Patent Application
20220213735
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.
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.
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.
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:
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
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.
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'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
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
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 Fn in a direction transverse (e.g., normal, perpendicular, etc.) to the wall of the wellbore 312 and a tangential force Ft in a direction substantially parallel to the wall of the wellbore 312. The normal force Fn 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 Ft 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 Fn 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 Fn 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.
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
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.
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
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.
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 Fn (
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 (
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.
