steps in the method claims are not intended to specify, nor specify a particular order of, the steps, but are used to simplify the subsequent reference to such steps.

Claims

1. A drill bit for drilling a wellbore in an earthen formation, the drill bit having a central axis and a cutting rotational direction about the central axis, the drill bit comprising:

a bit body having a bit face;

a blade disposed on the bit face;

a bore extending axially into the bit body;

a flow channel extending from the bore through the bit body to the bit face, wherein the flow channel is configured to supply drilling fluid to the bit face; and

a channel extending from the flow channel to the blade.

2. The drill bit of claim 1, further comprising a plurality of primary cutter elements mounted to a cutter support surface of the blade, wherein each primary cutter element includes a forward facing cutting face, and wherein the channel is configured to supply drilling fluid to the forward facing cutting face of one primary cutter element.

3. The drill bit of claim 1, wherein the blade includes a leading surface relative to the cutting rotational direction, a trailing surface relative to the cutting rotational direction, and a cutter support surface extending between the leading surface and the trailing surface;

wherein a plurality of cutter elements are mounted to the cutter support surface of the blade adjacent the front surface;

wherein the channel extends to the front surface of the blade.

4. The drill bit of claim 3, wherein a channel guide extends from the front surface of the blade, and the channel extends through the channel guide to an outlet end.

5. The drill bit of claim 1, wherein the blades extend along a tapered region, a shoulder region, and a metering region of the drill bit, and wherein the channel has an inlet end at the flow passage and an outlet end in the shoulder region.

6. The drill bit of claim 1, wherein a plurality of flow channels extend through the bit body from the bore to the bit face, wherein each flow channel is configured to supply drilling fluid to the bit face;

a plurality of channels, wherein each channel extends from one of the flow channels.

7. The drill bit of claim 6, wherein each channel extends to a front surface of the insert relative to the direction of cutting rotation.

8. The drill bit of claim 6, wherein each channel has an outlet in a shoulder region of the drill bit.

9. The drill bit of claim 1, wherein the channel has an inlet end and an outlet end, wherein a screen extends across the inlet end, wherein the screen is configured to prevent solids from entering the channel.

10. The drill bit of claim 1, wherein the blade includes a leading face relative to the cutting rotational direction, a trailing face relative to the cutting rotational direction, and a cutter support surface extending between the leading face and the trailing face;

wherein the insert has a width W measured circumferentially and substantially parallel to the cutting rotational direction from the leading end surface to the trailing end surface_blade；

Wherein the insert has a height H measured perpendicularly from the cutting tooth support surface to the bit face_blade；

Wherein the cutting teeth are supported along the front end surface of the bladeThe height H of the blade measured at each position of the intersection of the support surfaces_bladeWidth W of the blade_bladeThe maximum value of the ratio of (a) is greater than 1.1.

11. The drill bit of claim 10, wherein a maximum value of the ratio is greater than 1.8.

12. A drill bit for drilling a wellbore in an earthen formation, the drill bit having a central axis and a cutting rotational direction about the central axis, the drill bit comprising:

a bit body having a bit face;

a bore extending axially into the bit body;

a plurality of circumferentially spaced primary blades disposed on the bit face, wherein each primary blade begins substantially adjacent the central axis and extends through a cone region and a shoulder region of the bit;

a plurality of primary cutter elements mounted on each primary blade, wherein the primary cutter elements on each primary blade are arranged in an extended row and extend through a cone region and a shoulder region of the drill bit;

a plurality of drilling fluid flow channels extending from the bore through the bit body to the bit face, wherein each flow channel is configured to flow drilling fluid to the bit face;

a plurality of channels extending through the bit body, wherein each channel has an inlet end in fluid communication with the bore.

13. The drill bit of claim 12, wherein each primary blade includes a leading face relative to the direction of cutting rotation, a trailing face relative to the direction of cutting rotation, and a cutter support surface extending between the leading face and the trailing face, wherein the primary cutter elements are mounted to the cutter support surfaces of the primary blades;

wherein each primary cutter element includes a forward facing cutting face, and wherein each channel has an outlet end configured to direct drilling fluid to the forward facing cutting face of one primary cutter element.

14. The drill bit of claim 12, wherein each channel has an outlet disposed along the front face of one of the primary blades.

15. The drill bit of claim 14, wherein each primary blade includes a channel guide extending from a front surface of the primary blade, and wherein each channel extends through one of the channel guides.

16. The drill bit of claim 12, wherein each primary blade includes a leading face relative to the direction of cutting rotation, a trailing face relative to the direction of cutting rotation, and a cutter support surface extending between the leading face and the trailing face;

wherein each main insert has a width W measured circumferentially and substantially parallel to the cutting rotation direction from the front end face to the rear end face_blade；

Wherein each primary insert has a height H measured perpendicularly from the cutting tooth support surface to the bit face_blade；

Wherein a height H of each main blade measured at each position along an intersection of the front end face of the main blade and the cutting tooth support surface_bladeWidth W of the main blade_bladeThe maximum value of the ratio of (a) is greater than 1.1.

17. The drill bit of claim 16, wherein a maximum value of the ratio is greater than 1.8.

18. The drill bit of claim 12, wherein a screen extends across the inlet end of each channel.

19. A drill bit for drilling a wellbore in an earthen formation, the drill bit having a central axis and a cutting rotational direction about the central axis, the drill bit comprising:

a bit body having a bit face;

a bore extending axially into the bit body;

wherein each primary insert comprises a leading face relative to the cutting rotation direction, a trailing face relative to the cutting rotation direction, and a cutting tooth support surface extending between the leading face and the trailing face;

20. The drill bit of claim 19, wherein a maximum value of the ratio is greater than 1.8.