DRILL BIT WITH AUXILIARY CHANNEL OPENINGS

Abstract

The present description provides drill bits for connecting underground formations and for drilling wells, wherein the PDC drill bits are adapted to reduce erosion of the drill bit face by including openings in a portion of the thickness of the PDC drill bit; the present description also relates to systems and methods for drilling underground formations using the drill bits described herein.

Description

DRILL BIT WITH AUXILIARY CHANNEL OPENINGS CROSS REFERENCE WITH RELATED APPLICATION This application claims priority to U.S. Provisional Patent Application No. 62 / 949,226 filed on December 17, 2019, which is incorporated herein by reference. FIELD OF INVENTION The present invention generally relates to drill bits for connecting underground formations and for drilling wells. More specifically, the present description relates to compact polycrystalline diamond drill bits adapted to reduce erosion of the drill bit face. The present description also relates to methods for drilling underground formations using the drill bits described herein. BACKGROUND OF THE INVENTION Polycrystalline diamond compact (PDC) bits are a type of rotary drill bit used to drill through underground formations, for example, when drilling oil and gas / natural wells. As a PDC bit rotates, discrete cutting structures fixed to the bit face engage with the rock walls at the bottom of the well, dragging along the bottom of the well and scraping or cutting the formation. PDC bits use cutting structures, referred to as cutters, each of which has a cutting or wear surface comprised of a PDC, hence the designation PDC bit. Each PDC cutter is a discrete piece, separate from the drill bit, and is manufactured by bonding a layer of polycrystalline diamond, sometimes called a diamond crown or frame, to a substrate. PDC, although very hard and abrasion-resistant, tends to be brittle.The substrate, although already very hard, is more resilient, thus improving the cutter's impact resistance. The substrate is typically machined long enough to act as a mounting strut, for example, with a portion of it fitting into a pocket or depression formed in the drill bit body. In some designs, the PDC and / or substrate structure are attached to a metal mounting strut. Due to the manufacturing procedures used for the PDC cutter, the cutting surface and substrate are typically cylindrical, with a relatively thin diamond frame bonded to a taller or longer cylinder of substrate material. The resulting composite can be machined or ground to change its shape. However, the PDC layer and substrate are most commonly used. ΜΛ / a / ZUZZ / UU l DI ua often found in PDC bits in the cylindrical shape in which they are made. Each PDC cutter on a rotary drag bit can be positioned and oriented on a drag bit face so that at least a portion of the cutting surface engages with the underground formation as the bit rotates. The PDC cutters are separated on an outer cutting surface or on the body face of a drill bit. The PDC cutters are typically arranged along each of many blades, which are raised edges that generally extend radially from the centerline of the bit toward the periphery of the face. The PDC cutters along each blade present a predetermined cutting profile to the underground formation, cutting the formation as the bit rotates. A drilling fluid, such as drilling mud or pneumatic fluid, can be pumped down the drill string through a central passage formed in the center of the drill bit and then out through openings formed in the bit face. Drilling fluid can serve many purposes. For example, drilling fluid can be used to cool, lubricate, or otherwise operate the cutters or other components of the drill string; to withdraw and carry the cutters from the well; to suspend and release the cutters; to seal formations; to transmit hydraulic power to the tools; to transmit measurements to the surface; to control corrosion; and / or to facilitate cementing. Many conventional drilling methods use liquid drilling fluids (i.e., hydraulic fluids) that are generally incompressible when using PDC bits due to erosion problems. Other drilling methods use air-based fluids (i.e., pneumatic fluids) as the drilling fluid, which typically involve a combination of competent, stable formations and relatively low formation pressures. Air-based fluids (i.e., pneumatic fluids) are frequently used, for example, in mining and blast hole drilling. Although drilling fluid is an important aspect of downhole drilling and serves numerous desirable purposes, it has also been found to have negative effects. In particular, drilling fluid can cause severe erosion of the drill bit and / or the drill bit's PDC cutters. Such erosion is undesirable because it can reduce the operational life of a drill bit and / or contribute to the failure of the entire drilling system. Furthermore, some drilling fluid mixtures, particularly pneumatic fluids, have been found to present a particularly high risk of bit erosion. The reduced lubricity of pneumatic fluids, for example, causes structural damage from vibration and heat to the drill bit and PDC cutters. Vibrational and thermal stresses on the matrix body can result in the initiation and progression of damage to the drill bit. More specifically, severe erosion can occur on the cutter substrate or at the base of the drill bit blades, which can lead to cutter and / or blade failure. For example, cracks can form in PDC cutters and may cause a portion of the cutting face to separate from the substrate, rendering the PDC cutters ineffective or resulting in PDC cutter failure.When this occurs, drilling operations may have to be stopped to retrieve the drag bit and replace the ineffective or failed cutting element. Vibration and thermal stresses can also result in delamination of an ultrahard layer at the interface. In addition, erosion from drilling fluids can contribute to cutter substrate erosion. Cutter substrate erosion is a particularly costly problem. During typical operation, the cutter face may become dull or eroded as a result of, for example, normal wear. As long as the cutter has a sharp cutting edge around a substantial portion of its circumference (for example, about one-third of the circumference), it can still be used without issue. For example, a slightly worn cutter can be rotated on the drill bit to expose a fresh, sharp edge. Cutter substrate erosion prevents this. When the cutter substrate becomes damaged, it cannot be securely attached (for example, diffusion-welded) to the drill bit. As a result, the cutter may be discarded before its face becomes dull.This greatly reduced lifespan adds operating costs. Thus, there is a need for drill bits that can reduce the stress and erosion imposed during drilling to improve operating life. Furthermore, there is a need for PDC bits that cut efficiently at the design speed, flow rates, and drilling conditions in down-drilling environments to regulate the amount of cutting load in changing formations. BRIEF DESCRIPTION OF THE INVENTION The present description relates to a drill bit comprising a body comprising a thickness for fitting to a side of a borehole and a face for fitting to a bottom of the borehole; a plurality of channels formed in the body, wherein the plurality of channels extends radially along a portion of the face and longitudinally along a portion of the thickness; a central path formed through the body for supplying fluid to the plurality of channels; a second opening located in at least one of the plurality of channels within the portion of the thickness, wherein the second opening is in fluid communication with the central path through a second path; a first opening located in at least one of the plurality of channels within the portion of the face,wherein the first opening is in fluid communication with the central path via a first channel; and a plurality of blades formed between the plurality of channels, wherein each of the plurality of blades comprises an edge on which a plurality of blades is mounted, arranged to cut the bottom of the borehole. In some embodiments, the first opening and / or the second opening comprise a port. In some embodiments, the first opening and / or the second opening is formed in a nozzle. In some embodiments, the first path is directed toward the bit face and the second path is directed away from the bit face. In some embodiments, the second path is fluidly connected to the central path at a first junction, the central path having a longitudinal axis and the second path having a longitudinal axis.and wherein the angle of intersection between the longitudinal axis of the central path and the longitudinal axis of the second path at the first junction is less than 90 degrees. In some embodiments, the second path has a longitudinal axis and at least one of the plurality of channels within the thickness portion comprises a bottom wall having a longitudinal axis, and wherein the angle of intersection between the longitudinal axis and the second path and the longitudinal axis and the bottom wall at the second opening is less than 90 degrees. In some embodiments, the first opening and the second opening are formed in the same channel. In some embodiments, each channel in the plurality of channels comprises a width, a depth, a combination of width and depth, or a cross-sectional area that is substantially constant within at least a portion of each of the plurality of channels. In some embodiments, the width and depth of each of the plurality of channels remain substantially constant within a portion of each of the plurality of channels. In some embodiments, the cross-sectional area of ​​each of the plurality of channels remains substantially constant within a portion of each of the plurality of channels. The present description also relates to a system for drilling a borehole, the system comprising: a drill bit comprising: a body comprising a face for engaging a bottom of the borehole being drilled and a thickness for engaging a side of the borehole being drilled; a plurality of channels extending radially along a portion of the face and longitudinally along a portion of the thickness; a central path formed through the body to provide fluid to the plurality of channels from a first fluid path comprising a first opening and a first path, wherein the first opening is located in at least one of the plurality of channels within the portion of the face;and wherein the first fluid path is in fluid communication with the central path; a second fluid path comprising a second opening and a second path, wherein the second opening is located in at least one of the plurality of channels within the thickness portion, and wherein the fluid path is in fluid communication with the central path; and a fluid source configured to supply fluid to the first fluid path and the second fluid path through the central path. In some embodiments, the first opening and / or the second opening comprise a port. In some embodiments, the first opening and / or the second opening is formed in a nozzle. In some embodiments, the first fluid path is directed toward the face and the second fluid path is directed toward the thickness. In some embodiments,The first fluid path provides a first fluid volume, the second fluid path provides a second fluid volume, and the first and / or second fluid paths are structured such that the ratio of the first volume to the second volume is greater than 1. In some embodiments, the fluid comprises drilling mud. In some embodiments, the fluid comprises compressible pneumatic fluid. In some embodiments, the drill bit further comprises: a plurality of blades formed between the plurality of channels, wherein each of the plurality of blades has a leading edge on which a plurality of PDC cutters is mounted; and a plurality of inserts in the plurality of blades, wherein at least some of the plurality of inserts are positioned behind the plurality of PDC cutters, between the leading edge and a trailing edge of each of the plurality of blades. The present description also relates to a method for drilling a borehole through an underground formation, the method comprising: rotating a drill bit in the borehole, wherein the drill bit comprises: a body comprising a face for engaging a bottom of the borehole being drilled and a thickness for engaging a side of the borehole being drilled; a plurality of channels formed in the body, wherein the plurality of channels extends radially along a portion of the thickness;a plurality of blades formed between the plurality of channels, wherein each of the plurality of blades has a leading edge on which a plurality of PDC cutters are mounted; a central path formed through the body to provide fluid to the plurality of channels from a first fluid path comprising a first opening and a first path, wherein the first opening is located in at least one of the plurality of channels within the face portion, and wherein the first fluid path is in fluid communication with the central path; and a second fluid path comprising a second opening and a second path, wherein the second opening is located in at least one of the plurality of channels within the thickness portion, and wherein the second fluid path is in fluid communication with the central path;coupling the borehole with the plurality of PDC cutters to form rock cuttings, wherein the rock cuttings fall within the plurality of channels; ML / a / ZUZZ / UU l DI uy pump the fluid into the first fluid path and the second fluid path through the central path. In some embodiments, the first fluid path is directed in the direction of drilling and the second fluid path is directed opposite to the direction of drilling. In some embodiments, the first fluid path provides a first fluid volume, the second fluid path provides a second fluid volume, and the first fluid path and / or the second fluid path are structured such that the ratio of the first volume to the second volume is greater than 1. In some embodiments, the fluid comprises drilling mud. In some embodiments, the fluid comprises compressible pneumatic fluid. BRIEF DESCRIPTION OF THE DRAWINGS The description is detailed below with reference to the accompanying drawings, in which similar numbers designate similar parts. FIG. 1 is a schematic view of a downhole drilling operation in accordance with various modalities. FIG. 2A is a side view of a drill bit according to various modalities of the present description. FIG. 2B is a side view of a drill bit according to various embodiments of the present description, wherein the internal features of the drill bit are illustrated with dashed lines. FIG. 3 is a cross-sectional view of a drill bit according to various modalities of the present description. FIG. 4A is a perspective view of a conventional drill bit with a mapping of the drilling fluid velocity during drill bit operation. FIG. 4B is a perspective view of a drill bit according to various modalities of the present description with a mapping of the drilling fluid velocity during drill bit operation. DETAILED DESCRIPTION OF THE INVENTION Introduction Conventional downhole drilling operations utilize drilling fluid, such as drilling mud or pneumatic fluid, to serve several critical downhole functions. For example, drilling fluid can be used to evacuate or lift rock cuttings to the surface. During a drilling operation, drilling fluid can be pumped The drilling fluid flows down the drill string through a central passage formed in the center of the drill bit, and then out through openings, ports, or nozzles formed in the face of the drill bit. The drilling fluid both cools the cutters and helps to remove and transport the cuttings from between the blades to the surface. There are several advantages and disadvantages to both fluid drilling (e.g., drilling mud drilling) and air drilling (e.g., pneumatic drilling). For example, fluid drilling is useful for keeping formation water out of a drilled borehole. Formation water is typically encountered when drilling to a target subsurface depth, and the hydrostatic pressure of the hydraulic fluid column in the annulus is sufficient to prevent the water from flowing out of the exposed rock formations at the borehole. Similarly, fluid drilling is useful for managing the high pore pressure typically encountered in oil, natural gas, and geothermal drilling operations.The heavier hydraulic fluid column in the annulus provides the high bottom-hole pressure necessary to balance (or overbalance) the high pore pressure of a natural resource reservoir such as oil or gas. However, the heavier hydraulic fluid column can be a disadvantage because it increases the confining pressure on the bit face used to cut the rock, thus slowing the rate of penetration. Furthermore, the high velocity and pressure at which the hydraulic fluid is pumped into the drill string and through the drill bit can impose stress and erosion on the bit and the individual cutters attached to it. In contrast to fluid drilling, the most recently recognized advantage of air drilling is its ability to increase the rate of penetration. The lighter the fluid in the drill string (with trapped rock cuttings), the lower the confining pressure on the bit face cutting the rock. This lower confining pressure allows the rock cuttings to be more easily removed from the cutting face. Air drilling can also prevent formation damage, which is an important aspect of fluid recovery, and avoids lost circulation, which can result in severe drill string and bit failure.However, unlike conventional hydraulic fluids used in liquid drilling, pneumatic fluids used in air drilling are compressible and not as effective as hydraulic fluids in preventing excessive temperatures and vibration stresses that could degrade cutters. Furthermore, pneumatic fluids have been found to evacuate cuttings formed during drilling less effectively. As a result, operators typically run pneumatic fluids at higher flow rates (relative to hydraulic fluids) to compensate, which further contributes to cutter erosion. Specifically, the attempts. Previous attempts to apply PDC technology in air drilling environments have proven unsuccessful, primarily due to excessively rapid cutter erosion. Air drilling thus presents a unique set of problems and challenges for PDC bits, particularly those made with die bodies. To address these limitations and problems, several embodiments described herein are directed at drill bits developed to allow a portion of the drilling fluid pumped into the drill string and through the drill bit to bypass the bit face. In some embodiments, a drill bit includes a second opening (e.g., an auxiliary opening), such as a port or nozzle, formed in a thicknessed portion of at least one of the drill bit channels. The second opening is in fluid communication with the central passage through a second path. The second path travels from the central passage in a direction away from the drill bit face (e.g., substantially opposite to the drilling direction) toward the second opening in the thicknessed portion.The drill bit includes a first opening (e.g., a main opening), such as a port or nozzle, formed in at least one of the plurality of channels within the bit face portion. The first opening is in fluid communication with the central passage through a first path. The first path travels from the central passage in a direction toward the bit face (e.g., substantially the same drilling direction) to the first opening in the face. Consequently, drilling fluid pumped through the drill string and into the central passage of the bit may flow partially through the second path and out of the second opening and partially through the first path and out of the first opening.It has been surprisingly and / or unexpectedly found that the inclusion of the auxiliary opening greatly reduces the stress and erosion imposed on the falling auger bit as well as the PDC cutters formed there. The drill bits described herein are suitable for a variety of downhole operations, including drilling (e.g., rotary drilling with a knife bit), mining, blast hole drilling, fracturing completion, refracturing, re-entry, or remediation. Notably, the drill bits described herein are suitable for both fluid drilling and air drilling. Generally, auxiliary openings increase the total cross-sectional flow area (TFA) of the drilling fluid, which reduces the fluid velocity and thus minimizes erosion. In fluid drilling, the reduced fluid velocity is particularly advantageous because fluid drilling typically uses smaller drill bits. In air drilling, larger drill bits are typically used, and a minimal TFA is achieved. ML / a / ZUZZ / UU l DI u requires. The TFA required for conventional air drilling required high fluid velocities and thus serious erosion on the bit face. The inclusion of the auxiliary opening mitigates erosion while also meeting the minimum TFA requirement. As used herein, the terms substantially, approximately, and close to are defined as being largely, but not necessarily entirely, what is specified (and fully including what is specified) as understood by a person skilled in the art. In any modality described, the term substantially, approximately, or close to may be substituted with within [a percentage] of what is specified, where the percentage includes 0.1, 1, 5, and 10 percent. As used herein, the term fluid communication means that components are connected to each other in a manner that allows a fluid (e.g., pneumatic or hydraulic) to pass between them. As used in the present tense when an action is based on something, this means that the action is based at least in part on at least a part of something. Drilling Equipment As noted above, this description relates to a novel drill bit design for use in engaging underground formations and for drilling boreholes. The drill bit described herein can be incorporated into a system for drilling and other downhole operations. Figure 1 is a schematic representation of a drilling rig 100 for a drilling operation. Each of the components shown in the schematic representation of the drilling rig 100 is intended to be generally representative of the component, and the particular example is intended to be a representative, not limiting, example of how a drilling rig could be configured for drilling with a drill bit as described herein. In various embodiments, the drilling rig 100 includes a derrick 101 that places a drill bit 102 at the end of a drill string 104 within the borehole or drill hole 106 that is formed in the underground formation 112. During drilling operations, a drill bit 102 can be attached to a lower end of the drill string 104.In some embodiments, the 102 auger bit comprises one or more PDC cutters comprised of sintered polycrystalline diamond (either natural or synthetic) exhibiting diamond-to-diamond bonding, polycrystalline cubic boron nitride, wurtzite boron nitride, aggregated diamond nanorods (DNA), other hard crystalline materials that can be substituted for diamond, or combinations thereof. The sounding column 104 can be many kilometers (miles) long and, like ML / a / ZUZZ / UU l DI u that the borehole 106 extends in both the vertical and horizontal directions from the surface 118. In this example, the borehole string 104 is formed from threaded pipe segments that are threaded together at the surface as the borehole string 104 is lowered into the borehole 106. However, the borehole string 104 may also comprise coiled pipe. The borehole string 104 may also include components other than tubes or pipe. For example, a bottom hole assembly (BHA) 105 may be attached to a lower end of the borehole string 104 before the drill bit 102.The BHA 105 may include, depending on the specific application, one or more of the following components: a drill bit assistant, a downhole motor, stabilizers, a drill collar, percussion devices, directional drilling and measurement equipment, measuring tools while drilling, logging tools while drilling, and other devices. The characteristics of the BHA 105 components contribute to determining the penetration rate of the drill bit 102 and the shape of the borehole 106, direction, and other geometric characteristics. During drilling, the 102 drill bit is rotated to cut through the underground formation 112 and advance the borehole 106. The 102 drill bit can be rotated in any number of ways. For example, the drill bit 102 can be rotated by rotating the drill string 104 with an overhead drive 116 or a table drive (not shown) or with a downhole motor that is part of the BHA 105. The drill bit 102 can be surrounded by a side wall 110 of the drill hole 106. As the drill bit 102 is rotated inside the drill hole 106 via the drill string 104, drilling fluid can be pumped down the drill string 104, through internal passages within the drill bit 102, and out of the drill bit 102 through openings, nozzles, or ports.The cuttings from formation 126 generated by one or more PDC cutters of the drill bit 102 can be carried with the drilling fluid through the channels, around the drill bit 102, and back to the drill hole 106 through the annular space 127 inside the drill hole 106 outside the drill string 104. Drilling fluid can be pumped down the drill string 104 using conventional means, e.g., pumps. Figure 1 illustrates a fluid flow 120, which is intended as a non-limiting representation of any of the possible ways of generating the drilling fluid (e.g., hydraulic or pneumatic fluid), as the drill bit 102 can be used with any of them. The drilling fluid is circulated down the drill hole 106 by flowing it through the drill string 104 to the drill bit 102, where it exits through openings, nozzles, or ports to carry the cuttings away from the face of the drill bit 102 and into the annular space 127, where the cuttings can be carried upward to a collection point 122. The drilling fluid within the collection point 122 can be recirculated once it has been cleaned of the cuttings. In several embodiments, the drilling fluid comprises liquid drilling mud (i.e., a hydraulic fluid). Several conventional liquid drilling muds are known, and each of these is acceptable for use with the drill bits and drilling system described herein. In some embodiments, for example, the liquid drilling mud may comprise only water or water in combination with other components. In some embodiments, the liquid drilling mud may comprise water combined with clays (e.g., bentonite) or other chemicals (e.g., potassium formate). In some embodiments, the liquid drilling mud may be an oil-based mixture, for example, comprising a petroleum product. In some embodiments, the liquid drilling mud may comprise a synthetic oil. In several embodiments, the drilling fluid comprises a pneumatic fluid, for example, a mixture of one or more gases. In some embodiments, the pneumatic fluid comprises atmospheric air (for example, a combination of atmospheric gases). In other embodiments, the pneumatic fluid comprises one or more gases from storage tanks (such as liquid nitrogen) that are then vaporized to create a high-pressure gas, which may or may not be subsequently compressed. In other embodiments, the air is a combination of atmospheric gases and additional gases such as inert gases, for example, argon or helium. In some embodiments, the pneumatic fluid is pressurized before flowing through the drill pipe. The pressurized pneumatic fluid can be generated in any number of ways, any of which can be used with the drill bit 102. For example, the fluid source 120 may comprise one or more high-pressure pumps that compress the air. Auger Drill Bit This description relates to a drill bit structurally modified to reduce erosion of the PDC cutters and / or the drill bit face. Specifically, this description relates to PDC drill bits that have an opening within the bit thickness. This additional opening, as described in detail below, allows a portion of the drilling fluid to bypass the drill bit face, thereby reducing erosion of the PDC cutters and / or the face. The drill bits of the present description comprise a body comprising a thickness for fitting to a side of a borehole and a face for fitting to a bottom of the borehole; a plurality of channels formed in the body, wherein the plurality of channels extends radially along a portion of the face and longitudinally along a portion of the thickness; a central path formed through the body to provide ML / a / ZUZZ / UU / □ I u fluid to the plurality of channels; a second opening located in at least one of the plurality of channels within the thickness portion, wherein the second opening is in fluid communication with the central path through a second path; a first opening located in at least one of the plurality of channels within the face portion, wherein the first opening is in fluid communication with the central path through a first path; and a plurality of blades formed between the plurality of channels, wherein each of the plurality of blades comprises an edge on which is mounted a plurality of blades arranged to cut the bottom of the borehole. Figures 2A and 2B illustrate one embodiment of the drill bit described herein. In particular, Figures 2A and 2B illustrate a drill bit 200 (e.g., drill bit 104 as described with respect to Figure 1) structurally adapted to reduce face erosion. Drill bit 200 is intended as a representative example of drill bits, e.g., PDC drag bits, for drilling into underground formations. The drill bit 200 is structurally and mechanically designed to be rotated about its central axis 202. As shown, the drill bit 200 comprises a body 204 connected to a shank 205 having a tapered threaded coupling 206 for connecting the drill bit 200 to a drill string (not shown in FIG. 2A or FIG. 2B but as described with reference to FIG. 1). The body 204 is not limited to any particular material.In some forms, the 204 body is made of an abrasion-resistant composite material or matrix comprising, for example, powdered tungsten carbide cemented by a metallic binder. As shown, the body 204 is arranged radially around the central axis 202, about which the body 204 is designed to rotate during the drilling procedure. As shown in Figures 2A and 2B, the body 204 includes a face 210 intended to engage a bottom end of the borehole being drilled. In the embodiment shown in the figures, face 210 lies substantially in a plane perpendicular to the central axis 202 of the drill bit 200. The body 204 also includes a thickness 212 intended to engage the side wall of the borehole being drilled. In the embodiment shown in the figures, the thickness 212 lies substantially in a plane perpendicular to the central axis 202 of the drill bit 200. The drill bit 200 further includes a plurality of channels 208 formed in the body 204, extending along a portion of the face 210 and along a portion of the thickness 212.Formed between channels 208, is a plurality of blades 211. In the auger bit 200, the cutting elements 220 can be positioned along the front side (in the intended direction of rotation) of the blades 211, with their working surfaces generally facing forward to cut the formations ML / a / ZUZZ / UU / □ I or underground when the auger bit 200 is rotated about its central axis 202. In some embodiments, the blade 211 may comprise one or more rows of cutting elements 220 arranged on the blade 211. In some embodiments, the PDC auger 200 has both a first row of PDC cutters 221 (i.e., a subset of the cutting elements 220) and a second row of PDC cutters 222 (i.e., another subset of the cutting elements 220) mounted on each of the blades 211. The first row of PDC cutters 221 may be of primary cutters and the second row of PDC cutters may be of secondary or backup cutters. In addition, the primary cutters may be a single set or a plural set (e.g., multiple rows of cutters). Second Opening The drill bits described herein include a second opening (e.g., an auxiliary opening) located within the thickness portion of at least one of the plurality of channels. At this location, the second opening, and the second path to which it is connected, provides a drilling fluid path such that the drilling fluid can avoid the drill bit face. In the embodiments shown in Figures 2A and 2B, the drill bit 200 includes second openings 230 formed within the thickness 212. As can be seen in Figure 2B, in particular, the drill bit 200 comprises a central path 250, which runs through the body. The central path 250 is connected to every second opening 230 by means of a second path 232. The central path 250, through the second path 232 and the first path 242, is intended to provide drilling fluid to the channels 208. In some embodiments, the drill bit comprises an auxiliary opening. In other embodiments, the drill bit may comprise a plurality of auxiliary openings. For example, the drill bit may comprise at least one auxiliary opening, at least two auxiliary openings, at least three main openings, four auxiliary openings, or at least five auxiliary openings. In some embodiments, the drill bit comprises a second main opening in each channel of the plurality of channels. In one such embodiment, for example, the drill bit comprises four channels formed in the drill bit body, and each of the four channels comprises a second opening formed in a portion of its thickness. In some of these embodiments, each channel of the plurality may comprise a second opening. In some of these embodiments, each channel of the plurality of channels may comprise at least one second opening, for example, at least two second openings, at least three second openings, four second openings, or at least five second openings. In the embodiment shown in Figures 2A and 2B, for example, the drill bit 200 includes a second opening 230 formed in each channel. The nature and structure of the auxiliary opening is not particularly restricted. In some embodiments, the auxiliary opening is a port. In some embodiments, the auxiliary opening is part of a nozzle. In some embodiments, the drill bit comprises a plurality of auxiliary openings, and each auxiliary opening is a port. In some embodiments, the drill bit comprises a plurality of auxiliary openings, and each auxiliary opening is part of a nozzle. In some embodiments, the drill bit comprises a plurality of auxiliary openings, each auxiliary opening independently being either a port or a nozzle. In the embodiment shown in FIGS. 2A and 2B, for example, every second opening 230 is in the form of a port. In the auger bits described herein, the second opening (e.g., the auxiliary opening) is in communication with the central path of the auger bit via a second path. Each of the second path and the central path has a longitudinal axis, which runs through the center of the second path and the central path, respectively. Similarly, the second opening may be located on the bottom wall of the thickness portion of a channel, and the bottom wall may comprise a longitudinal axis. The second path, central path, and / or the bottom wall of the channel are preferably structured such that the second path is generally directed into the thickness and substantially away from the face of the auger bit. In some modalities, for example, the second path and the central path can be structured such that the longitudinal axis of the second path and the longitudinal axis of the central path intersect at a specific angle. In one modality, the angle of intersection between the longitudinal axis of the second path and the longitudinal axis of the central path is less than 90 degrees, for example, less than 80 degrees, less than 70 degrees, or less than 60 degrees. In terms of lower limits, the angle of intersection between the longitudinal axes can be greater than 0 degrees, for example, greater than 5 degrees, greater than 10 degrees, greater than 15 degrees, or greater than 20 degrees. In terms of intervals, the angle of intersection between the longitudinal axes can range from 0 to 90 degrees, for example, from 10 to 80 degrees, from 20 to 70 degrees, or from 30 to 60 degrees. In some configurations, for example, the second lane and the bottom wall can be structured so that the longitudinal axis of the second lane and the longitudinal axis of the bottom wall intersect at a specific angle. In one configuration, the angle of intersection between the longitudinal axis of the second lane and the longitudinal axis of the bottom wall is less than 90 degrees, for example, less than 80 degrees, less than 70 degrees, or less than 60 degrees. In terms of lower limits, the angle of intersection between the longitudinal axes can be greater than 0 degrees, for example, greater than 5 degrees, greater than 10 degrees, greater than 15 degrees, or greater than 20 degrees. In terms of intervals, the angle of intersection between the longitudinal axes can range from 0 to 90 degrees, for example, from 10 to 80 degrees, from 20 to 70 degrees, or from 30 to 60 degrees. The shape of the second lane is not particularly restricted, and any suitable shape may be used. In some modalities, the second lane is substantially straight. In some modalities, the second lane is curved. In some modalities, the second lane has a cross-section selected from the group consisting of circular, substantially circular, almond-shaped, or oval, polygonal, substantially polygonal, dogbone, Y, X, K, C, multilobed, and any combination thereof. The structure and orientation of the second path can be observed in FIG. 3, which illustrates a cross-section of one embodiment of the drill bit of the present description. As shown, the drill bit 300 comprises a body 304 arranged radially about the central axis 302, about which the body 304 is designed to rotate during the drilling procedure. The body 304 includes a face 310 intended to engage a bottom end of the borehole being drilled and a thickness 312 intended to engage the side wall of the borehole being drilled. FIG. 3 illustrates the cross-section of a channel 308 formed in the body 304, extending along a portion of the face 310 and along a portion of the thickness 312, as well as the cross-section of a cutting edge 311.The 300 auger bit also includes 320 cutting elements for cutting underground formations when the 300 auger bit is rotated around its central axis. As can be seen in FIG. 3, the drill bit 300 comprises a central path 350, which runs through the body. The central path 350 is connected to a second opening 330 by means of a second path 332. The central path 350, partly through the second path 332 and the first path, is intended to supply drilling fluid to the channels 308. In FIG. 3, the arrows illustrate the typical direction of drilling fluid flow during operation. The arrows demonstrate how the second path 332 is structured to allow the drilling fluid to avoid the bit face. The second path 332 is directed toward thickness 312. During drilling, the second path 332 is directed opposite to the drilling direction. In particular, the second path is structured such that the longitudinal axis LAfb of the second path 332 intersects the longitudinal axis of the centerline path (which corresponds to the centerline axis 302 of this mode) at an angle α, which is less than 90 degrees. Furthermore, the second path is structured such that the longitudinal axis LAfb of the second path 332 intersects the longitudinal axis LAbw of a bottom wall of channel 308 at an angle β, which is less than 90 degrees. First opening As noted, the drill bits of the present description include a first opening (e.g., a main opening) located within the face portion of at least one of the plurality of channels. At this location, the main opening, and the primary path to which it connects, provides a trajectory for drilling fluids such that the drilling fluid can reach the face of the drill bit. The drilling fluid can therefore be used to, for example, cool the cutters formed on the face of the bit and assist in removing and transporting rock cuttings away from between the cutters. In the embodiment shown in Figures 2A and 2B, for example, the drill bit 200 includes first openings 240 formed in the face 210. As can be seen in Figure 2B, in particular, the drill bit comprises a central path 250, which runs through the body.The central path 250 is connected to each first opening 240 by means of the first path 242. The central path 250, partly through the first path 242, is intended to provide drilling fluid to the channels 208. In some embodiments, the drill bit comprises one main opening. In other embodiments, the drill bit may comprise at least one main opening, for example, at least two main openings, at least three main openings, four main openings, or at least five main openings. In some embodiments, the number of main openings corresponds to the number of auxiliary openings, for example, one main opening for each auxiliary opening, two main openings for each auxiliary opening, or one main opening for every two auxiliary openings. In the embodiment shown in Figures 2A and 2B, for example, the drill bit 200 includes a first opening 240 formed in a portion of the face 210 of each flute 208. In some embodiments, the drill bit comprises a main opening in each channel of the plurality of channels. In one such embodiment, for example, the drill bit comprises four channels formed in the drill bit body, and each of the four channels comprises a main opening formed in a portion of its thickness. In some embodiments, each channel of the plurality may comprise a primary opening. In some of these embodiments, each channel of the plurality of channels may comprise at least one main opening, for example, at least two main openings, at least three main openings, four main openings, or at least five main openings. In some embodiments, the drill bit comprises a main opening in each channel in which a main opening is formed. The nature and structure of the first opening are not particularly restricted. In some embodiments, the first opening comprises a port. In some embodiments, the first opening comprises a nozzle. In some embodiments, the drill bit comprises In some embodiments, the drill bit comprises a plurality of first openings, and each first opening comprises a port. In some embodiments, where the drill bit comprises a plurality of first openings, each first opening may independently comprise a port or a nozzle. In the embodiment shown in FIGS. 2A and 2B, for example, the drill bit 200 includes a first opening 240 formed in a portion of the face 210 of each flute 208, and each first opening 240 is formed in a nozzle. Figure 3 also illustrates the first opening 340. As shown, the center path 350 is also connected to a first opening 340 via a first path (not illustrated). The first path is directed toward face 310. During drilling, the first path is directed in the drilling direction and allows the flow of drilling fluid (illustrated by arrows) toward face 310 through the first opening 340. In some configurations, the first and / or second flow paths are sized or otherwise designed to control the relative volume of drilling fluid flowing through each. In some configurations, for example, the first and second flow paths are sized so that a greater volume of drilling fluid flows through the first path than through the second path. In other words, during operation, the first flow path provides a first fluid volume (e.g., the flow area at the bit face), the second flow path provides a second fluid volume (e.g., the auxiliary flow area), and in some configurations, the first fluid volume is greater than the second fluid volume. In one configuration, the ratio of the first volume to the second volume is greater than 1, for example, greater than 1.5, greater than 2, greater than 2.5, greater than 3, or greater than 3.5. Channels In several embodiments, the width, depth, or a combination thereof (width and depth) of one or more channels in the plurality of channels is substantially constant within at least a portion of the one or more channels in the plurality of channels. As described herein, the term substantially may be substituted with within [a percentage] of what is specified, where the percentage includes 0.1, 1, 5, and 10 percent; and thus substantially constant means that the width, depth, or a combination thereof of one or more channels remains within 0.1, 1, 5, or 10% throughout the entire portion of the channels (e.g., the width and / or depth never varies by more than 0.1, 1, 5, or 10% throughout the portion of the channels).In some embodiments, the width, depth, or a combination thereof of each of the one or more channels is the same or different within the portion of the one or more channels where the width, depth, or a combination thereof remains substantially constant. For example, a first subset of the one or more channels may have a first width, a first depth, or a combination thereof that remains substantially constant within at least a portion of the first subset of the one or more channels, and a second subset of the one or more channels may have a second width, a second depth, or a combination thereof that remains substantially constant within at least a portion of the second subset of the one or more channels, where the first width is the same as or different from the second width, the first depth is the same as or different from the second depth, or a combination thereof.In some embodiments, the width or depth is substantially constant within at least a portion of one or more channels of the plurality of channels. In other embodiments, both the width and depth are substantially constant within at least a portion of one or more channels of the plurality of channels. In several embodiments, the cross-sectional area of ​​one or more channels within the plurality of channels is substantially constant within at least a portion of the one or more channels. As described herein, the term "substantially" may be substituted with "within [a percentage] of what is specified," where the percentage includes 0.1, 1, 5, and 10 percent; and thus "substantially constant" means that the cross-sectional area of ​​one or more channels remains within 0.1, 1, 5, or 10 percent across the entire portion of the channels (i.e., the cross-sectional area never varies by more than 0.1, 1, 5, or 10 percent across the entire portion of the channels). In some embodiments, the cross-sectional area of ​​each of the one or more channels is either equal or different within the portion of the one or more channels where the cross-sectional area remains substantially constant.For example, a first subset of one or more channels may have a first cross-sectional area that remains substantially constant within at least a portion of the first subset of the one or more channels, and a second subset of one or more channels may have a second cross-sectional area that remains substantially constant within at least a portion of the second subset of one or more channels, where the first cross-sectional area is equal to or different from the second cross-sectional area. Reduced erosion As discussed, the present inventors have found that including the second opening in the thick portion of the drill bit greatly reduces erosion on the PDC cutters and / or the drill bit face. By doing so, the second opening can improve drill bit operation, for example, by extending the service life of the drill bit or individual PDC cutters. One aspect of reduced erosion is illustrated in FIGS. 4A and 4B, which illustrate Figure 4A illustrates a drill bit that lacks second openings in the channel thickness portion. As Figure 4A illustrates, the PDC cutters of the conventional drill bit, particularly the first row of PDC cutters, are exposed to high-velocity drilling fluid flow. Figure 4B illustrates a drill bit that incorporates the present description and includes second openings in the channel thickness portion. As can be seen in Figure 4B, the inclusion of the second openings allows a portion of the drilling fluid to bypass the drill bit face. As a result, the PDC cutters are exposed to substantially lower drilling fluid velocities, reducing erosion on each PDC cutter. As a result of reduced erosion, the drill bit PDC cutters described herein advantageously have a longer service life. In some cases, the service life of the PDC cutter can be described by the period of time the drill bit can be operated without requiring cutter replacement (for example, due to damage to the cutter holder, as described above). In some embodiments, the drill bit can be operated for at least 10 hours without needing to replace a PDC cutter, for example, at least 12 hours, at least 15 hours, at least 18 hours, at least 20 hours, at least 22 hours, at least 25 hours, at least 30 hours, at least 35 hours, at least 40 hours, at least 45 hours, or at least 50 hours. Modalities As used below, any reference to a series of modalities is to be understood as a reference to each of those modalities disjunctively (e.g., Modalities 1 to 4 is understood as Modalities 1, 2, 3 or 4). Modality 1 is a drill bit comprising: a body comprising a thickness for coupling to a side of a borehole and a face for coupling to a bottom of the borehole; a plurality of channels formed in the body, wherein the plurality of channels extends radially along a portion of the face and longitudinally along a portion of the thickness; a central path formed through the body for supplying fluid to the plurality of channels; a second opening located in at least one of the plurality of channels within the portion of the thickness, wherein the second opening is in fluid communication with the central path through a second path; a first opening located in at least one of the plurality of channels within the portion of the face, wherein the first opening is in fluid communication with the central path through a first path;and a plurality of blades formed between the plurality of channels, wherein each of the plurality of blades comprises an edge on which is mounted a plurality of blades arranged to cut the bottom of the borehole.; Mode 2 is a drill bit of mode(s) 1, wherein the first opening and / or the second opening comprises a port. Mode 3 is the drill bit of mode(s) 1 to 2, wherein the first opening and / or the second opening is formed in a nozzle. Mode 4 is the drill bit of mode(s) 1 to 3, where the first path is directed towards the face of the drill bit and the second path is directed away from the face of the drill bit. Mode 5 is the drill bit of mode(s) 1 to 4, wherein the second path is seamlessly connected to the central path at a first junction, the central path has a longitudinal axis and the second path has a longitudinal axis, and wherein an intersection angle between the longitudinal axis of the central path and the longitudinal axis of the second path at the first junction is less than 90 degrees. Mode 6 is the drill bit of mode(s) 1 to 5, wherein the second path has a longitudinal axis and at least one of the plurality of channels within the thickness portion comprises a bottom wall having a longitudinal axis, and wherein an angle of intersection between the longitudinal axis and the second path and the longitudinal axis and the bottom wall at the second opening is less than 90 degrees. Mode 7 is the drill bit of mode(s) 1 to 6, where the first opening and the second opening are located in the same channel. Mode 8 is the drill bit of mode(s) 1 to 7, wherein each channel of the plurality of channels comprises a width, a depth, a combination of width and depth, or a cross-sectional area that is substantially constant within at least a portion of each of the one or more channels. Mode 9 is the drill bit of mode 8, wherein the width and depth of each of the plurality of channels remains substantially constant within the portion of each of the plurality of channels. Mode 10 is the drill bit of mode(s) 8 to 9, wherein the cross-sectional area of ​​each of the plurality of channels remains substantially constant within the portion of each of the plurality of channels.Modality 11 is a system for drilling a borehole, the system comprising: a drill bit comprising: a body comprising a face for coupling to a bottom of the borehole being drilled and a thickness for coupling to a side of the borehole being drilled; a plurality of channels formed in the body, wherein the plurality of channels extends radially along a portion of the face and extends longitudinally along a portion of the thickness; a central path formed through the body to provide fluid to the plurality of channels from a first fluid path comprising a first opening and a first path, wherein the first opening is located in at least one of the plurality of channels within the portion of the face, and wherein the first fluid path is in fluid communication with the central path;a second fluid path comprising a second opening and a second trajectory, wherein the second opening is located in at least one of the plurality of channels within the thickness portion, and wherein the second fluid path is in fluid communication with the central trajectory; and a fluid source configured to supply fluid to the first fluid path and the second fluid path via the central trajectory. Mode 12 is a drill bit of mode 11, wherein the first opening and / or the second opening comprises a port. Mode 13 is the drill bit of mode(s) 11 to 12, wherein the first opening and / or the second opening is formed in a nozzle. Mode 14 is the system of modes 11 to 13, where the first fluid path is directed towards the face and the second fluid path is directed towards the thickness. Mode 15 is the system of modes 11 to 14, wherein the first fluid path provides a first fluid volume, the second fluid path provides a second fluid volume, and the first fluid path and / or the second fluid path is structured such that an index from the first volume to the second volume is greater than 1. Mode 16 is the system of mode(s) 11 to 15, where the fluid comprises drilling mud. Mode 17 is the system of modes 11 to 16, wherein the fluid comprises compressible pneumatic fluid. Mode 18 is the system of modes 11 to 17, wherein the drill bit further comprises: a plurality of blades formed between the plurality of channels, wherein each of the plurality of blades has a leading edge on which a plurality of PDC cutters is mounted; and a plurality of inserts in the plurality of blades, wherein at least part of the plurality of inserts are positioned behind the plurality of PDC cutters, between the leading edge and a trailing edge of each of the plurality of blades. Method 19 is the method for drilling a borehole through an underground formation, the method comprising: rotating a drill bit in the borehole, wherein the drill bit comprises: a body comprising a face for engaging a bottom of the borehole being drilled and a thickness for engaging a side of the borehole MA / a / ZUZZ / UU / □ I u being perforated; a plurality of channels formed in the body, wherein the plurality of channels extends radially along a portion of the face and longitudinally along a portion of the thickness; a plurality of blades formed between the plurality of channels, wherein each of the plurality of blades has a leading edge on which a plurality of PDC cutters is mounted; a central path formed through the body to provide fluid to the plurality of channels from a first fluid path comprising a first opening and a first path, wherein the first opening is located in at least one of the plurality of channels within the portion of the face, and wherein the first fluid path is in fluid communication with the central path;and a second fluid path comprising a second opening and a second trajectory, wherein the second opening is located in at least one of the plurality of channels within the thickness portion, and wherein the second fluid path is in fluid communication with the central trajectory; coupling the borehole with the plurality of PDC cutters to form rock cuttings, wherein the rock cuttings fall within the plurality of channels; and pumping fluid into the first fluid path and the second fluid path through the central trajectory. Mode 20 is the method of mode 19, where the first fluid path is directed towards the drilling direction and the second fluid path is directed opposite to the drilling direction. Mode 21 is the method of mode(s) 19 to 20, wherein the first fluid path provides a first fluid volume, the second fluid path provides a second fluid volume, and the first fluid path and / or the second fluid path is structured such that an index from the first volume to the second volume is greater than 1. Mode 22 is the method of mode(s) 19 to 21, where the fluid comprises drilling mud. Mode 23 is the method of mode(s) 19 to 22, wherein the fluid comprises compressible pneumatic fluid.

Claims

1. A drill bit comprising: a body comprising a thickness for fitting a side of a borehole and a face for fitting a bottom of the borehole; a plurality of channels formed in the body, wherein the plurality of channels extends radially along a portion of the face and longitudinally along a portion of the thickness; a central path formed through the body for supplying fluid to the plurality of channels; a second opening located in at least one of the plurality of channels within the portion of the thickness, wherein the second opening is in fluid communication with the central path through a second path; a first opening located in at least one of the plurality of channels within the portion of the face, wherein the first opening is in fluid communication with the central path through a first path;and a plurality of blades formed between the plurality of channels, wherein each of the plurality of blades comprises an edge on which is mounted a plurality of blades arranged to cut the bottom of the borehole.; 2. The drill bit according to claim 1, further characterized in that the first opening and / or the second opening comprises a port.

3. The drill bit according to claim 1, further characterized in that the first opening and / or the second opening is formed in a nozzle.

4. The drill bit according to claim 1, further characterized in that the first path is directed towards the face of the drill bit and the second path is directed away from the face of the drill bit.

5. The drill bit according to claim 1, further characterized in that the second path is fluidly connected to the central path at a first junction, the central path having a longitudinal axis and the second path having a longitudinal axis, and wherein an intersection angle between the longitudinal axis of the central path and the longitudinal axis of the second path at the first junction is less than 90 degrees.

6. The drill bit according to claim 1, further characterized in that the second path has a longitudinal axis and at least one of the plurality of channels within the thickness portion comprises a bottom wall having a longitudinal axis, and wherein an intersection angle between the longitudinal axis and the second path and the longitudinal axis and the bottom wall at the second opening is less than 90 degrees.

7. The drill bit according to claim 1, further characterized in that the first opening and the second opening are located in the same channel.

8. The drill bit according to claim 1, further characterized in that each channel of the plurality of channels comprises a width, a depth, a combination of width and depth, or a cross-sectional area that is substantially constant within at least a portion of each of the one or more channels.

9. The drill bit according to claim 8, further characterized in that the width and depth of each of the plurality of channels remains substantially constant within the portion of each of the plurality of channels.

10. The drill bit according to claim 8, further characterized in that the cross-sectional area of ​​each of the plurality of channels remains substantially constant within the portion of each of the plurality of channels.

11. A system for drilling a borehole, comprising: a drill bit comprising: a body comprising a face for coupling to the bottom of the borehole being drilled and a thickness for coupling to the side of the borehole being drilled; a plurality of channels formed in the body, wherein the plurality of channels extends radially along a portion of the face and longitudinally along a portion of the thickness; a central path formed through the body to provide fluid to the plurality of channels from a first fluid path comprising a first opening and a first path, wherein the first opening is located in at least one of the plurality of channels within the portion of the face, and wherein the first fluid path is in fluid communication with the central path;a second fluid path comprising a second opening and a second path, wherein the second opening is located in at least one of the plurality of channels within the thickness portion, and wherein the fluid path is in fluid communication with the central path; and a fluid source configured to supply fluid to the first fluid path and the second fluid path via the central path.

12. The drill bit according to claim 11, further characterized in that the first opening and / or the second opening comprises a port.

13. The drill bit according to claim 11, further characterized in that the first opening and / or the second opening is formed in a nozzle.

14. The system according to claim 11, further characterized in that the first fluid path is directed towards the face and the second fluid path is directed towards the thickness.

15. The system according to claim 11, further characterized in that the first fluid path provides a first fluid volume, the second fluid path provides a second fluid volume, and the first fluid path and / or the second fluid path is structured such that an index from the first volume to the second volume is greater than 1.

16. The system according to claim 11, further characterized in that the fluid comprises drilling mud.

17. The system according to claim 11, further characterized in that the fluid comprises compressible pneumatic fluid.

18. The system according to claim 11, further characterized in that the drill bit further comprises: a plurality of blades formed between the plurality of channels, wherein each of the plurality of blades has a leading edge on which a plurality of PDC cutters is mounted; and a plurality of inserts in the plurality of blades, wherein at least part of the plurality of inserts are positioned behind the plurality of PDC cutters, between the leading edge and a trailing edge of each of the plurality of blades.

19. A method for drilling a borehole through an underground formation, comprising: rotating a drill bit in the borehole, wherein the drill bit comprises: a body comprising a face for engaging a bottom of the borehole being drilled and a thickness for engaging a side of the borehole being drilled; a plurality of channels formed in the body, wherein the plurality of channels extends radially along a portion of the face and extends longitudinally along a portion of the thickness;a plurality of blades formed between the plurality of channels, wherein each of the plurality of blades has a leading edge on which a plurality of PDC cutters are mounted; a central path formed through the body to provide fluid to the plurality of channels from a first fluid path comprising a first opening and a first path, wherein the first opening is located in at least one of the plurality of channels within the face portion, and wherein the first fluid path is in fluid communication with the central path; and a second fluid path comprising a second opening and a second path, wherein the second opening is located in at least one of the plurality of channels within the thickness portion, and wherein the second fluid path is in fluid communication with the central path;coupling the borehole with the plurality of PDC cutters to form rock cuttings, wherein the rock cuttings fall within the plurality of channels; and pumping the fluid into the first fluid path and the second fluid path through the central path.

20. The method according to claim 19, further characterized in that the first fluid path is directed towards the drilling direction and the second fluid path is directed opposite to the drilling direction.

21. The method according to claim 19, further characterized in that the first fluid path provides a first fluid volume, the second fluid path provides a second fluid volume, and the first fluid path and / or the second fluid path is structured in such a way that an index of the first volume to the second volume is greater than 5 1.

22. The method according to claim 19, further characterized in that the fluid comprises drilling mud.

23. The method according to claim 19, further characterized in that the fluid comprises compressible pneumatic fluid.

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