Patent Publication Number: US-2022213735-A1

Title: Earth-boring tools, cutting elements, and associated structures, apparatus, and methods

Description:
TECHNICAL FIELD 
     Embodiments of the present disclosure generally relate to earth-boring operations. In particular, embodiments of the present disclosure relate to earth-boring tools, cutting elements, and associated structures. 
     BACKGROUND 
     Wellbore drilling operations may involve the use of an earth-boring tool at the end of a long string of pipe commonly referred to as a drill string. An earth-boring tool may be used for drilling through formations, such as rock, dirt, sand, tar, etc. In some cases, the earth-boring tool may be configured to drill through additional elements that may be present in a wellbore, such as cement, casings (e.g., a wellbore casing), discarded or lost equipment (e.g., fish, junk, etc.), packers, etc. In some cases, earth-boring tools may be configured to drill through plugs (e.g., fracturing plugs, bridge plugs, cement plugs, etc.). In some cases, the plugs may include slips or other types of anchors and the earth-boring tool may be configured to drill through the plug and any slip, anchor, and other component thereof. 
     A fluid may be supplied into the wellbore during the wellbore drilling operation. The fluid may be used to cool and/or clean the earth-boring tool and/or related cutting elements. For example, the fluid may cool the earth-boring tool and carry cuttings and debris away from the earth-boring tool. Fluid pressure in the wellbore may be controlled to different pressures for different types of drilling operations. For example, in overbalanced drilling, the fluid pressure in the wellbore may be maintained above the pressure of the fluid in the earth formation to substantially prevent ingress of the fluids from the formation into the wellbore during the drilling operation. In some cases, termed “underbalanced” drilling, the fluid pressure in the wellbore may be maintained below the fluid pressure of the formation. Lower fluid pressures may increase the efficiency of the drilling operation, however, this may allow fluid from the formation to enter the wellbore. 
     BRIEF SUMMARY 
     Embodiments of the present disclosure may include a downhole cutting element. The cutting element may include a cutting face defined by a surrounding edge. The cutting element may further include a fluid passage through the cutting element. The cutting element may also include an aperture defined in the cutting face proximate the edge, the aperture operatively coupled to the fluid passage. 
     Another embodiment of the present disclosure may include an earth-boring tool. The earth-boring tool may include a tool body. The earth-boring tool may further include a cutting element coupled to the tool body. The cutting element may include a cutting edge and an aperture proximate the cutting edge. The earth-boring tool may also include a fluid passage coupled between the fluid supply in the tool body and the aperture. 
     Another embodiment of the present disclosure may include a cutting element. The cutting element may include a fluid passage passing through the cutting element. The cutting element may further include a cutting edge and an aperture proximate the cutting edge. The aperture may be coupled to the fluid passage, and having a major cross-sectional dimension less than a major cross-sectional dimension of the fluid passage. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       While the specification concludes with claims particularly pointing out and distinctly claiming embodiments of the present disclosure, the advantages of embodiments of the disclosure may be more readily ascertained from the following description of embodiments of the disclosure when read in conjunction with the accompanying drawings in which: 
         FIG. 1  illustrates a perspective view of an earth-boring tool in accordance with an embodiment of the present disclosure; 
         FIG. 2  illustrates a graphical representation of stresses in an earth formation under different conditions; 
         FIG. 3  illustrates schematic view of a cutting element in accordance with an embodiment of the present disclosure; 
         FIG. 4  illustrates schematic view of a cutting element in accordance with an embodiment of the present disclosure; 
         FIG. 5  illustrates schematic view of a cutting element in accordance with an embodiment of the present disclosure; and 
         FIG. 6  illustrates schematic view of a cutting element in accordance with an embodiment of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     The illustrations presented herein are not meant to be actual views of any particular earth-boring system or component thereof, but are merely idealized representations employed to describe illustrative embodiments. The drawings are not necessarily to scale. 
     As used herein, the term “earth-boring tool” means and includes any type of bit or tool used for drilling during the formation or enlargement of a wellbore in a subterranean formation. For example, earth-boring tools include fixed-cutter bits, roller cone bits, percussion bits, core bits, eccentric bits, bicenter bits, reamers, mills, drag bits, hybrid bits (e.g., rolling components in combination with fixed cutting elements), and other drilling bits and tools known in the art. 
     As used herein, the term “substantially” in reference to a given parameter means and includes to a degree that one skilled in the art would understand that the given parameter, property, or condition is met with a small degree of variance, such as within acceptable manufacturing tolerances. For example, a parameter that is substantially met may be at least about 90% met, at least about 95% met, at least about 99% met, or even at least about 100% met. In another example, an angle that is substantially met may be within about +/−15°, within about +/−10°, within about +/−5°, or even within about 0°. 
     As used herein, relational terms, such as “first,” “second,” “top,” “bottom,” etc., are generally used for clarity and convenience in understanding the disclosure and accompanying drawings and do not connote or depend on any specific preference, orientation, or order, except where the context clearly indicates otherwise. 
     As used herein, the term “and/or” means and includes any and all combinations of one or more of the associated listed items. 
     As used herein, the terms “vertical” and “lateral” refer to the orientations as depicted in the figures. 
     During a drilling operation fluid may be supplied into the wellbore to cool and/or clean the earth-boring tool and related cutting elements. The pressure of the fluid in the wellbore may be used to substantially prevent reservoir fluids (e.g., fluids stored in the formation, such as gas, oil, water, etc.) from entering the wellbore during the drilling operation, this is commonly referred to as overbalance drilling. High fluid pressured in the wellbore may reduce the efficiency of the drilling operation. For example, maintaining the fluid pressure above the pressure of the reservoir fluids may increase the strength of the formation near the wall of the wellbore. The increased strength of the formation may reduce the efficiency of the drilling operation by reducing the cutting depth and rate of penetration (ROP) of the earth-boring tool. 
     Referring to  FIG. 1 , a perspective view of an earth-boring tool  10  is shown. The earth-boring tool  10  may have blades  20  in which a plurality of cutting elements  100  may be secured. The cutting elements  100  may have a cutting table  102  with a cutting face  104  which may form the cutting edge of the blade  20 . The cutting elements  100  may also include a substrate  108  configured to support the cutting table  102 . The substrate  108  may be secured to a cutting pocket in the blade  20 , such as through welding, soldering, brazing, etc., securing the cutting elements  100  to the blade  20 . 
     The earth-boring tool  10  may rotate about a longitudinal axis of the earth-boring tool  10 . When the earth-boring tool  10  rotates the cutting face  102  of the cutting elements  100  may contact the earth formation and remove material. The material removed by the cutting faces  102  may then be removed through the junk slots  40 . The earth-boring tool  10  may include nozzles  106  which may introduce fluid, such as water or drilling mud, into the area around the blades  20  to aid in removing the sheared material and other debris from the area around the blades and/or to cool the cutting elements  100  and the blade  20  to increase the efficiency of the earth-boring tool  10 . 
     The fluid may enter the wellbore through the nozzles  106 . The nozzles  106  may be coupled to a pressurized fluid supplied through the drill string. The pressure of the fluid in the borehole may be controlled through the pressure of the fluid being supplied through the drill string and the nozzles  106 . One or more of the cutting elements  100  may be configured to inject fluid into the formation in a manner that may weaken the formation near the wall of the wellbore to counteract the strengthening effects of the fluid pressure in the wellbore. In some embodiments, the fluid injected through the one or more cutting elements  100  may be the same fluid that is supplied to the nozzles  106 . In some embodiments, a separate fluid may be supplied to the cutting element  100  through the earth-boring tool  10  and/or the drill string. 
     In some embodiments, a select number of the cutting element  100  may be configured to inject the fluid into the formation. For example, one cutting element  100  on each blade  20  may be configured to inject the fluid into the formation. In some embodiments, each of the cutting elements  100  in a nose region of the earth-boring tool  10  may be configured to inject the fluid into the formation. In some embodiments, only one or two of the cutting elements  100  may be configured to inject the fluid into the formation. For example, a cutting element  100  on a first blade  20  may be configured to inject the fluid into the formation, substantially weakening the formation for the cutting elements  100  on each of the following blades. In some embodiments, a second blade  20  positioned opposite the first blade  20  may include a second cutting element  100  configured to inject the fluid, such that at least two cutting elements  100  are configured to inject the fluid weakening the formation for the subsequent cutting elements  100 . In some embodiments, the cutting elements  100  configured to inject the fluid may be arranged at different positions along the respective blades. For example, as the earth-boring tool  10  rotates, the cutting elements  100  configured to inject the fluid on each adjacent blade  20  may travel in different paths, such that the fluid may be injected into the formation along different paths from each blade  20  of the earth-boring tool  10 . 
       FIG. 2  illustrates a graph  200  representative of the stresses experienced by the formation in an overbalanced drilling operation. The graph  200  further illustrates the effect of pore fluid pressure on the effective stress experienced by the formation. In particular the graph  200  illustrates representations of the shear stress  202  of the formation with respect to the normal stress  204  of the formation under different conditions. A first curve represents the total stress  206  of the formation and a second curve represents the effective stress  208  of the formation under the pore pressure effect  212 . 
     The pore pressure effect  212  is caused by increasing pore fluid pressure, such as by injecting fluid into the formation as described above. Increasing pore fluid pressure beyond the in-situ pore pressure reduces the normal principle stresses without diminishing the shear stress. This effect may change the total stress field of the formation without changing a failure envelope  210 . Changing the total stress field of the formation without changing the failure envelope  210  may encourage fracture in the formation by increasing the ratio of shear stress  202  to normal stress  204 . The change in the normal stress  204  caused by the pore pressure effect  212  may be represented by the following formula: 
       σ′=σ− u  
 
     Where σ′ represents effective stress, σ represents total stress, and μ represents pore pressure. The pore pressure μ may be scaled by Biot&#39;s constant α, which is a scalar representative of the porosity of the formation. This scalar may be directly proportional to porosity; approaching zero with porosity, and approaching one as porosity approaches 100%. 
     The effective stress may be reduced by the increase in pore pressure by reducing the ratio of the fluid pressure in the wellbore (e.g., wellbore pressure) to the fluid pressure in the formation  308  (e.g., pore pressure). Reducing the ratio of wellbore pressure to pore pressure at the area where the earth-boring tool  10  engages the formation  308 , may preserve borehole integrity while reducing the strength of the formation  308  at the specific location where the earth-boring tool  10  is engaged with the formation  308 . For example, increasing pore pressure at the location where the earth-boring tool  10  engages the formation  308  may encourage crack opening in the formation  308 , may reduce the stress at which the maximum shear stress threshold is reached for the formation  308 , and may locally reduce the strengthening effect of overbalanced drilling on the formation  308   
       FIG. 3  illustrates a schematic view of a cutting element  300  configured to inject a fluid into a formation  308 . The cutting element  300  may include a substrate  302  and a cutting table  304 . A fluid passage  306  may be defined through the cutting element  300 . The fluid passage  306  may pass through the substrate  302  of the cutting element  300  into the cutting table  304  of the cutting element  300  and out through a cutting face  318  of the cutting table  304 . The fluid passage  306  may pass out of the cutting element  300  through the cutting face  318  of the cutting table  304  in an area near a cutting edge  316  of the cutting face  318 . The cutting edge  316  may be a portion of an edge formed between a side of the cutting table  304  and the cutting face  318  of the cutting table  304 . The cutting edge  316  may be the portion of the edge proximate the formation  308 , such that the cutting edge  316  may engage the formation  308  at a wall of the wellbore  312 . 
     The cutting face  318  of the cutting table  304  may include a transition region  320  between the cutting face  318  and the edge between the cutting face  318  and the side of the cutting table  304 . For example, the transition region  320  may include a chamfer or radius transitioning between the cutting face  318  and a side of the cutting table  304 . The fluid passage  306  may pass out of the cutting element  300  through the transition region  320  of the cutting face  318 . In some embodiments, where the transition region  320  is a chamfer or other substantially planar surface, the fluid passage  306  may be positioned such that the fluid passage  306  is substantially normal to (e.g., perpendicular to, transverse to, orthogonal to, etc.) the surface of the cutting face  318  in the transition region  320 . 
     A fluid  314  may pass through the fluid passage  306  exiting the fluid passage  306  through the cutting face  318 . As described above, the fluid  314  may exit the cutting face  318  in the transition region  320  proximate the cutting edge  316 . As illustrated in  FIG. 3 , the cutting edge  316  and the cutting face  318  may be actively engaged with the formation  308 , such that the cutting element  300  may be removing material from the formation  308  in the form of cuttings  310 . The fluid  314  may be injected into the formation  308  near the cutting edge  316  of the cutting element  300 . The fluid  314  may weaken the formation  308  in the region of the formation  308  proximate cutting edge  316  (e.g., the wall of the wellbore  312 ). 
     In some embodiments, the earth-boring tool  10  may include an additional pump  324 . The pump  324  may be configured to increase a pressure of the fluid  314  before passing the fluid  314  through the fluid passage  306 . For example, the fluid  314  may be the drilling fluid supplied through the drill string, such as drilling mud. The pump  324  may boost the pressure of the fluid from the fluid supply, such as to supply a greater pressure into the formation  308 . For example, the pump  324  may pressurize the fluid  314  to a pressure greater than about 1000 pounds per square inch (psi) (6,895 kilopascals (kPa)), such as between about 1000 psi (6,895 kPa) and about 2000 psi (13,790 kPa), or between about 1200 psi (8,274 kPa) and about 1,500 psi (10,342 kPa). In some embodiments, the earth-boring tool  10  may not include the pump  324  and the fluid  314  may pass through the fluid passage  306  and into the formation  308  under the pressure of the drilling fluid from the drill string. In some embodiments, the fluid  314  may be a separate fluid from the drilling fluid. For example, a separate fluid may be supplied through the drill string or a fluid reservoir may be included in the earth-boring tool  10  or drill string. 
     In some embodiments, the pump  324  may be positioned within the earth-boring tool  10 . For example, the earth-boring tool  10  may include a cavity coupled to a flow path of the fluid. The pump  324  may be positioned within the cavity and coupled to the fluid passage  306 . In other embodiments, the pump  324  may be positioned outside the earth-boring tool  10 . For example, the pump  324  may be positioned within the drill string or as a module adjacent to the shank of the earth-boring tool 
     As the cutting element  300  engages the formation  308 , the earth-boring tool  10  may exert forces on the cutting element  300  in at least two directions. The earth-boring tool  10  may exert a normal force F n  in a direction transverse (e.g., normal, perpendicular, etc.) to the wall of the wellbore  312  and a tangential force F t  in a direction substantially parallel to the wall of the wellbore  312 . The normal force F n  may be proportional to the weight on bit (WOB) exerted on the earth-boring tool  10  by an associated drill string or drilling assembly. The tangential force F t  may be proportional to the rotational force exerted on the earth-boring tool  10  by the associated drill string and/or motor (e.g., downhole motor, mud motor, etc.). The normal force F n  may push the cutting element  300  into the formation  308  to a depth represented as the depth of cut  322 . The depth of cut  322  may be proportional to the rate of penetration (ROP) of the earth-boring tool  10 . The depth of cut  322  may increase under the same normal force F n  as the formation  308  is weakened. Increasing the depth of cut  322  and the ROP may increase the speed with which the earth-boring tool  10  drills through a formation. Increasing the speed with which the earth-boring tool  10  drills through the formation under substantially the same forces may represent an increase in efficiency of the earth-boring tool  10 . 
       FIG. 4  illustrates an embodiment of a cutting element  400  configured to inject a fluid  314  into the formation  308 . As described above, the cutting element  400  may a fluid passage  408  passing through the substrate  302  and the cutting table  304 . The cutting table  304  may include an orifice  404  at an end of the fluid passage  408 . As used herein, an orifice means and includes a hole or aperture in a wall separating two fluid volumes, such as fluid passageways, fluid filled cavities, etc., such that fluid may pass from one fluid volume to another through the orifice. The end of the fluid passage  408  and the orifice  404  may be positioned within the cutting table  304  before the cutting face  318 . The orifice  404  may have a major cross-sectional dimension (e.g., diameter, radius, apothem, width, etc.) that is less than a major cross-sectional dimension of the fluid passage  408 . For example, the orifice  404  may be circular and may have a diameter of between about 0.2 inches (in) (5.08 millimeters (mm)) and about 0.05 in (1.27 mm), such as between about 0.1 in (2.54 mm) and about 0.15 in (3.81 mm). The orifice  404  may be configured to concentrate the flow of the fluid  314  to form a jet. Concentrating the flow of the fluid  314  may cause the fluid to accelerate such that the jet of the fluid  314  is traveling at a higher rate of speed and has a smaller cross-sectional area than the fluid  314  within the fluid passage  408 . 
     The cutting face  318  may include an aperture  406  extending into the cutting table  304  and connected to the orifice  404 . A nozzle  402  may be disposed within the aperture  406 . In some embodiments, the nozzle  402  may be secured in the aperture  406  with a mechanical connection, such as a threaded connection, an interference connection, etc. In some embodiments, the nozzle  402  may be secured in the aperture  406  with an adhesive connection, such as with a glue or epoxy. In some embodiments, the nozzle  402  may be secured in the aperture  406  through a high temperature process, such as welding, brazing, or soldering. 
     The nozzle  402  may be configured to concentrate the flow the fluid  314 . For example, the nozzle  402  may be configured to further concentrate the flow of the fluid  314  after the concentration created by the orifice  404 . In some embodiments, the nozzle  402  may be configured to maintain the concentration of the flow of the fluid  314  from the orifice  404 . In some embodiments, the nozzle  402  may replace the orifice  404 . The nozzle  402  may be positioned within the aperture  406 , such that a tip of the nozzle  402  is proximate the opening of the aperture  406  (e.g., proximate the cutting face  318 ). The jet of the fluid  314  may exit the tip of nozzle  402  at the higher rate of speed and with the smaller cross-sectional area resulting from the flow concentration of the orifice  404  and/or the nozzle  402 . The fluid  314  may imping upon the formation  308  and the higher rate of speed and the smaller cross-sectional area may enable the fluid  314  to penetrate a greater distance into the formation  308 . 
     The aperture  406  may be defined in the cutting table  304 , such that the opening of the aperture  406  in the cutting face  318  may be proximate the cutting edge  316 . As described above, the opening of the aperture  406  may be defined in the transition region  320  proximate the cutting edge  316 . The aperture  406  may be positioned such that the flow of the fluid  314  is substantially perpendicular to the cutting face  318  in the area of the aperture  406 . As illustrated in  FIG. 4 , where the aperture  406  is defined in the transition region  320  of the cutting face  318 , the aperture  406  may be positioned such that the flow of the fluid is in a direction substantially perpendicular to the cutting face  318  in the transition region  320 . Directing the fluid  314  in a direction substantially perpendicular to the cutting face  318  in the transition region  320  may direct the fluid  314  at a different angle relative to the cutting face  318  outside of the transition region  320 . The direction of the flow of the fluid  314  may create deeper penetration into the formation  308 , weakening the formation  308  at a greater depth. In some embodiments, the direction of the flow of the fluid  314  may substantially prevent debris from blocking the aperture  406 . 
     The fluid passage  408 , orifice  404 , and aperture  406  may be formed in the cutting element  300  through a material removal process. For example, the material may be removed through a laser ablation process. In some embodiments, the fluid passage  408 , orifice  404 , or aperture  406  may be formed from an acid dissolvable material within the cutting element  400  when the cutting element  400  is formed. The acid dissolvable material may then be removed with an acid. In some embodiments, multiple processes may be used to form the fluid passage  408 , orifice  404 , and aperture  406 . For example, the fluid passage  408  through the substrate  302  may be formed through laser ablation and the aperture  406  and orifice  404  in the cutting table  304  may be formed through an acid dissolving process. 
       FIG. 5  illustrates another embodiment of a cutting element  500  configured to inject a fluid  314  into the formation  308 . Similar to the embodiments described above, the cutting element  500  may include a fluid passage  502  defined through the substrate  302  and the cutting table  304  of the cutting element  500 . The fluid passage  502  may include an orifice  504  at an end of the fluid passage  502  within the cutting table  304 . The fluid passage  502  may be coupled to an aperture  506  in the cutting face  318  of the cutting table  304 . The aperture  506  may include a nozzle  508  disposed within the aperture  506 , such that a tip of the nozzle  508  is proximate the cutting face  318 . As described above, the aperture  506  may be defined in the transition region  320  between the cutting face  318  and the cutting edge  316 . 
     The orifice  504  may have a major cross-sectional dimension that is less than the major cross-sectional dimension of the fluid passage  502 . As described above, the orifice  504  may be configured to concentrate the flow of the fluid  314  into a jet as the fluid  314  leaves the fluid passage  502 . 
     The cutting element  500  may include an abrasive inlet tube  510 . The abrasive inlet tube  510  may be coupled to an abrasive reservoir  512 . The abrasive reservoir  512  may contain abrasive particles, such as silica particles, sand particles, diamond particles, etc. In some embodiments, the abrasive reservoir  512  may be enclosed within the cutting element  500 . For example, the abrasive reservoir  512  may be a cavity defined within the cutting element  500 . In some embodiments, the abrasive reservoir  512  may be enclosed within the earth-boring tool  10 , such as within a blade  20  of the earth-boring tool  10  or within the body of the earth-boring tool  10 . In other embodiments, the abrasive reservoir  512  may be housed outside the earth-boring tool  10 , such as in a module or in the drill string. 
     The abrasive inlet tube  510  may be coupled to the fluid passage  502  or the aperture  506 . The abrasive inlet tube  510  may be arranged to intersect the fluid passage  502  and/or the aperture  506  orthogonally (e.g., perpendicular, transverse, at a 90° angle) to a longitudinal axis  514  of the fluid passage  502  and/or the aperture  506 . As illustrated in  FIG. 5 , the abrasive inlet tube  510  may orthogonally intersect the aperture  506  between the orifice  504  and the nozzle  508 . The flow of the fluid  314  may generate a vacuum in the aperture  506  between the orifice  504  and the nozzle  508 . For example, as the fluid  314  is accelerated due to the constriction of the orifice  504 , the pressure in the region of the aperture  506  between the orifice  504  and the nozzle  508  may be reduced creating a lower pressure than the surrounding regions, such as the abrasive inlet tube  510 , through the Venturi effect. Abrasive particles may enter the fluid  314  through the abrasive inlet tube  510  under the influence of the vacuum generated by the flow of the fluid  314 . 
     The fluid  314  with the abrasives may then pass through the nozzle  508  concentrating the flow of the fluid  314  and the abrasives into a jet. The jet of fluid  314  and abrasives may then impinge on the formation  308  near the cutting edge  316 . The abrasives may increase the material removing actions of the jet of fluid  314 . The increase in material removing actions may enable the fluid  314  to penetrate a greater distance into the formation  308 , weakening the formation  308  at a greater depth. 
       FIG. 6  illustrates an embodiment of a cutting element  600 , such as a cutting element  600  from a roller cone drill bit. The cutting element  600  may include a fluid passage  602  passing through the cutting element  600 . The fluid passage  602  may be defined substantially along a longitudinal axis  618  of the cutting element  600 , such that the fluid passage  602  may pass from a base  616  of the cutting element  600  to a tip  604  of the cutting element  600 . The fluid passage  602  may include an orifice  606  at an end of the fluid passage  602  configured to concentrate the flow of a fluid  614  through the fluid passage  602  to form a jet of the fluid  614 . The fluid passage  602  may be coupled to a cavity  608 . The cavity  608  may include nozzle  610  formed therein. The nozzle  610  may be configured to further concentrate the flow of the fluid  614  and/or to maintain the concentrated jet of the fluid  614 . In some embodiments, an abrasive inlet tube  510  ( FIG. 5 ) may be included in the cutting element  600  and may inject abrasives into the cavity  608  between the orifice  606  and the nozzle  610  as described above. The tip  604  of the cutting element  600  may include an aperture  620  substantially aligned with the nozzle  610 , such that the jet of the fluid  614  may exit the cutting element  600  through the tip  604  at a cutting edge of the cutting element  600  and imping upon the formation  308  ( FIG. 3 ). 
     A cutting element may not be in constant contact with the formation  308 . Therefore, the cutting element  600  may include a valve  612  configured to restrict and/or stop flow of the fluid  614  when the cutting element  600  is not in contact with the formation  308 . For example, the valve  612  may be a spring valve configured to open when under pressure (e.g., normal force F n  ( FIG. 3 ), WOB, when the cutting element  600  is in contact with the formation) and close when the pressure is released (e.g., when the cutting element  600  is not in contact with the formation). For example, the cutting element  600  may be a cutting element on a roller cone. As the roller cone rotates the cutting element  600  may contact the formation  308  and then release from the formation  308  until the rotation of the roller cone brings the cutting element  600  back into contact with the formation  308 . The valve  612  may cause the cutting element  600  to supply the jet of fluid  614  into the formation  308  when the cutting element  600  is in contact with the formation  308  and may interrupt the flow of the fluid  614  when the cutting element  600  loses contact with the formation  308  (e.g., during the portion of the rotation of the roller cone when the cutting element  600  is not in contact with the formation  308 ). 
     In some embodiments, the valve  612  may be positioned within the cutting element  600 . For example, the valve  612  may be positioned in the tip  604  of the cutting element  600  or deeper within the body of the cutting element  600  along the longitudinal axis  618  of the cutting element  600 . In some embodiments, the valve  612  may be positioned between the cutting element  600  and the earth-boring tool  10 . For example, the valve  612  may be positioned in a cutter pocket of the earth-boring tool  10  where the fluid passage  602  connects the cutting element  600  to the fluid supplied by the earth-boring tool  10 . As the cutting element  600  contacts the formation  308 , the pressure may be transferred from the cutting element  600  to the earth-boring tool  10  through the cutter pocket. Therefore, the valve  612  may receive the pressure by being sandwiched between the cutting element  600  and the earth-boring tool  10  in the cutter pocket. When the valve  612  receives the pressure input from the cutting element  600 , the valve  612  may open allowing the fluid  614  to flow from the earth-boring tool  10  into the cutting element  600  and out the aperture  620  into the formation  308 . 
     The valve  612  may enable multiple cutting elements  600  to be configured to supply the fluid  614  into the formation  308  while only allowing the fluid  614  to flow out of a select number of the cutting elements  600  at one time. Limiting the number of cutting elements  600  flowing fluid  614  at one time may reduce the requirements (e.g., size, power, etc.) of any associated pump (e.g., pump  324  ( FIG. 3 ) and/or fluid supply line. 
     Embodiments of the present disclosure may cause the pore pressure in a formation to be artificially increased in a controlled area. Increasing the pore pressure of the formation may reduce the forces required to shear the formation and remove the material from the formation. This may reduce the power required to remove the material, reducing the power used in a drilling operation and/or increasing the speed with which the drilling may be performed. Controlling the area where the pore pressure of the formation is artificially increased may enable a drilling operation to maintain the integrity of the wellbore through overbalanced drilling in the majority of the wellbore, while weakening the wall of the wellbore in a localized area to increase the efficiency of the material removal process. Increasing the efficiency of the material removal process may reduce the cost of drilling a wellbore. Increasing the efficiency of the material removal process may further reduce the amount of time before a wellbore may begin production and become a profitable wellbore. 
     The embodiments of the disclosure described above and illustrated in the accompanying drawing figures do not limit the scope of the invention, since these embodiments are merely examples of embodiments of the invention, which is defined by the appended claims and their legal equivalents. Any equivalent embodiments are intended to be within the scope of this disclosure. Indeed, various modifications of the present disclosure, in addition to those shown and described herein, such as alternative useful combinations of the elements described, may become apparent to those skilled in the art from the description. Such modifications and embodiments are also intended to fall within the scope of the appended claims and their legal equivalents.